UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,Washington, DC 20549
FORM 10-K
(Mark One)
x(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
[FEE REQUIRED]
For the fiscal year endedFiscal Year Ended December 31, 19952000
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
[NO FEE REQUIRED]
For the transition periodTransition Period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-8809 SCANA Corporation 57-0784499
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-3375 SOUTH CAROLINA ELECTRICSouth Carolina Electric & GAS COMPANY
(Exact nameGas Company 57-0248695
(a South Carolina Corporation)
1426 Main Street, Columbia, South Carolina 29201
(803) 217-9000
1-11429 Public Service Company of registrant as specified in its charter)
SOUTH CAROLINA 57-0248695
(State or other jurisdiction of (IRS employer
incorporation or organization) identification no.)North Carolina, Incorporated 56-2128483
(a South Carolina Corporation)
1426 MAIN STREET, COLUMBIA, SOUTH CAROLINAMain Street, Columbia, South Carolina 29201
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code (803) 748-3000217-9000
Securities registered pursuant to Section 12(b) of the Act:
Each of the following classes or series of securities is registered on the New
York Stock Exchange.
Title of each class Name of each exchange on which registeredRegistrant
Common Stock, without par value SCANA Corporation
5% Cumulative Preferred Stock South Carolina Electric & Gas Company
par value $50 per share
New York Stock Exchange7.55% Trust Preferred Securities,
Series A liquidation value $25 South Carolina Electric & Gas Company
per Trust Preferred Security
Securities registered pursuant to Section 12(g) of the Act: Title of Class
The Class is comprised of the following series of Cumulative
Preferred Stock, par value $50 per share or $100 per share,
having a periodic sinking fund:
9.40% Cumulative Preferred 8.72% Cumulative Preferred
Stock par value $50 per Stock par value $50
share per share
8.12% Cumulative Preferred 7.70% Cumulative Preferred
Stock par value $100 Stock par value $100
per share per shareNone
Indicate by check mark whether the registrant:registrants: (1) hashave 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 wasregistrants were required to file such reports), and (2) hashave been subject to
such filing requirements for the past 90 days. Yes x .X No .
1
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
[ ]
State the aggregate market valueSCANA Corporation ( )
South Carolina Electric & Gas Company ( )
Public Service Company of the voting stock held by
nonaffiliates of the registrant. The aggregate market value
shall be computed by reference to the price at which the stock
was sold, or the average bid and asked prices of such stock, as
of a specified date within 60 days prior to the date of filing.
(See definition of affiliate in Rule 405.)
Note. If a determination as to whether a
particular person or entity is an affiliate cannot be
made without involving unreasonable effort and expense,
the aggregate market value of the common stock held by
non-affiliates may be calculated on the basis of
assumptions reasonable under the circumstances,
provided that the assumptions are set forth in this
form.North Carolina, Incorporated (X)
The aggregate market value of the voting stock held by non-
affiliatesnon-affiliates of
SCANA Corporation was $2.8 billion at February 28, 2001, based on a price of
$27.21. Each of the registrant asother registrants is a wholly-owned subsidiary of February 29, 1996 was zero.
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:
Indicate by check mark whether the registrantSCANA
Corporation and has filed all
documents and reports required to be filed by Section 12, 13 or
15(d)no voting stock other than its common stock. A description
of the Securities Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.
Yes No
(APPLICABLE ONLY TO CORPORATE REGISTRANTS)
Indicate the number of shares outstanding of each of the
registrant's classes ofregistrants' common stock asfollows:
Shares Outstanding
Registrant Description of the latest
practicable date.
AsCommon Stock at February 28, 2001
---------- --------------------------- --------------------
SCANA Corporation Without Par Value 104,729,131
South Carolina Electric
and Gas Company $4.50 Par Value 40,296,147
Public Service Company of
February 29, 1996 there were issued and outstanding
40,296,147 sharesNorth Carolina,Incorporated Without Par Value 1,000
Documents incorporated by reference: Specified sections of the registrant's common stock, $4.50 par
value, allSCANA
Corporation's 2001 Proxy Statement, dated March 19, 2001, in connection with its
2001 Annual Meeting of which were held, beneficially and of record, by
SCANA Corporation.
DOCUMENTS INCORPORATED BY
REFERENCE.
List hereunder the following documents ifStockholders, are incorporated by reference and thein Part of theIII
hereof.
This combined Form 10-K (e.g., Partis separately filed by SCANA Corporation, South Carolina
Electric & Gas Company and Public Service Company of North Carolina,
Incorporated. Information contained herein relating to any individual company is
filed by such company on its own behalf. Each company makes no representation as
to information relating to the other companies.
Public Service Company of North Carolina, Incorporated meets the conditions set
forth in General Instruction I Part II,
etc.) into which(1) (a) and (b) of Form 10-K and therefore is
filing this form with the document is incorporated: (1) any annual
report to security-holders;reduced disclosure format allowed under General
Instruction I (2) any proxy or information
statement; and (3) any prospectus filed pursuant to Rule 424(b)
or (c) under the Securities Act of 1933. The listed documents
should be clearly described for identification purposes (e.g.,
annual report to security-holders for fiscal year ended December
24, 1980).
NONE
2
TABLE OF CONTENTS
Page
DEFINITIONS .......................................................DEFINITIONS.............................................................. 4
PART I
Item 1. Business ............................................Business................................................... 5
Item 2. Properties .......................................... 19................................................ 18
Item 3. Legal Proceedings ................................... 21Proceedings.......................................... 20
Item 4. Submission of Matters to a Vote of Security Holders .......................................... 20
Corporate Structure ................................................ 21
Executive Officers of SCANA Corporation ............................ 22
PART II
Item 5. Market for Registrant's Common StockEquity and
Related Security Holder Matters ................ 21Stockholder Matters............................... 23
Item 6. Selected Financial Data ............................. 22Data.................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
...... 23Item 7A. Quantitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
......... 30SCANA Corporation.......................................... 25
South Carolina Electric & Gas Company...................... 75
Item 7. Management's Narrative Analysis of Results of Operations
Item 7A. Quantitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Public Service Company of North Carolina, Incorporated..... 109
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure ................ 55Disclosure.................................. 138
PART III
Item 10. Directors and Executive Officers of the Registrant ......................................... 55Registrants........ 138
Item 11. Executive Compensation .............................. 60.................................... 142
Item 12. Security Ownership of Certain Beneficial Owners
and Management .............................. 64........................................... 148
Item 13. Certain Relationships and Related Transactions ...... 65............ 149
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K ............................ 65
SIGNATURES ........................................................ 66
3............................................. 150
SIGNATURES............................................................... 154
DEFINITIONS
The following abbreviations used in the text have the meaningmeanings set forth below
unless the context requires otherwise:
ABBREVIATION TERM AFC.........................MEANING
AFC...................... Allowance for Funds Used During Construction
BTU.........................BTU...................... British Thermal Unit
Circuit Court............... South Carolina Circuit Court
Clean Air Act...............CAA...................... Clean Air Act Amendments of 1990
Company.....................Circuit Court............ South Carolina Electric & Gas CompanyCircuit Court
Consumer Advocate...........Advocate........ Consumer Advocate of South Carolina
Dekatherm...................Dekatherm................ One millionMillion BTUs
DHEC........................DHEC..................... South Carolina Department of Health and Environmental
Control
DOE.........................DOE...................... United States Department of Energy
EPA.........................DT....................... Dekatherm
Energy Marketing......... SCANA Energy Marketing, Inc.
EPA...................... United States Environmental Protection Agency
FERC........................FERC..................... United States Federal Energy Regulatory Commission
Fuel Company................Company............. South Carolina Fuel Company, Inc., an
affiliate
GENCO.......................
GENCO.................... South Carolina Generating Company, Inc., an
affiliate
KVA.........................
Investor Plus Plan....... SCANA Corporation Investor Plus Plan
KVA...................... Kilovolt-ampere
KW..........................KW....................... Kilowatt
KWH.........................KWH...................... Kilowatt-hour
LNG.........................LLC...................... Limited Liability Company
LNG...................... Liquefied Natural Gas
MCF.........................MCF...................... Thousand Cubic Feet
MW..........................MGP...................... Manufactured Gas Plant
Mhz...................... Megahertz
MMBTU.................... Million British Thermal Unit
MMCF..................... Million Cubic Feet
MW....................... Megawatt
NEPA........................NEPA..................... National Energy Policy Act of 1992
NRC.........................NCUC..................... North Carolina Utilities Commission
NRC...................... United States Nuclear Regulatory Commission
PCS...................... Personal Communications Service
Pipeline Corporation........Corporation..... South Carolina Pipeline Corporation
an
affiliate
PRP.........................PRP...................... Potentially Responsible Party
PSA......................... The South Carolina Public Service Authority
PSC.........................PSC...................... The Public Service Commission of South Carolina
PUHCA.......................PSNC..................... Public Service Company of North Carolina, Incorporated
PUHCA.................... Public Utility Holding Company Act of 1935, as amended
SCANA.......................RTO...................... Regional Transmission Organization
SCI...................... SCANA Communications, Inc.
SCANA.................... SCANA Corporation, the parent company
SCE&G.................... South Carolina Electric & Gas Company
SEC...................... United States Securities and its subsidiariesExchange Commission
Southern Natural............Natural......... Southern Natural Gas Company
SPSP..................... SCANA Corporation Stock Purchase-Savings Plan
Summer Station..............Station........... V. C. Summer Nuclear Station
Supreme Court...............Court............ South Carolina Supreme Court
Transco.....................Transco.................. Transcontinental Gas Pipeline Corporation
USEC........................ United States Enrichment Corporation
Westinghouse................ Westinghouse Electric Corporation
Williams Station............Station......... A. M. Williams coal-fired, electric
generating station ownedCoal-Fired, Electric Generating Station
Owned by GENCO
4WNA Weather Normalization Adjustment
PART I
ITEM 1. BUSINESS
THE COMPANY
ORGANIZATION
The Company, a wholly owned subsidiary of SCANA, is a South Carolina corporation organized in 1924having general business powers, was
incorporated on October 10, 1984, and hasregistered as a public utility holding
company under PUHCA on February 10, 2000, concurrent with the completion of its
principal
executive office at 1426 Main Street, Columbia, South Carolina
29201, telephone number (803) 748-3000. The Companyacquisition of 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 percent of an indirect subsidiary.
SCANA and its subsidiaries (the Company) had 3,7215,426 full-time, permanent
employees as of December 31, 1995February 28, 2001 as compared to 4,0095,488 full-time, permanent
employees as of February 29, 2000. SCE&G was incorporated under the laws of
South Carolina in 1924, and is an operating public utility. SCE&G had 2,412
full-time, permanent employees as of February 28, 2001 as compared to 3,771
full-time, permanent employees as of February 29, 2000. Prior to being acquired
by SCANA, PSNC was incorporated under the laws of North Carolina in 1938.
Subsequent to its acquisition, PSNC is incorporated under the laws of South
Carolina. PSNC is an operating public utility in North Carolina with 653
full-time, permanent employees as of February 28, 2001 as compared to 879
full-time, permanent employees as of February 29, 2000.
SEGMENTS OF BUSINESS
SCANA neither owns nor operates any physical properties. It has 11
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. SCANA also has four other direct, wholly owned subsidiaries that are
in liquidation.
Information with respect to major segments of business for the years
ended December 31, 1994.2000, 1999 and 1998 is contained in Management's Discussion
and Analysis of Financial Condition and Results of Operations for SCANA a South Carolina corporation, was organized in 1984
and
is a public utility holding company withinSCE&G and the meaning of
PUHCA but is presently exempt from registration under such Act.
SCANA holds all of the issued and outstanding common stock of the
Company. (See Note 1A of Notes to Consolidated Financial Statements.)
INDUSTRY SEGMENTS
The CompanyStatements appearing in Item 8,
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 14), SCE&G (Note 13)
and PSNC (Note 14). 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. The CompanySCE&G also renders urban
bus service in the metropolitan areasarea of Columbia, and Charleston, South Carolina. The Company'sSCE&G's
business is subject to seasonal fluctuations. Generally, sales of electricity
are higher during the summer and winter months because of air-conditioning and
heating requirements, and sales of natural gas are greater in the winter months
due to its use for heating requirements.
The Company'sSCE&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 3031 of the
46 counties in South Carolina and covers more than 20,00021,000 square miles. The
total population of the counties representing the Company's
combined service area is
approximately 2.32.5 million.
The predominantPredominant industries in the territoriesareas served by the
CompanySCE&G include: synthetic
fibers; chemicals and allied
products; fiberglass and fiberglass products;chemicals; fiberglass; paper and wood
products;wood; metal fabrication; stone, clay
and sand mining and processing; and various textile-related products.
Information with respecttextile.
GENCO owns and operates Williams Station and sells electricity solely to
industry segmentsSCE&G. Fuel Company acquires, owns and provides financing for the years
ended December 31, 1995, 1994SCE&G's nuclear
fuel, fossil fuel and 1993sulfur dioxide emission allowance requirements.
Pipeline Corporation is contained in Note 11 of
Notes to Consolidated Financial Statements and all such
information is incorporated herein by reference.
COMPETITION
The electric utility industry has begun a major transition
that could lead to expanded market competition and less
regulatory protection. Future deregulation of electric wholesale
and retail markets will create opportunities to compete for new
and existing customers and markets. As a result, profit margins
and asset values of some utilities could be adversely affected.
The pace of deregulation, the future market price of electricity,
and the regulatory actions which may be taken by the PSC in
response to the changing environment cannot be predicted.
However, the Company is aggressively pursuing actions to position
itself strategically for the transformed environment. To enhance
its flexibility and responsiveness to change, the Company
operates Strategic Business Units. Maintaining a competitive
cost structure is of paramount importanceengaged in the utility's
strategic plan.purchase, transmission and sale of
natural gas on a wholesale basis to distribution companies and directly to
industrial customers in 41 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 Company has undertakenindustrial
customers of Pipeline Corporation are primarily engaged in the manufacturing or
processing of ceramics, paper, metal, food and textiles. Pipeline Corporation
also operates a 62-mile six-inch propane pipeline that is owned by Suburban
Propane, L.P. of Whippany, New Jersey.
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 370,000 residential, commercial and industrial
customers. PSNC provides service to 25 of its 28 franchised counties covering
approximately 11,500 square miles in North Carolina. The industrial customers of
PSNC include manufacturers or processors of textiles, chemicals, ceramics and
clay products, glass, automotive products, minerals, pharmaceuticals, plastics,
metals, electronic equipment, furniture and a variety of initiatives, including reductionsfood and tobacco
products. PSNC, through wholly owned, non-regulated subsidiaries, refuels
natural gas vehicles and converts gasoline-fueled vehicles to natural gas.
Effective January 1, 2001, PSNC's gas brokering activities were transferred to
Energy Marketing.
Nonregulated Businesses
Energy Marketing markets electricity, natural gas and other light
hydrocarbons primarily in operationthe southeast. Energy Marketing, also provides
energy-related risk management services to producers and customers. In addition,
SCANA Energy, a division of Energy Marketing, markets natural gas to
approximately 432,000 customers in Georgia's deregulated natural gas market.
SCI owns and operates a 500-mile fiber optics telecommunications network
in South Carolina. In addition, SCI provides tower site construction, management
and rental services in South Carolina and Georgia. SCI also owns an 800 Mhz
radio service network within the state, and in January 2001, signed a letter of
intent to sell the network. The sale is expected in April 2001. SCANA
Communications Holdings, Inc. (SCH), 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. On August 28, 2000 SCH announced
that Powertel has agreed to be acquired by either Deutsche Telekom AG or
VoiceStream Wireless Corporation, as further discussion under "Other" in the
Liquidity and Capital Resources section of Management's Discussion and Analysis
of Financial Condition and Results of Operations for SCANA.
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. ServiceCare has announced the sale of its home security business
expected to be completed in March 2001.
Primesouth, Inc. is engaged in power plant management and maintenance
costsservices.
SCANA Resources, Inc. conducts energy-related businesses and in staffing levels. In January 1996provides
energy-related services.
Service Company
SCANA Services, Inc. provides administrative, management and other
services to the PSC
approved (as discussed under "Capital Requirementssubsidiaries and Financing
5
Program")business units within the accelerated recoveryCompany.
COMPETITION
For a discussion of the Company's electric
regulatory assetsimpact of competition, see the Competition
section of Management's Discussion and the shiftAnalysis of depreciation reserves from
transmissionFinancial Condition and
distribution assets to nuclear production
assets. The Company believes that these actions as well as
numerous others that have beenResults of Operations for SCANA and will be taken demonstrate its
ability and commitment to succeed in the new operating
environment to come.
Regulated public utilities are allowed to record as assets
some costs that would be expensed by other enterprises. If
deregulation or other changes in the regulatory environment
occur, the Company may no longer be qualified to apply this
accounting treatment and may be required to eliminate such
regulatory assets from its balance sheet. Such an event could
have a material adverse effect on the Company's results of
operations in the period the write-off is recorded. The Company
reported on its balance sheet at December 31, 1995 approximately
$116 million and $4 million of regulatory assets and
liabilities, respectively, excluding amounts related to net
accumulated deferred income tax assets of approximately $33
million.SCE&G.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The Company's cash requirements of the Company arise primarily from itsSCE&G's and PSNC's
operational needs, the Company's construction program, the need to fund the
activities or investments of SCANA's nonregulated subsidiaries and its construction program.payment of
dividends. The ability of the CompanySCANA's regulated subsidiaries to replace existing
plant investments,investment, as well as to expand to meet future demand for electricity and
gas, will depend upon itstheir ability to attract the necessary financial capital
on reasonable terms. The Company recoversSCANA's regulated subsidiaries recover the costs of
providing services through rates charged to customers. Rates for regulated
services are generally based on historical costs. AsDepending on customer growth
and inflation, occur and as the Company expands itsregulated subsidiaries continue their ongoing
construction programprograms, it ismay be necessary to seek increases in rates. On July 10, 1995,
the Company filed an application with the PSC for an increase in
retail electric rates. On January 9, 1996 the PSC issued an
order granting the Company an increase of 7.34% which will
produce additional revenues of approximately $67.5 million
annually. The increase will be implemented in two phases. The
first phase, an increase in revenues of approximately $59.5
million annually based on a test year, or 6.47%, commenced on
January 15, 1996. The second phase will be implemented in
January 1997 and will produce additional revenues of
approximately $8.0 million annually, or .87% more than current
rates. The PSC authorized a return on common equity of 12.0%.
The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over
a ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all (excluding accumulated deferred
income taxes) of the Company's electric regulatory assets and the
transition obligation for postretirement benefits other than
pensions, changing the amortization periods to allow recovery by
the end of the year 2000. The Company's request to shift
approximately $257 million of depreciation reserves from
transmission and distribution assets to nuclear production assets
was also approved. The
Company's future financial position and results of operations will be affected
by itsthe regulated subsidiaries' ability to obtain adequate and timely rate and
other regulatory relief. (See
"Regulation.")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 and the Notes to Consolidated
Financial Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA for SCANA (Note 4), SCE&G (Note 3) and PSNC (Note 5).
During 19962001 the Company is expected to meet its capital requirements
principally through internally generated funds (approximately 77%,61 percent, after
payment of dividends), and the issuanceincurrence of additional short-term and salelong-term
indebtedness. Sales of debt securities and additional equity contributions from
SCANA. Short-term liquidity is expectedsecurities may also occur. The Company
expects that it has or can obtain adequate sources of financing to be provided by
issuance of commercial paper.meet its
projected cash requirements for the next 12 months and for the foreseeable
future.
The timing and amount of such
sales and the type of securities to be sold will depend upon
market conditions and other factors.
6
The Company's current estimates of its cash requirements for construction
and nuclear fuel expenditures, which are subject to continuing review and
adjustment, for 19962001 and the four-yeartwo-year period 1997-2000 as now scheduled,2002-2003 are as follows:
- -------------------------------------------------------------- -----------------
Type of Facilities 1997-2000 1996
(Thousands2002-2003 2001
(Millions of Dollars)
South Carolina Electric & Gas Company:
Electric Plant:
Generation. . . . . . . . . . . . . . . . $268,987 $ 49,036
Transmission. . . . . . . . . . . . . . . 92,502 17,976
Distribution. . . . . . . . . . . . . . . 319,092 64,227Generation $329 $249
Transmission 43 22
Distribution 178 83
Other . . . . . . . . . . . . . . . . . . 34,152 13,83517 15
Nuclear Fuel. . . . . . . . . . . . . . . . 86,413 21,147Fuel 36 26
Gas . . . . . . . . . . . . . . . . . . . . 94,147 16,918
Common. . . . . . . . . . . . . . . . . . . 34,089 34,63338 20
Common 17 6
Other . . . . . . . . . . . . . . . . . . . 1,511 5531 1
- -------------------------------------------------------------- -----------------
Total . . . . . . . . . . . . . . $930,893 $218,325
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program
for the periods 1996SCE&G 659 422
PSNC Gas 91 42
Other Companies Combined 193 63
- -------------------------------------------------------------- -----------------
Total $943 $527
- -------------------------------------------------------------- -----------------
During 2000 SCE&G and 1997-2000, shown in the above table,
include costs of the projects described below.
The Company entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
Construction of the plant started in November 1992. Commercial
operation began in January 1996. The cost of the Cope plant,
excluding AFC, is $410.9 million. In addition, the
transmission lines for interconnection with the Company's system
cost $22.5 million. Approximately $9.8 million of the amounts
included in the above table for 1996 relate to the completion of
the Cope plant.
During 1995 the CompanyGENCO expended approximately $15.9$23.2 million and
$0.5 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 to be made during 19962001, included in the table above, are estimated to
cost approximately $19.9 million.
Additional Capital Requirements$80.3 million for SCE&G.
In addition to the Company's capital requirements for 19962001 described in "Capital Requirements" above, the
Company, SCE&G and PSNC will require approximately $21.2$41.5 million, will be required for refunding$28.2 million
and retiring$4.3 million, respectively, to refund and retire outstanding securities and
obligations.obligations in 2001. For the years 1997-2000,2002-2005, the Company has an aggregate of
$292.8$1,705.4 million of long-term debt maturing, (includingwhich includes an aggregate of
$455.2 million for SCE&G, $2.2 million of purchase or sinking fund requirements
for SCE&G's preferred stock and $22.5 million for PSNC. SCE&G's long-term debt
maturities for the years 2002-2005 include approximately $69.2$94.0 million for
sinking fund requirements, of which $68.7$93.9 million may be satisfied by deposit
and cancellation of bonds issued upon the basis of property additions or bond
retirement credits)credits.
SCANA and $9.8Westvaco 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. 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 purchasethese costs. In addition to Cogen, Westvaco, SCE&G and SCANA were
also named as defendants 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
their results of operations, cash flows or sinking fund requirementsfinancial position.
On October 15, 1999 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 preferred stock.
Actual 1996 expendituresthe dam over the past several years as part of SCE&G's ongoing
hydroelectric operating license with FERC. Until discussions are concluded, it
is not possible to finalize the cost of the project; however, it is possible
that the cost could range up to $250 million. Although any costs incurred by
SCE&G are expected to be recoverable through electric rates, SCE&G also is
exploring alternative sources of funding. The project is expected to be
completed in 2004.
On September 21, 1999 SCE&G announced a $256 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 7, 2000 Summer Station was removed from service for a planned
maintenance and refueling outage scheduled to last 38 1/2 days. During initial
inspection activities, plant personnel discovered a small leak coming from a
hole in a weld in a primary coolant system pipe. SCE&G performed extensive
ultrasonic testing of similar welds in the cooling system, which confirmed that
the problem was limited to this single weld. A root cause analysis determined
that the cause of the crack was primary water stress corrosion cracking. The
repair involved cutting out a twelve-inch long spool of the pipe, which included
the entire weld, and installing a new spool piece. Repairs have been completed
and the integrity of the new welds have been verified through extensive testing.
The plant was returned to service in March 2001. The NRC was closely involved
throughout this process and approved SCE&G's actions to repair the crack, as
well as the restart schedule. SCE&G will continue to monitor primary coolant
system pipes during the next outage, scheduled for Spring of 2002. SCE&G
recorded a pretax charge of approximately $6 million in the fourth quarter of
2000 to expense repair costs to date. Additional costs that may vary frombe recorded in
the estimates set
forth abovefirst quarter of 2001 are not expected to be material. The cost of
replacement power is expected to be recovered through SCE&G's electric fuel
adjustment clause.
In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
was taken out of service due to factors such as inflation, economic
conditions, regulation, legislation, ratesan electrical ground in the generator. The unit
is expected to be returned to service in Spring 2001. The cost of load growth,
environmental protection standards and the cost and availability
of capital.
7
replacement
power is expected to be recovered through SCE&G's fuel adjustment clause.
Financing Program
The Company'sSCANA and PSNC each have in effect a medium-term note program for the
issuance from time to time of unsecured medium-term debt securities. At December
31, 2000 SCANA had registered with the SEC and available for issuance $1 billion
under its program, the proceeds of which may be used to refinance indebtedness
incurred in connection with the acquisition of PSNC, to fund additional business
activities in nonutility subsidiaries, to reduce short-term debt 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 twelve12
consecutive months out of the fifteen18 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, 19952000 the Bond Ratio
was 3.97.6.43. The Old Mortgage allows the issuance of additional Class A Bonds also is restricted to an
additional principal amount equal to (i) 60%70 percent of unfunded net property
additions (which unfunded net property additions totaled approximately $162.3$1,452
million at December 31, 1995)2000), (ii) retirements of Class A Bonds (which
retirement credits totaled $64.8$68.4 million at December 31, 1995)2000), and (iii) and cash
on deposit with the Trustee.
The Company has placedSCE&G is subject to a new bond indenture (New Mortgage) 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 $185$665 million were available for such purpose at December 31,
1995), until such time
as all presently outstanding Class A Bonds are retired.
Thereafter, New Bonds will be issuable on the basis of property
additions in a principal amount equal to 70% of the original cost
of electric and common plant properties (compared to 60% of value
for Class A Bonds under the Old Mortgage), cash deposited with
the Trustee, and retirement of New Bonds.2000). New Bonds will be issuable under the New Mortgage only if adjusted net
earnings (as therein defined) for twelve12 consecutive months out of the eighteen18 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, 19952000
the New Bond Ratio was 5.31.6.34.
The following additional financing transaction hastransactions have occurred since
December 31, 1994:January 1, 2000:
o On April 12, 1995February 8, 2000 the Company issued $100$400 million of two-year floating
rate notes maturing February 8, 2002. The interest rate on the notes is
reset quarterly based on three-month LIBOR plus 50 basis points. The
proceeds from these privately sold notes were used to consummate SCANA's
acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a
three-year term under a credit agreement with several banks. The interest
rate is reset every one, two, three or six months and is based on LIBOR
plus 100 basis points. These funds also were used to consummate SCANA's
acquisition of PSNC.
o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds 7 5/8% serieshaving
an annual interest rate of 7.50 percent and maturing on June 15, 2005. The
proceeds from the sale of these bonds were used to pay the maturity of
SCE&G's $100 million First Mortgage Bonds due April 1, 2025June 15, 2000, to reduce
short-term debt and for general corporate purposes.
o On July 13, 2000 SCANA issued $300 million two-year floating rate notes
maturing on July 15, 2002. The interest rate is reset quarterly based on
three-month LIBOR plus 65 basis points. Proceeds from the debt were used to
repay medium-term notes totaling $170 million, to reduce short-term borrowings.debt
and for general corporate purposes.
o On January 24, 2001 SCANA issued $202 million two-year floating rate notes
maturing on January 24, 2003. The interest rate is reset quarterly based on
three-month LIBOR plus 110 basis points. Proceeds from the debt were used
to reduce short-term debt and for general corporate purposes.
o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having
an annual interest rate of 6.70 percent and maturing on February 1, 2011.
The proceeds from the sale of these bonds were used to reduce short-term
debt and for general corporate purposes.
o On February 16, 2001 PSNC issued $150 million of medium-term notes having
an annual interest rate of 6.625 percent and maturing on February 15, 2011.
These funds were used to reduce short-term debt and for general corporate
purposes.
The Company's electric and natural gas businesses are seasonal in
nature, with the primary demand for electricity being experienced during summer
and winter and the primary demand for natural gas being experienced during
winter. As a result of the significant increase during the latter half of 2000
in the cost to the Company of natural gas and the colder than normal weather
experienced in December, the Company experienced significant increases in its
working capital requirements, contributing to the need for the financings by
SCANA and PSNC in early 2001 described above.
Without the consent of at least a majority of the total voting power of
the Company'sSCE&G's preferred stock, the CompanySCE&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%ten percent of the aggregate
principal amount of all of the Company'sSCE&G's secured indebtedness and capital and surplus;
provided, however, that no such consent shall beis required to enter into agreements for payment of
principal, interest and premium for securities issued for pollution control
purposes.
Pursuant to Section 204 of the Federal Power Act, the
CompanySCE&G and GENCO must
obtain the FERC authority to issue short-term debt. The FERC has authorized the CompanySCE&G to
issue up to $200$250 million of unsecured promissory notes or commercial paper with
maturity dates of twelve12 months or less, but not later than December 31, 1997.2002. GENCO
has not sought such authorization.
The SEC order authorizing the Company had $165 million authorizedto register as a public utility
holding company under PUHCA imposes various limits during the three years ending
February 11, 2003 (the Authorization Period) on SCANA's, SCE&G's and unusedPSNC's
ability to issue long- and short-term debt. The order, as amended, requires
SCANA, SCE&G and PSNC to maintain common equity of at least 30 percent of their
consolidated capitalization. SCANA's issuance of capital securities is limited
to $2.385 billion, including securities issued to repay acquisition debt
financing. SCANA's short-term borrowings outstanding are limited to $450
million. SCE&G and PSNC may issue commercial paper and establish bank lines of
credit for $300 million and $200 million, respectively. In addition, PSNC
requires SEC approval under PUHCA prior to issuing long-term debt.
SCANA plans to request such approval for PSNC in 2001.
At December 31, 2000 SCE&G had $250 million of unused authorized lines of
credit which consist of a credit agreement for a maximum of $250 million to
support the issuance of commercial paper. SCE&G's commercial paper outstanding
at December 31, 1995.2000 and 1999 was $117.5 million and $143.1 million,
respectively. In addition, Fuel Company has a credit agreement for a maximum of
$125 million with the full amount available at December 31, 1995.2000. 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, 19952000 was $76.8$70.2 million. The Company'sThis
commercial paper and amounts outstanding under the revolving credit agreement,
if any, are guaranteed by SCE&G.
At December 31, 2000 PSNC had $125 million authorized lines of credit
which consist of a credit agreement for a maximum of $125 million to support the
issuance of commercial paper. Unused lines of credit at December 31, 2000
totaled $125 million. PSNC's commercial paper outstanding on December 31, 2000
was $125 million.
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 twelve12 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, 19952000 the
Preferred Stock Ratio was 2.58.
8
2.09.
As a result of SCANA's acquisition of PSNC on February 10, 2000, PSNC
shareholders were paid $212 million in cash and 17.4 million shares of SCANA
common stock valued at approximately $488 million. In connection with this
transaction, certain SCANA shareholders were paid $488 million in cash for 16.3
million shares of SCANA common stock. During 2000, 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)method) were 3.41, 3.46, 3.57, 2.732.57,
2.98, 3.67, 3.64 and 3.323.60 for the years ended December 31, 1995, 1994, 1993, 19922000, 1999, 1998,
1997 and 1991,1996, respectively. The Company expects that it has or can obtain adequate
sources of financing to meet its projected cash requirementsFor SCE&G these ratios were 4.20, 3.71, 4.40, 3.85
and 3.80 for the next twelve months andsame periods. For PSNC these ratios were 2.97 for the foreseeable future.
Fuel Financing Agreements
The Company has assigned to Fuel Company all of its rights
and interests in its various contracts relating to the
acquisition and ownership of nuclear and fossil fuels. To
finance nuclear and fossil fuels and sulfur dioxide emission
allowances, Fuel Company issues, from time to time, commercial
paper which is supported, up to $125 million, by an irrevocable
revolving credit agreement which expires July 31, 1998.
Accordingly, the amounts outstanding have been included in long-
term debt. This commercial paper and amounts outstanding under
the revolving credit agreement, if any, are guaranteed by the
Company.
Atyear
ended December 31, 1995 commercial paper outstanding was
approximately $76.8 million at a weighted average interest
rate of 5.76%. (See Notes 1N2000 and 4 of Notes to Consolidated
Financial Statements.)3.24, 3.23, 3.44 and 3.62 for the fiscal years ended
September 30, 1999, 1998, 1997 and 1996, respectively.
ELECTRIC OPERATIONS
Electric Sales
In 19952000 residential sales of electricity accounted for 43%40% of electric
sales revenues; commercial sales 30%; industrial sales 20%19%; sales for resale 4%3%;
and all other 3%8%. The Company's KWH sales by classification, excluding volumes
attributable to the cumulative effect of accounting change, for the years ended
December 31, 19952000 and 19941999 are presented below:
Sales
KWH (Millions)
- --------------------------------------------------------------------------------
CLASSIFICATION 2000 1999 % Classification 1995 1994 Change
(thousands)CHANGE
- --------------------------------------------------------------------------------
Residential 5,726,815 5,311,139 7.836,665 6,269 6%
Commercial 5,078,185 4,848,620 4.736,305 5,950 6%
Industrial 5,210,368 5,161,717 0.94
Sale6,665 6,140 9%
Sales for resale 1,063,064 1,024,376 3.781,222 1,189 3%
Other 506,806 494,030 2.59553 518 7%
- ----------------------------------------------------------------
Total Territorial 17,585,238 16,839,882 4.43
Interchange 195,591 171,046 14.3521,410 20,066 7%
Negotiated Market Sales Tariff 1,942 1,678 16%
================================================================
Total 17,780,829 17,010,928 4.53
The Company furnishes23,352 21,744 7%
================================================================
Sales for resale includes electricity furnished for resale to threetwo
municipalities fourand two electric cooperatives. Sales under the Negotiated Market
Sales Tariff during 2000 include sales to 36 investor-owned utilities twoand
registered marketers, seven electric cooperatives, two municipalities and one public power authority. Suchfour
federal/state electric agencies. During 1999 sales for
resale accounted for 4% of totalunder the Negotiated Market
Sales Tariff included sales to 32 investor-owned utilities and registered
marketers, seven electric cooperatives, two municipalities and four
federal/state electric agencies.
The electric sales revenues in 1995.volume from residential sales increased for 2000
primarily as a result of colder weather. During 19952000 the Company recorded a net
increase of 7,943
electric13,701 customers, increasing its total customers to 484,381.
9
The electric sales volume increased for the year ended
December 31, 1995 compared to the prior year as a result of
increased residential and commercial sales due to favorable
weather and customer growth.537,253. The
all-time peak demand of 3,6834,211 MW was set on August 14, 1995.
On August 8, 1995 the Company signed an agreement with the
DOE to lease the Savannah River Site's (SRS) power and steam
generation and transmission facilities. The agreement calls for
SRS to purchase all its electrical and a majority of its steam
requirements from the Company. The Company will lease (with an
option to renew) the power plant for ten years and the electrical
transmission lines for 40 years, with an option to refurbish the
facilities or build a new system.July 20, 2000.
Electric Interconnections
The CompanySCE&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 560580 MW.
The Company'sSCE&G's transmission system is part of the interconnected grid
extending over a large part of the southern and eastern portions of the nation.
The Company,SCE&G, Virginia Power Company, Duke Power Company, Carolina Power & Light
Company, Yadkin, Incorporated and PSASouth Carolina Public Service Authority
(Santee Cooper) are members of the Virginia-
CarolinasVirginia-Carolinas Reliability Group, one of the
several geographic divisions within the Southeastern Electric Reliability
Council. This councilCouncil provides for coordinated planning for reliability among
bulk power systems in the Southeast. The CompanySCE&G is also interconnected with Georgia
Power Company, Savannah Electric & Power Company, Oglethorpe Power Corporation
and the Southeastern Power Administration's Clark Hill Project.
On February 9, 2000 the FERC issued FERC Order 2000. The Order requires
utilities which operate electric transmission systems to submit plans for the
possible formation of an RTO. On October 16, 2000 the Company and two other
southeastern electric utilities filed a joint request with FERC to establish
GridSouth Transco, LLC (GridSouth). When operational, GridSouth will function as
an independent transmission company. Initially, the three utilities will
continue to own their respective transmission networks, while GridSouth will
provide planning and operational oversight of the electric transmission grid.
FERC gave provisional approval to GridSouth in March 2001. GridSouth is expected
to be operational by December 2001.
Fuel Costs
The following table sets forth the average cost of nuclear fuel and
coal and the weighted average cost of all fuels (including oil and natural gas)
used by the Company and GENCO for the years 1993-1995.
1995 1994 19931998-2000.
2000 1999 1998
---- ---- ----
Nuclear:
Per million BTU $ .48 $ .51 $ .47$.46 $.46 $.46
Coal:
Company:SCE&G
Per ton $40.01 $39.92 $39.95$37.10 $39.37 $38.19
Per million BTU 1.48 1.57 1.57 1.55
GENCO:1.50
GENCO
Per ton $42.21 $41.85 $41.64$38.98 $41.46 $41.67
Per million BTU 1.51 1.61 1.63 1.63 1.62
Weighted Average Cost of All Fuels:
Per million BTU $ 1.26 $ 1.39 $ 1.31
The fuel costs shown above exclude the effects of a PSC-approved
offsetting of fuel costs through the application of credits carried on the
Company's books as a result of a 1980 settlement of certain litigation.
10$1.31 $1.32 $1.26
Fuel Supply
The following table shows the sources and approximate percentages of
the Company's total KWH generation (including Williams Station) by each category of fuel for the years
1993-19951998-2000 and the estimates for 19962001 and 1997.2002.
Percent of Total KWH Generated
-------------------------------------------------------------
Estimated Actual
1997 1996 1995 1994 1993---------------------- ------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Coal 67% 73% 71% 65% 76% 72%77% 73% 69%
Nuclear 24 24 27 17 2320 20 18 22 25
Hydro 3 36 5 64 4 5
Natural Gas & Oil -7 2 3 1 -1 1
========== ============= ====================================
100% 100% 100% 100% 100%
========== ============= ====================================
Coal is used at all five of the Company's majorSCE&G's fossil fuel-
firedfuel-fired plants and
GENCO's Williams Station. Unit train deliveries are used at all of these plants.
On December 31, 1995 the
Company2000 SCE&G had approximately a 73-day37-day supply of coal in
inventory and GENCO had approximately a 49-day43-day supply.
The supply of coalCoal is obtained through contracts and purchases on the spot market.
Spot market purchases are expected to continue for coal requirements in excess
of those provided by the Company'sSCANA's existing contracts.
Contracts for the purchase
of coal represent 91.5% of estimated requirements for 1996
(approximately 5.3 million tons, including requirements of
Williams Station).
The supply of contractContract coal is purchased from seventen suppliers located in eastern
Kentucky, Tennessee, southwest Virginia and southwestWest Virginia. Contract commitments,
which expire at various times from 1997-
2003,2001 through 2009, approximate 4.856.1 million
tons annually.annually, which is 88 percent of total expected coal purchases for 2001.
Sulfur restrictions on the contract coal range from .75%0.75 percent to 2%.1.5 percent.
SCE&G is building two combined-cycle turbines that 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 schedule to be completed by
June 2002.
The Company believes that itsSCE&G's and GENCO's operations are in substantial
compliance with all existing regulations relating to the discharge of sulfur
dioxide.dioxide and nitrogen oxides. The Company has not been advised by
officials of DHECis unaware that any more stringent
sulfur content requirements for existing plants are contemplated at the State
level. However, the Company will be required to meet the more
stringent Federal emissions standards establishedstate
level by the Clean
Air Act (see "Environmental Matters").
The CompanyDHEC.
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) Term
Uranium Energy Resources
of Australia 9-13 1990-1997
Uranium Everest Minerals 9-13 1990-1996
Conversion Sequoyah Fuel Corp. 8-12 1989-1995Date
Enrichment USEC 12-18 1995-2005United States Enrichment Corporation (2) 16-18 2005
Fabrication Westinghouse 1-21 1982-2009
Reprocessing NoneElectric Corporation 16-21 2009
(1) A region represents approximately one-third to one-half of the nuclear
core in the reactor at any one time. Region no.
1115 was loaded in 1994 and2001.
Region no. 1216 will be loaded in 1996.
11
The Company2002.
(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
20092006 and expects to be able to expand its storage capacity to accommodate the
spent fuel output for the life of the plant through rod consolidation,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 "NuclearNuclear Fuel Disposal"Disposal under
"Environmental
Matters"Environmental Matters for information regarding the contract with the DOE for
disposal of spent fuel.)
On October 7, 2000 Summer Station was removed from service for a
planned maintenance and refueling outage. See preceding discussion of this
matter on page 8.
Decommissioning
DecommissioningFor information regarding the decommissioning of Summer Station, is presently projected to
commence in the year 2022 when the operating license expires.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to the Company's share of decommissioning activities are
estimated, in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimated
decommissioning costs of Summer Station over the life of Summer
Station. The Company's method of funding decommissioning costs
is referred to as COMReP (Cost of Money Reduction Plan). Under
this plan, funds collected through rates ($3.2 million in each of
1995 and 1994) are used to purchase insurance policies on the
lives of certain Company personnel. Through the purchase of
insurance contracts, the Company is able to take advantage of
income tax benefits and accrue earnings on the fund on a tax-
deferred basis at a rate higher than can be achieved using more
traditional funding approaches. Amounts for decommissioning
collected through electric rates, insurance proceeds, and
interest on proceeds less expenses are transferred by the Company
to an external trust fund in compliance with the financial
assurance requirementssee
Note 1H, Nuclear Decommissioning, of the NRC. Management intendsNotes to Consolidated Financial
Statements appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 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 investmentSCANA and the cash transfers from the Company described
above. The Company records its liability for decommissioning
costs in deferred credits.SCE&G.
GAS OPERATIONS
Gas Sales - Regulated
In 19952000 the Company's residential sales accounted for 47%38% of gas sales
revenues; commercial sales 22%; industrial sales 28%; sales for resale 8%; and
other 4%. During the same period, SCE&G's residential sales accounted for 41% of
gas sales revenues; commercial sales 32%; and industrial sales 21%27%. Also during
the same period, PSNC's residential sales accounted for 64% of gas sales
revenues; commercial sales 27%; and industrial sales 9%. Dekatherm sales by
classification, excluding volumes associated with the cumulative effect of
accounting change, for the years ended December 31, 19952000 and 19941999 are presented
below:
Sales
Dekatherms %
Classification 1995 1994 Change
Residential 12,333,769 11,531,558 7.0
Commercial 10,436,987 9,813,454 6.4
Industrial 13,467,687 10,938,713 23.1
Sales
Dekatherms (000)
- ----------------------------------------------------------------------------------------------------------------------------
The Company SCE&G PSNC
% % %
CLASSIFICATION 2000 1999* Change 2000 1999 Change 2000 1999 Change
- ----------------------- ---------- ------------- ------------ ---------- --------- ---------- -------- --------- -----------
Residential 35,365 11,823 199.1% 12,235 11,823 3.5% 23,130 19,976 15.8%
Commercial 25,039 11,790 112.4% 12,076 11,699 3.2% 12,850 11,609 10.7%
Industrial 61,662 61,748 (0.1%) 17,129 17,958 (4.6%) 5,307 6,349 (16.4%)
Sales for Resale 16,931 15,947 6.2% - - - - - -
Transportation gas 31,634 2,252 1,304.7% 2,085 1,975 5.6% 29,372 28,750 2.2%
-------- ---------- -- ----- ------- ------ ------
Total 170,631 103,560 64.8% 43,525 43,455 0.2% 70,659 66,684 6.0%
======================= ========== ============= ============ ========== ========= ========== ======== ========= ===========
*SCANA acquired PSNC effective January 1, 2000 for accounting purposes. Therefore, the Company's 1999 sales do
not include PSNC.
The Company's and SCE&G's gas 3,603,314 5,469,728 (34.1)
Total 39,841,757 37,753,453 5.5
During 1995sales volume increased for 2000 primarily
as a result of customer growth. The Company obtained 354,763 customers when it
acquired PSNC. In addition, during 2000 the Company recorded a net increase of
4,90921,798 customers, increasing its total customers to 637,017. SCE&G recorded a
net increase of 6,103 gas customers, increasing its total customers to 243,342.
The Company purchases all266,348.
PSNC recorded a net increase of 15,148 customers, increasing its natural gas from Pipeline
Corporation.total customers
to 370,181.
The demand for gas is affected by conservation, the weather, the price relationship
between gas and alternate fuels and other factors.
12
The deregulationPipeline Corporation, operating wholly within the State of South
Carolina, provides natural gas prices at the wellheadutility and the changes in the prices oftransportation services for its
customers, and supplies natural gas that have occurred under
Federal regulation have resulted in the development of a spot
marketto SCE&G and other wholesale purchasers.
Pipeline Corporation is developing plans for an interstate natural gas pipeline
to ensure adequate supplies to growing gas markets. The anticipated interstate
pipeline will require Pipeline Corporation to file an application for approval
with FERC and other federal and state agencies. Energy Marketing acquires and
sells natural gas in the producing areas of the country.
Pipeline Corporationregulated and deregulated markets. Energy Marketing has been successful in purchasing lower costnot
supplied natural gas to any affiliate for use in the spot market and arranging for its
transportation to South Carolina.
On November 1, 1993 Transco and Southern Natural (Pipeline
Corporation's interstate suppliers) began operations under Order
No. 636, which deregulated the markets for interstate sales of
naturalproviding regulated gas by requiring that pipelines provide transportation
services that are equal in quality for all gas supplies whether
the customer purchases gas from the pipeline or another supplier.
The impact of this order on the Company will be primarily through
changes affecting its supplier, Pipeline Corporation.
To reduce dependence on imported oil, NEPA imposes purchase
requirements for the purchase of alternate fuel vehicles on
Federal, state, municipal and private fleets. The Company
expects these requirements to develop business opportunities for
the sale of compressed natural gas as fuel for vehicles, but it
cannot predict the magnitude of this new market.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 both
Southern Natural (expiring in 2005 and 2006) and Transco which expire at various times from
1996 to 2003.(expiring in 2008
and 2017). The daily volume of gas whichthat Pipeline Corporation is entitled to
transport under these contracts on a firm basis is shown below:
Maximum Daily
Supplier Contract Demand Capacity (MCF)188 MMCF from Southern
Natural Firm Transportation 184,974
Transco Firm Transportation 29,300
Total 214,274
Under aand 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, the Company's
maximumis entitled to
receive a daily contract demand is 224,270of 266,495 dekatherms. The contract allows the CompanySCE&G
to receive amounts in excess of this demand based on availability.
TheDuring 2000 Pipeline Corporation's average cost per MCF of natural gas
purchased fromfor resale, including firm service demand charges, was $4.42 compared
to $2.99 during 1999. SCE&G's average cost per MCF was $5.35 and $3.73 during
2000 and 1999, respectively.
Pipeline Corporation was approximately $3.77has engaged in 1995 comparedhedging activities on the New York
Mercantile Exchange (NYMEX) of its gas supply pursuant to $4.29a limited program
authorized and monitored by the PSC. Any gains or losses associated with that
hedging activity are accounted for in 1994.Pipeline Corporation's purchased gas
adjustment clause and, therefore, have no impact on net income.
To meet the requirements of the Company and its other high priority natural gas customers
during periods of maximum demand, Pipeline Corporation supplements its supplies
of natural gas from two LNG plants. The LNG plants are capable of storing the
lique-
fiedliquefied equivalent of 1,900,000 MCF1,880 MMCF of natural gas,gas. Approximately 1,192 MMCF of
which
approximately 1,695,489 MCFgas were in storage at December 31, 1995.2000. On peak days the LNG plants can
regasify up to 150,000 MCF150 MMCF per day. Additionally, Pipeline Corporation had
contracted for 6,450,727 MCF6,447 MMCF of natural gas storage spacespace. Approximately 3,713 MMCF
of which 4,307,796 MCFgas were in storage on December 31, 1995.2000.
PSNC Energy 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 reservation charge. The
gas is brought to North Carolina through transportation agreements with Transco
and Dominion Gas Transmission with expiration dates ranging through 2016. The
daily volume of gas that PSNC Energy is entitled to transport under these
contracts on a firm basis is 259,894 dekatherms from Transco and 30,331
dekatherms from Dominion Gas Transmission. PSNC Energy has submitted non-binding
nominations for firm transportation service on three proposed pipeline projects
to meet incremental capacity requirements beginning in 2003.
During 2000 PSNC Energy's average cost per dekatherm of natural gas
purchased for resale, including firm service demand charges, was $5.63 compared
to $3.71 during 1999.
To meet the requirements of its high priority natural gas customers
during periods of maximum demand, PSNC Energy supplements its supplies of
natural gas with underground natural gas storage services and liquefied natural
gas (LNG) peaking services. Underground natural gas storage service agreements
with Dominion Gas Transmission, Columbia Gas Transmission and Transco provide
for storage capacity of approximately 8,657 MMCF. In addition, PSNC Energy's own
LNG facility is capable of storing the liquefied equivalent of 1,000 MMCF of
natural gas with daily regasification capability of 106 MMCF. Approximately 835
MMCF were in storage at December 31, 2000. LNG storage service agreements with
Transco, Cove Point LNG and Pine Needle LNG provide for approximately 1,266 MMCF
of storage space. At December 31, 2000 approximately 869 MMCF were stored in
these three facilities.
The Company believes that supplies under long-term contract and
supplies available for spot market purchase are adequate to meet existing
customer demands and to accommodate growth.
13
Curtailment Plans
The FERCPSC has established allocation priorities applicable to the firm
and interruptible capacities on interstate pipeline
companies to their customers which require Southern Natural and
Transco to allocate capacity toof Pipeline Corporation. The FERC
allocationcurtailment 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. Energy Marketing is also a power
marketer, which allows it to buy and sell large blocks of electric capacity in
wholesale markets. In addition, SCANA Energy, a division of Energy Marketing,
markets natural gas to approximately 432,000 customers in Georgia's deregulated
natural gas market.
Although Energy Marketing's activities are primarily focused in the
southeast, Energy Marketing has maintained smaller scale operations in the
Midwest and in California. While Energy Marketing has from time to time been a
customer of the California utilities (PG&E, SoCalEdison and SDG&E), it has not
applicablebeen a supplier to deliveries bysuch companies and does not have material direct or indirect
credit risk related to them.
The Company's Board of Directors has established a Risk Management
Committee which is responsible for developing corporate policies and overseeing
the Company to its customers, which are governed by a separate
curtailment planmanagement of risk within tolerance parameters approved by the PSC.Board.
REGULATION
General
The CompanySCANA became a registered public utility holding company under PUHCA on
February 10, 2000, concurrent with completion of its acquisition of 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.
The CompanyPipeline 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.
In the opinion of the Company, it will be able to meet
successfully the challenges of the NEPA without any material
adverse impact on its results of operations, financial position
or business prospects.
Federal Energy Regulatory Commission
The Company is subject to regulation under the Federal Power
Act, administered by the FERC and the DOE, in the transmission of electric energy in
interstate commerce and in the sale of electric energy at wholesale for resale,
as well as with respect to licensed hydroelectric projects and certain other
matters, including accounting and the issuance of short-term promissory notes.
(See "CapitalCapital Requirements and Financing Program.")
The CompanySCE&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:
License License
Project Capability (KW) License Expiration DateProject Expiration
Neal Shoals 5,000 19932036 Saluda 2007
Stevens Creek 9,000 2025
Columbia 10,000 2000
Saluda 206,000 2007 Parr Shoals 14,000 2020
Columbia 2000 Fairfield Pumped Storage 512,000 2020
Pursuant to the provisions of the Federal Power Act, as
amended, applications for new licenses for Neal Shoals and
Stevens Creek wereSCE&G filed with the FERC on December 30, 1991. No
competing applications were filed. The FERC issued a new 30-year
license for the Stevens Creek project on November 22, 1995. The
Neal Shoals license application is in the final stage of review.
The FERC has issued a Notice of Authorization for Continued
Project Operation for Neal Shoals until the FERC acts on the
Company'san application for a new license.license for Columbia on June 30,
1998. The application was officially accepted for filing by FERC notice dated
December 23, 1999, and is currently in environmental review. The current license
for Columbia expired on June 30, 2000; subsequent to that date, FERC issued a
temporary operating license to allow SCE&G to continue to operate the project
until a new license is issued.
At the termination of a license under the Federal Power Act, the United
States government may take over the project covered thereby, or the FERC may extend
the license or issue a license to another applicant. If the United StatesFederal 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.
14
The Company has filed an applicationFor a discussion of SCE&G's agreement with FERC related to reinforcing
the FERC
requesting authorizationLake Murray Dam (related to sell bulk power at market based
rates. The application also included proposed open access
transmission tariffs. (See "National Energy Policy Actthe Saluda hydroelectric project), see previous
discussion under Capital Requirements and see Liquidity and Capital Resources in
Management's Discussion and Analysis of 1992Financial Condition and FERC Order 636.")Results of
Operations for SCANA and SCE&G.
Nuclear Regulatory Commission
The CompanySCE&G is subject to regulation by the NRC with respect to the
ownership, operation and operationdecommissioning of Summer Station. The NRC's
jurisdiction encompasses broad supervisory and regulatory powers over the
construction and operation of nuclear reactors, including matters of health and
safety, antitrust considerations and environmental impact. In addition, the
Federal Emergency Management Agency is responsible for the review, in
conjunction with the NRC, of certain aspects of emergency planning relating to
the operation of nuclear plants.
For the fourth time in the last five evaluations, Summer
Station received a category one rating from the Institute of
Nuclear Power Operations (INPO). The category one rating is the
highest given by INPO for a nuclear plant's overall operations.
National Energy Policy Act of 1992 and FERC OrderOrders No. 636, 888 and 2000
The Company's regulated business operations are likely to bewere impacted by the NEPA
and FERC OrderOrders No. 636.636, 888 and 2000. NEPA iswas designed to create a more
competitive wholesale power supply market by creating "exempt wholesale
generators" and by potentially requiring utilities owning transmission
facilities to provide transmission access to wholesalers. Order No. 636 iswas
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. InOrders No. 888 and 2000 require utilities under
FERC jurisdiction that own, control or operate transmission lines to file
nondiscriminatory open access tariffs that offer to others the opinionsame transmission
service they provide to themselves and to submit plans for the possible
formation of thean RTO. The Company believes it will continue to be able to meet
successfully the challenges of these altered business climates and does not
anticipate there towill be any material adverse impact from these Orders on the
Company's results of its operations, itscash flows, financial position or its business
prospects.
RATE MATTERS
The following table presentsFor a summarydiscussion of significantthe impact of various rate activitymatters, 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, and the years 1991-1995 based on test years:
REQUESTED GRANTED
Date of % % ofNotes to Consolidated Financial Statements appearing in
Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA (Note 4), SCE&G
(Note 3) and PSNC (Note 5).
General
Rate Application/ Amount Increase Date of Amount Increase
Applications Hearing (Millions) Requested Order (Millions) Granted
PSC
Electric
Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88%
Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84%
Transit
Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering ofSCE&G and PSNC's gas rate of return the Company was seeking.
15
On July 10, 1995, the Company filed an application withschedules for their residential and small
commercial customers include a WNA. SCE&G's and PSNC's WNA were approved by the
PSC and NCUC, respectively, and are in effect for an increase in retail electric rates. On January 9,
1996bills rendered during the
PSC issued an order grantingperiod from November 1 through April 30 of each year. In each case the Company an increaseWNA
increases tariff rates if weather is warmer than normal and decreases rates if
weather is colder than normal. The WNA does not change the seasonality of 7.34% which will produce additional revenues of approximately
$67.5 million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 million annually based on a test year, or
6.47%, commenced on January 15, 1996. The second phase will
be implemented in January 1997 and will produce additional
revenues of approximately $8.0 million annually, or .87% more
than current rates. The PSC authorized a return on common equity
of 12.0%. The PSC also approved establishment of a Storm Damage
Reserve Account capped at $50 million to be collected through
rates over a ten-year period. Additionally, the PSC approved
accelerated recovery of substantially all (excluding accumulated
deferred income taxes) of the Company's electric regulatory
assets and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods
to allow recoverygas
revenues; however, it does reduce fluctuations caused by the end of the year 2000. The Company's
request to shift approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
On October 27, 1994 the PSC issued an order approving the
Company's request to recover through a billing surcharge to its
gas customers the costs of environmental cleanup at the sites of
former manufactured gas plants. The billing surcharge, which was
effective with the first billing cycle in November 1994 and is
subject to annual review, provides for the recovery of
approximately $16.2 million representing substantially all actual
and projected site assessment and cleanup costs for the Company's
gas operations that had previously been deferred. In October
1995, as a result of the ongoing annual review, the PSC approved
the continued use of the billing surcharge. The balance
remaining to be recovered amounts to approximately $14.5 million.
On September 14, 1992 the PSC issued an order granting the
Company a $.25 increase in transit fares from $.50 to $.75 in
both Columbia and Charleston, South Carolina; however, the PSC
also required $.40 fares for low-income customers and denied the
Company's request to reduce the number of routes and frequency of
service. The new rates were placed into effect on October 5,
1992. The Company has appealed the PSC's order to the Circuit
Court. On May 23, 1995 the Circuit Court ordered the case back
to the PSC for reconsideration of several issues including the
low-income rider program, routing changes, and the $.75 fare.
The Supreme Court declined to review an appeal of the Circuit
Court decision and dismissed the case. The PSC filed, along with
other intervenors, another Petition for Reconsideration, which
the Circuit Court denied. Procedural matters in this case are
yet to be resolved in the court.abnormal weather.
Fuel Cost Recovery Procedures
The PSC has established a fuel cost recovery procedure which determines the
fuel component in the Company'sSCE&G's retail electric base rates semiannuallyannually based on projected
fuel costs for the ensuing six-month12-month period, adjusted for any overcollection or
undercollection from the preceding six-month12-month period. The CompanySCE&G has the right to
request a formal proceeding at any time should circumstances dictate such a
review. In the April 1995 semiannual2000 annual review of the fuel cost component of electric
rates, the PSC decreased the fuel cost component of the electric rate from
14.16 mills per KWH to 13.48 mills per KWH, a monthly decrease of
$.68 for an average customer using 1,000 KWH a month. For the
October 1995 review the PSC continued the rate of 13.4813.30
mills per KWH. The Company'sFor the April 2001 annual review, SCE&G has filed for an increase
in the fuel cost component of electric rates to 15.79 mills per KWH.
SCE&G's gas rate schedules and contracts include mechanisms whichthat allow
it to recover from its customers changes in the actual cost of gas. The Company'sSCE&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
July 2000 the PSC approved SCE&G's request for an out-of-period adjustment to
increase the cost of gas component from 54.334 cents per therm to 68.835 cents
per therm, effective with the first billing cycle in August 2000. In the October
19952000 review the PSC decreasedincreased the base cost of gas from 51.058to 78.151 cents per therm. In
December 2000 the PSC approved SCE&G's request for an out-of-period adjustment
to increase the cost of gas component to 99.340 cents per therm, effective with
the first billing cycle in January 2001. In March 2001 the PSC approved SCE&G's
request to 43.081decrease the cost of gas component to 79.340 cents per therm,
effective with the first billing cycle in March 2001.
PSNC also operates under two rate provisions in addition to WNA that
serve to reduce fluctuations in PSNC's earnings. First, its Rider D rate
mechanism allows PSNC to recover, in any manner authorized by the NCUC, margin
losses on negotiated gas sales. The Rider D rate mechanism also allows PSNC to
recover from customers all prudently incurred gas costs, including changes in
natural gas prices. Second, PSNC operates with full margin transportation rates.
These rates allow PSNC to earn the same margin on gas delivered to customers
regardless of whether the gas is sold, or only transported, by PSNC to the
customer.
PSNC's rates are established using a base cost of gas approved by the
NCUC, which resultedmay be modified periodically to reflect changes in a monthly decreasethe market price
of $7.98 (including
applicable taxes) based on an average of 100 therms per month on
a residential bill duringnatural gas and changes in the heating season.
16
rates charged by PSNC's pipeline transporters.
PSNC may file revised tariffs with the NCUC coincident with these changes or it
may track the changes in its deferred accounts for subsequent rate
consideration. The NCUC reviews PSNC's gas purchasing practices annually.
ENVIRONMENTAL MATTERS
General
Federal and state authorities have imposed environmental control requirementsregulations
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 19931998 through 1995,2000, the Company's capital expenditures for
environmental control amounted to approximately $90.0 million.
In$98.4 million (including
approximately $88.1 million for SCE&G). This was in addition approximately $10.4 million, $8.8 million and $7.4
million of environmental controlto expenditures were made during
1995, 1994 and 1993, respectively, which were
included in "Other operation"operation and "Maintenance" expenses.maintenance" expenses, which were approximately
$19.6 million, $18.2 million, and $18.8 million during 2000, 1999 and 1998,
respectively (including approximately $16.6 million, $15.0 million and $16.2
million for SCE&G during 2000, 1999 and 1998, respectively). It is not possible
to estimate all future costs for environmental purposes, but forecasts for
capitalized environmental expenditures for the Company are $10.1$23.3 million for
19962001 and $138.8$192.8 million for the four-year period 19972002 through 2000.2005 (including
$22.8 million for 2001 and $129.4 million for the four-year period 2002 through
2005 for SCE&G). These expenditures are included in the Company's and SCE&G's
construction program.
Air Quality Control
The Clean Air Act requires electric utilitiesIn October 1998 the EPA issued a final rule requiring 22 states,
including South Carolina, to reduce
substantially emissionsmodify their state implementation plans (SIP) to
address the issue of sulfur dioxide and nitrogen oxide by
the year 2000. These requirements are being phased in over two
periods. The first phase hadNOx pollution. On May 25, 1999 a compliance date of January 1,
1995 and the second, January 1, 2000. The Company's facilities
did not require modifications to meet the requirements of Phase
I. The Company will most likely meet the Phase II requirements
through the burning of natural gas and/or lower sulfur coal in
its generating units and the purchase and use of sulfur dioxide
emission allowances. Low nitrogen oxide burners are being
installed to reduce nitrogen oxide emissions to the levels
required by Phase II. Air toxicity regulations for the electric
generating industry are likely to be promulgated around the year
2000.
The Company filed compliance plans related to Phase II
requirements with DHEC by December 31, 1995. The Company
currently estimates that air emissions control equipment will
require capital expenditures of $113 million over the 1996-2000
period to retrofit existing facilities, with increased operation
and maintenance cost of approximately $1 million per year. To
meet compliance requirements through the year 2005, the Company
anticipates total capital expenditures of approximately $150
million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the
imposition of effluent limitations that require various levels of
treatment for each wastewater discharge. Under this Act,
compliance with applicable limitations is achieved under a
national permit program. Discharge permits have been issued for
all and renewed for nearly all of the Company's and GENCO's
generating units. Concurrent with renewal of these permits the
permitting agency has implemented a more rigorous control
program. The Company has been developing compliance plans to
meet this program. Amendments to the Clean Water Act proposed in
Congress include several provisions which, if passed, could prove
costly to the Company. These include limitations to mixing
zones andfederal appeals court
delayed indefinitely the implementation of technology-based standards.
17
Superfund Actthe rule. On March 3, 2000 the court
affirmed the EPA's NOx rule for the affected states. South Carolina was
subsequently ordered to amend its SIP to achieve significant NOx reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and Environmental Assessment Program
The Company has an environmental assessment program to
identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
are deferred and are being amortized and recovered through rates
over a ten-year period for electric operations and an eight-year
period for gas operations. Deferred amounts totaled $18.0
million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates include, among other items, the costs
estimated to be associated with the matters discussed in the
following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company has maintained an active review of the sites to monitor
the nature and extent of the residual contamination.
In September 1992 the
EPA notified the Company, the Cityhas issued official notice to South Carolina (and a number of Charleston and the Charleston Housing Authority of their
potential liability for the investigation and cleanup of the
Calhoun Park Area Site in Charleston,other states)
to comply. While not final, South Carolina. This site
originally encompassed approximately eighteen acres and included
properties which were the locations for industrial operations,
including a wood preserving (creosote) plant and one of the
Company's decommissioned manufactured gas plants. The original
scope of this investigationCarolina has been expanded to approximately 30
acres, including adjacent properties owned by the National Park
Service and the City of Charleston, and private properties. The
site has not been placed on the National Priority List, but may
be added before cleanup is initiated. The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigations process to
be compressed significantly. The PRPs have negotiated an
administrative order by consent for the conduct of a Remedial
Investigation/Feasibility Study and a corresponding Scope
of Work. Field work began in November 1993. The Company is
also working with the City of Charleston to investigate potential
contamination from the manufactured gas plant which may have
migrated to the city's aquarium site. In 1994 the City of
Charleston notified the Companyproposed NOx reductions that
it considerswould require the Company to install pollution control equipment. Because DHEC
had not amended its SIP as of December 31, 2000 to set out or allocate any NOx
reductions, it is not possible to estimate what, if any, capital expenditures
will be responsible for a $43.5 million increase in costs of the
aquarium project attributablerequired to delays resulting from
contamination of the Calhoun Park Area Site. The Company
believes that it has meritorious defenses against this claim and
does not expect its resolution to have a material impact on its
financial position or results of operations.
The Company has been listed as a PRP and has recorded
liabilities, which are not material, for the Macon-Dockery waste
disposal site near Rockingham, North Carolina. The Company has
participated in de minimis buy-outs for the Aqua-Tech
Environmental Inc. site in Greer, South Carolina and a landfill
owned by Lexington County in South Carolina. The Company expects
to have no further involvementcomply with these two sites.
The Arkansas Department of Pollution Control and Ecology has
identified the Company as a PRP for clean-up of PCBs at an
abandoned transformer rebuilding plant in Little Rock, Arkansas.
No formal notice from the Department has been received. The
Company believes that its identification as a PRP was in error,
and that the resolution of this issue will not have a material
effect on the Company's results of operations or financial
position.
18any potential mandated reductions.
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of
1991 directed the DHEC to promulgate regulations for the disposal
of industrial solid waste. DHEC has promulgated a proposal
regulation, which if adopted as a final regulation in its present
form, would significantly increase the Company's costs of
construction and operation of existing and future ash management
facilities.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 requiresrequired 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 millmil 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. The CompanySCE&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.
The CompanySCE&G has on-site spent nuclear fuel storage capability until at least 20092006 and
expects to be able to expand its storage capacity
over the life of Summer Station to accommodate the spent
nuclear fuel output for the life of the plant through rod consolidation,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 the Company'sSCE&G's insurance coverage for Summer Station, reference
is made to Note 10B ofthe Notes to Consolidated Financial Statements.Statements (Note 13B for the
Company and Note 12B for SCE&G), which are incorporated herein by reference.
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.
ITEM 2. PROPERTIES
The Company'sSCANA 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 percent of an indirect subsidiary.
It also has investments in two LLCs: one operates a cogeneration facility in
Charleston, South Carolina and the other 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. 19GENCO'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
The following table gives information with respect to the Company'sInformation on electric generating facilities.facilities, all of which are owned by
SCE&G except as noted, is as follows:
Net Generating
Present Year CapabilityCapacity
Facility Fuel Capability Location In-Service (Summer Rating)
(KW)(1)
Steam
Urquhart-----
Urquhar(1) Coal/Gas Beech Island, SC 1953 250,000
McMeekin Coal/Gas Irmo, SC 1958 252,000
Canadys Coal/Gas Canadys, SC 1962 430,000420,000
Wateree Coal Eastover, SC 1970 700,000
Summer (2)Williams(2) Coal Goose Creek, SC 1973 615,000
Summer(3) Nuclear Parr, SC 1984 594,000
D-Area (3)635,000
D-Area(4) Coal DOE Savannah River
Site, SC 1995 17,00038,000
Cope (4) Coal Cope, SC 1996 385,000417,000
Cogen South * Charleston, SC 1999 65,000
Gas Turbines
------------
Burton Gas/Oil Burton, SC 1961 28,500
Faber Place Gas Charleston, SC 1961 9,500
Hardeeville Oil Hardeeville, SC 1968 14,000
Canadys Gas/Oil Canadys, SC 1968 14,000
Urquhart Gas/Oil Beech Island, SC 1969 38,000
Coit Gas/Oil Columbia, SC 1969 30,000
Parr (5) Gas/Oil Parr, SC 1970 60,000
Williams (6) Gas/Oil Goose Creek, SC 1972 49,000
Hagood Gas/Oil Charleston, SC 1991 95,000
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
Total (7) 3,722,000536,000
----------
4,544,000
(1) Summer rating.On September 21, 1999 SCE&G announced a $256 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.
(2) The steam unit at Williams Station is owned by GENCO. (3) Represents the Company'sSCE&G's
two-thirds portion of the Summer Station. (3)(4) This plant is operated under leaseleased from the DOE
and is dispatcheddedicated to DOE's Savannah
River Site steam needs. "Net Capacity Rating"Generating Capability" for this plant is
expected average hourly output. The lease which may be extended, expires on October 1, 2005.
(4) Plant began commercial operation in January 1996.
(5) Two of the four Parr gas turbines are leased* SCE&G receives shaft horse power from Cogen South, LLC to operate SCE&G's
generator. Cogen South, LLC is owned 50 percent by SCANA and have a net
capability of 34,000 KW. This lease expires on June 29,
1996. The Company has agreed to purchase the leased
turbines on the lease expiration date.
(6) The two gas turbines at Williams are leased and have a net
capability of 49,000 KW. This lease expires on June 29,
1997.
(7) Excludes Williams Station.
20
The Company50 percent by
Westvaco.
SCE&G owns 429450 substations having an aggregate transformer capacity of
19,577,86822,673,443 KVA. The transmission system consists of 3,0903,166 miles of lines and the
distribution system consists of 15,59616,778 pole miles of overhead lines and 3,1913,836
trench miles of underground lines.
GAS
Natural Gas
The Company'sSCE&G's gas system consists of approximately 6,833
miles of three-inch equivalent distribution pipelines and
approximately 11,26512,596 miles of
distribution mains and related service facilities.
Propane
The CompanySCE&G also has propane air peak shaving facilities which can supplement
the supply of natural gas by gasifying propane to yield the equivalent of 102,000 MCF73
MMCF per day of natural gas.day. These facilities can store the equivalent of 430,405 MCF392 MMCF of natural
gas.
Pipeline Corporation's gas system consists of approximately 1,947 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 785 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 7,049 miles
of distribution mains and related service facilities. PSNC also owns, through a
wholly owned subsidiary, 33.21 percent of Cardinal Pipeline Company, LLC, which
owns a 105-mile transmission pipeline. In addition, PSNC owns, through a wholly
owned subsidiary, 17 percent of Pine Needle LNG Company, LLC. Pine Needle owns
and operates a liquefaction, storage and regasification facility.
TRANSIT
The CompanySCE&G owns 9840 motor coaches which operate on a routeused in the operation of the Columbia
transit system. The Columbia system is comprised of 28617 routes covering 177
miles. SCE&G intends to dispose of its investment in the Columbia transit system
as soon as practicable. 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.Item 1, BUSINESS RATE
MATTERS (the Company, SCE&G and PSNC), "BUSINESS - RATE MATTERS"Environmental Matters in the Liquidity
and "BUSINESS - ENVIRONMENTAL MATTERS -
Superfund ActCapital Resources section of Item 7, MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS (the Company and Environmental Assessment Program"SCE&G), and Note 10
of Notes
to Consolidated Financial Statements appearing in Item 8., "FINANCIAL8, FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA."DATA (Note 13C and 13E for the Company, Note 12C and 12E for
SCE&G and Note 12 for PSNC).
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED
SECURITY HOLDER
CORPORATE STRUCTURE
SCANA CORPORATION
A holding company, owning the direct, wholly owned subsidiaries listed below
SOUTH CAROLINA ELECTRIC & GAS COMPANY SCANA COMMUNICATIONS, INC.
------------------------- --------------------------
Generates and sells electricity and gas Provides fiber optic
telecommunications to wholesale and retail customers, in South Carolina, tower
construction, purchases, sells and transports management and rental services
for natural gas at retail and provides wireless providers and, through a
public tansit service in Columbia. subsidiary, invests in telecommunications
companies.
SCANA ENERGY MARKETING, INC.
SOUTH CAROLINA GENERATING Markets electricity, natural gas and
COMPANY, INC. other light hydrocarbons primarily in
Owns and operates Williams Station and the southeast. Provides energy-related risk
sells electricity to SCE&G. management services to producers and customers.
Through its SCANA Energy division, markets
SOUTH CAROLINA FUEL natural gas in Georgia's deregulated retail natural
COMPANY, INC. gas market.
Acquires, owns and provides financing
for SCE&G's nuclear fuel, fossil fuel SERVICECARE, INC.
and sulfur dioxide emission allowances. Provides energy-related products and
service contracts on home appliances.
SOUTH CAROLINA PIPELINE
CORPORATION PRIMESOUTH, INC.
Purchases, sells and transports natural Engages in power plant management and
gas to wholesale and direct industrial maintenance services.
customers. Owns and operates two LNG
plants for the liquefaction, storage and SCANA RESOURCES, INC.
regasification of natural gas. Conducts energy-related businesses and provides
energy-related services.
PUBLIC SERVICE COMPANY OF
NORTH CAROLINA, INCORPORATED SCANA SERVICES, INC. Purchases, sells and
transports natural gas Provides administrative, management and other to retail
customers, markets natural gas, services to the subsidiaries and business
units refuels natural gas vehicles and within SCANA Corporation. 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. SCANA also owns four additional
companies that are in liquidation.
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 54 Chairman of the Board and Chief Executive Officer 1997-present
Chief Operating Officer 1996-1997
President *-present
President, SCI 1996-1997
Chief Financial Officer and Controller *-1996
H. T. Arthur 55 Senior Vice President and General Counsel 1998-present
Vice President and General Counsel 1996-1998
Vice President and General Counsel, Pipeline Corporation *-1996
G. J. Bullwinkel 52 Senior Vice President, Governmental Affairs and
Economic Development 1999-present
President, SCI 1997-present
Senior Vice President - Retail Electric, SCE&G *-1999
A. H. Gibbes 54 President and Chief Operating Officer, Pipeline Corporation 1996-present
Senior Vice President and General Counsel *-1996
President and Treasurer, SCANA Development Corp. *-present
D. C. Harris 48 Senior Vice President of Human Resources - SCANA 2000-present
Vice President Human Resources, Austin Quality Foods,
Inc., Cary, NC *-2000
N. O. Lorick 50 President and Chief Operating Officer, SCE&G 2000-present
Vice President of Fossil and Hydro Operations *-2000
K. B. Marsh 45 Senior Vice President - Finance and Chief Financial Officer 2000-present
Senior Vice President - Finance, Chief Financial Officer
and Controller 1998-2000
Vice President - Finance, Chief Financial Officer and Controller 1996-1998
Vice President - Finance, Treasurer and Secretary *-1996
A. M. Milligan 41 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
C. E. Zeigler, Jr. 54 President and Chief Operating Officer of PSNC 2000-present
Chairman, President and Chief Executive Officer *-2000
of PSNC (prior to acquisition)
S. A. Byrne 40 Vice President Nuclear Operations 2000-present
General Manager Nuclear Plant Operations *-2000
M. R. Cannon 50 Controller, SCANA and all subsidiaries (excluding SEMI) 2000-present
Treasurer, SCANA and SCE&G *-2000
* Indicates position held at least since March 1, 1996.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
COMMON STOCK INFORMATION - SCANA Corporation
- -------------------- ---------------------------------------------------- ----------------------------------------------------
2000 1999
- -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------
4th 1st
Qtr. 3rd Qtr. 2nd Qtr. Qtr. 4th Qtr. 3rd Qtr. 2nd Qtr. 1st Qtr.
- -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------
Price Range: (a)
High 31.13 30.94 26.88 29.00 28.31 25.69 26.94 32.56
Low 25.75 24.38 22.81 22.00 23.63 22.81 21.13 21.56
- -------------------- ----------- ------------- -------------- ----------- ------------ ------------ ------------- ------------
(a) As reported on the New York Stock Exchange Composite Listing.
- ------------------------------ -------------------- ------------------- ------------ -------------------- -----------------
Dividends Per Share 2000 1999
- ------------------------------ -------------------- ------------------- -------------------- -----------------
------------
Amount Date Declared Date Paid Amount Date Declared Date Paid
------ ------------- --------- ------ ------------- ---------
First Quarter .2875 February 22, 2000 April 1, 2000 .3850 March 9, 1999 April 1, 1999
Second Quarter .2875 April 27, 2000 July 1, 2000 .3850 June 9, 1999 July 1, 1999
Third Quarter .2875 August 16, 2000 October 1, 2000 .2750 September 10,1999 October 1, 1999
Fourth Quarter .2875 October 17, 2000 January 1, 2001 .2750 December 10,1999 January 1,2000
- ------------------ ----------- -------------------- ------------------- ------------ -------------------- -----------------
The principal market for SCANA common stock is the New York Stock Exchange.
The ticker symbol used is SCG. The corporate name SCANA is used in newspaper
stock listings. The total number of shares of SCANA common stock outstanding
at February 28, 2001 was 104,729,131. The number of common stockholders of
record at February 28, 2001 was 43,245.
All of the Company'sSCE&G and PSNC's common stock is owned by SCANA and therefore there ishas no market for such stock.market.
During 19952000 and 1994 the Company1999 SCE&G paid $116.7$130.8 million and $115.1$122.4 million,
respectively, in cash dividends to SCANA. During 2000, PSNC paid $19.0
million in cash dividends to SCANA.
SECURITIES RATINGS (As of February 28, 2001)
SCANA SCE&G PSNC
- ---------------------- ---------------------------- ---------------------------------------------- -- ----------------------
First and
Medium- First Refunding Trust
Rating Term Mortgage Mortgage Preferred Preferred Commercial Senior Commercial
Agency Notes Bonds Bonds Stock Securities Paper Unsecured Paper
------ ----- ----- ----- ----- ---------- ----- --------- -----
Fitch
IBCA,
Duff
&
Phelps A- A+ A+ A A F-1 n/a n/a
Moody's A3 A1 A1 a2 a2 P-1 A2 P-1
Standar
& A-
Poors d A A BBB+ BBB+ A-1 A A-1
- --------- ------------ ---------------- ------------- ------------ ------------ --------------- -------------- -------------
Further reference is made to the Notes to Consolidated Financial Statements
appearing in Item 8, FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA for SCANA
(Note 6), SCE&G (Note 5) and PSNC (Note 7).
The Restated Articles of Incorporation of the CompanySCE&G and the Indenture
underlying its First and Refunding Mortgage Bonds contain provisions that,
mayunder certain circumstances, could limit the payment of cash dividends on
common stock. In addition, with respect to hydroelectric projects, the
Federal Power Act may requirerequires the appropriation of a portion of thecertain earnings
therefrom. At December 31, 19952000 approximately $14.5$32.7 million of retained
earnings were restricted by this requirement as to payment of cash dividends
on common stock.
21stock of SCE&G.
ITEM 6. SELECTED FINANCIAL DATA
SCANA
- ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- ---
For the Years Ended December 31, 2000(1) 1999 1998 1997 1996
- ------------------------------------------------------ ---------- ----------- ------------ ---------- ---------- ---
Statement of Income Data
ITEM 6. SELECTED FINANCIAL DATA
For the Years Ended December 31, 1995 1994 1993 1992 1991
Statement of Income Data (Thousands of Dollars except statistics)
Operating Revenues $1,211,087 $1,181,274 $1,118,433 $ 994,381 $1,022,342$3,433 $2,078 $2,106 $1,725 $1,510
Operating Income 255,854 230,418 219,319 182,267 196,706554 353 470 425 442
Other Income 9,553 7,271 6,585 3,006 3,283(Loss) 44 90 19 41 20
Income Before Cumulative Effect of Accounting
Change 221 179 223 221 215
Net Income 169,185 152,043 145,968 102,163 122,836
Earnings Available for Common Stock 163,498 146,088 139,751 95,689 116,130250 179 223 221 215
Balance Sheet Data
Utility Plant, Net $3,157,657 $2,998,132 $2,687,193 $2,503,201 $2,380,761$4,949 $3,851 $3,787 $3,648 $3,529
Total Assets 3,802,433 3,587,091 3,189,939 2,890,953 2,748,5807,420 6,011 5,281 4,932 4,759
Capitalization:
Common equity 1,315,072 1,133,432 1,051,334 963,741 840,5052,032 2,099 1,746 1,788 1,684
Preferred stockStock (Not subject to purchase or
sinking funds) 26,027 26,027 26,027 26,027 26,027106 106 106 106 26
Preferred stock, NetStock (Subject to purchase or
sinking funds) 46,243 49,528 52,840 56,154 59,46910 11 11 12 43
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 50 -
Long-term debt, Net 1,279,379 1,231,191 1,097,043 945,964 993,674Debt, net 2,850 1,563 1,623 1,566 1,581
- ------------------------------------------------------ ---------- ----------- ------------ ---------- ----------
====================================================== ========== =========== ============ ========== ---
Total Capitalization $2,666,721 $2,440,178 $2,227,244 $1,991,886 $1,919,675$5,048 $3,829 $3,536 $3,522 $3,334
====================================================== ========== =========== ============ ========== ========== ---
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions) 104.5 103.6 105.3 107.1 105.1
Basic and Diluted Earnings Per Share $2.40 $1.73 $2.12 $2.06 $2.05
Dividends Declared Per Share of Common Stock $1.15 $1.32 $1.54 $1.51 $1.47
Other Statistics (2)
Electric:
Customers (Year-End) 484,381 476,438 468,901 461,928 453,687
Territorial Sales537,253 523,552 517,447 503,905 493,320
Total sales (Million KWH) 17,585 16,840 16,889 15,801 15,70223,352 21,744 21,203 18,852 18,905
Residential:
Average annual use per customer (KWH) 13,859 13,048 14,077 13,037 13,24614,596 14,011 14,481 13,214 14,149
Average annual rate per KWH $.0747 $.0743 $.0707 $.0695 $.0700$.0787 $.0787 $.0801 $.0799 $.0785
Generating capability - Net MW (Year-End) 4,544 4,483 4,387 4,350 4,316
Territorial peak demand - Net MW 4,211 4,158 3,935 3,734 3,698
Regulated Gas:
Customers (Year-End) 243,342 238,433 221,278 218,582 214,485637,017 260,456 257,051 252,797 248,787
Sales, excluding transportation (Thousand
Therms) 362,384 322,837 267,335 256,495 247,4831,389,975 1,013,083 1,002,952 945,289 893,170
Residential:
Average annual use per customer (Therms) 570 538 606 577 522644 507 521 531 639
Average annual rate per therm $.82 $.84 $.76$1.08 $.86 $.86 $.86 $.74
$.77Nonregulated Gas:
Retail customers (Year-End) 431,814 430,950 78,091 n/a n/a
Firm customer deliveries (Thousand Therms) 431,115 229,660 4,692 n/a n/a
Interruptible customer deliveries (Thousand
Therms) 306,099 188,828 2,167,931 n/a n/a
SCE&G
- ------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
For the Years Ended December 31, 2000 1999 1998 1997 1996
- ------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
Statement of Income Data
Operating Revenues $1,669 $1,465 $1,450 $1,337 $1,341
Operating Income 457 393 448 387 404
Other Income (Loss) 16 12 9 5 (6)
Income Before Cumulative Effect of Accounting
Change 231 189 227 195 190
Net Income 253 189 227 195 190
Balance Sheet Data
Utility Plant, Net $3,615 $3,501 $3,432 $3,310 $3,197
Total Assets 4,664 4,404 4,246 4,054 3,959
Capitalization:
Common equity 1,657 1,558 1,499 1,447 1,413
Preferred Stock (Not subject to purchase or
sinking funds) 106 106 106 106 26
Preferred Stock (Subject to purchase or
sinking funds) 10 11 11 12 43
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 50 -
Long-term Debt, net 1,267 1,121 1,206 1,262 1,277
- ------------------------------------------------------ ---------- ---------- ---------- ---------- ----------
====================================================== ========== ========== ========== ========== ==========
Total Capitalization $3,090 $2,846 $2,872 $2,877 $2,759
====================================================== ========== ========== ========== ========== ==========
Common Stock Data
Weighted Average Number of Common Shares
Outstanding (Millions) n/a n/a n/a n/a n/a
Basic and Diluted Earnings Per Share n/a n/a n/a n/a n/a
Dividends Declared Per Share of Common Stock n/a n/a n/a n/a n/a
Other Statistics (2)
Electric:
Customers (Year-End) 537,286 523,581 517,472 503,930 493,346
Total sales (Million KWH) 23,353 21,746 21,204 18,853 18,907
Residential:
Average annual use per customer (KWH) 14,596 14,011 14,481 13,214 14,149
Average annual rate per KWH $.0787 $.0787 $.0801 $.0799 $.0785
Generating capability - Net MW (Year-End) 3,929 3,883 3,807 3,790 3,756
Territorial peak demand - Net MW 4,216 4,158 3,935 3,734 3,698
Regulated Gas:
Customers (Year-End) 266,451 260,348 256,843 252,589 248,497
Sales, excluding transportation (Thousand
Therms) 414,405 414, 800 405,249 381,726 387,328
Residential:
Average annual use per customer (Therms) 563 507 521 531 639
Average annual rate per therm $.95 $.86 $.86 $.86 $ .74
Nonregulated Gas:
Retail customers (Year-End) n/a n/a n/a n/a n/a
Firm customer deliveries (Thousand Therms) n/a n/a n/a n/a n/a
Interruptible customer deliveries (Thousand
Therms) n/a n/a n/a n/a n/a
22
SCANA CORPORATION
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................ 26
Item 7A. Quantitative Disclosures About Market Risk................... 41
Item 8. Financial Statements and Supplementary Data.................. 42
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
COMPETITION
The electric utility industry has begunStatements 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 major transitionnumber of risks and
uncertainties, and that actual results could differ materially from those
indicated by such forward-looking statements. Important factors that could leadcause
actual results to expanded marketdiffer 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, especially in areas served by the
Company's subsidiaries , (4) the impact of competition from other energy
suppliers, (5) growth opportunities for the Company's regulated and less
regulatory protection. Future deregulationdiversified
subsidiaries, (6) the results of financing efforts, (7) changes in the Company's
accounting policies, (8) weather conditions, especially in areas served by the
Company's subsidiaries , (9) performance of and marketability of the Company's
investments in telecommunications companies, (10) inflation, (11) changes in
environmental regulations and (12) 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
Regulated Electric and Gas Markets
Efforts to restructure electric markets at the state level have slowed
considerably. Dwindling operating reserves and rolling blackouts in parts of
California in January and February 2001 have been widely reported nationwide.
These shortages of electricity have been attributed to flawed state
restructuring legislation, unplanned generating plant shutdowns and other
economic factors. In response, many states that had passed or considered
legislation to restructure the electric industry have stopped such efforts or
are proceeding more slowly.
In South Carolina, electric restructuring efforts also have stalled. The
developments unfolding in California, and several unrelated, contentious issues
before the General Assembly have combined to make consideration of electric
wholesale
and retail markets will create opportunities to compete for new
and existing customers and markets. Asrestructuring legislation unlikely in 2001. Legislation or regulatory action at
the Federal level, particularly as a result, profit margins
and asset valuespart of some utilities could be adversely affected.
The pace of deregulation, future prices of electricity, and the
regulatory actions whicha larger energy policy initiative,
may be taken by the PSCconsidered in response to
the changing environment cannot be predicted. However, the2001. The Company is aggressively pursuing actionsnot able to position itself
strategicallypredict whether any
restructuring legislation or regulatory action will be enacted and, if it is,
the conditions it will impose on utilities.
The Company has taken several steps to prepare for the transformed environment. To enhance its
flexibility and responsiveness to change, the Company operates
Strategic Business Units. Maintaining a competitive cost
structure is of paramount importancerestructuring,
including aggressive participation in the utility's strategic
plan. The Companynewly deregulated natural gas market
in Georgia (further discussed at Georgia Retail Gas Market below). In addition,
SCANA's electric and gas utility, SCE&G, has undertaken a variety of initiatives
including reductions in operation and maintenance costs and in
staffing levels. In January 1996 the PSC approved (as discussed
under "Liquidity and Capital Resources") theaimed at preparing for a restructured electric market. These initiatives include
obtaining accelerated recovery of the Company's electric regulatory assets, establishing open
access transmission tariffs and the shiftselling bulk power to wholesale customers at
market-based rates. Marketing of depreciation reserves from transmissionservices to commercial and distribution assets
to nuclear production assets.industrial customers
has also increased significantly, and 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 newevolving
operating environment to come.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. Such an eventAlthough 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 recorded.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
$116$244 million and $4$75 million of regulatory assets and liabilities, respectively,
excludingincluding amounts related
to net accumulatedrecorded for deferred income tax assets and liabilities of
approximately $33$140 million and $57 million, respectively, on its balance sheet
at December 31, 1995.2000.
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,
2000 the Company's net investment in fossil/hydro and nuclear generation assets
was $1,332.6 million and $587.2 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 has been
accounted for as a purchase. PSNC is operated as a wholly-owned subsidiary of
SCANA. As a result of the transaction, SCANA became a registered public utility
holding company under PUHCA.
Georgia Retail Gas Market
SCANA Energy, the retail gas division of Energy Marketing, has been
aggressively marketing natural gas to residential and commercial customers in
Georgia. SCANA Energy is Georgia's second largest gas marketer, with
approximately 432,000 customers at December 31, 2000, or approximately a 30
percent market share. For purposes of comparison, SCANA Energy had approximately
431,000 customers at December 31, 1999 and 78,000 at December 31, 1998. In 2000
SCANA Energy successfully transitioned from start up to ongoing operations and
for the year ended December 31, 2000 recognized net earnings of approximately
$4.4 million. SCANA Energy's strategy includes the determination of
methodologies to serve all customer classes profitably and developing programs
that will enhance relationships with those customers and attract similar new
customers. In addition SCANA Energy has successfully employed a gas supply
hedging strategy and has maintained a price structure that is both competitive
and profitable. The level of future revenues and expenditures is dependent on
several factors, including SCANA Energy's ability to retain customers and market
share, the weather, the margin achieved on gas sales and its ability to find
industrial interruptible customers to purchase available capacity.
Proposed Interstate Pipeline
Pipeline Corporation, a wholly owned subsidiary of the Company, is
developing plans for an interstate natural gas pipeline to ensure adequate
supplies to growing gas markets. The anticipated interstate pipeline will
require Pipeline Corporation to file an application for approval with the FERC
and other federal and state agencies.
LIQUIDITY AND CAPITAL RESOURCES
The Company's cash requirements of the Company arise primarily from itsSCE&G's and PSNC's
operational needs, the Company's construction program, the need to fund the
activities or investments of SCANA's nonregulated subsidiaries and its construction program.payment of
dividends. The ability of the CompanySCANA's regulated subsidiaries to replace existing
plant investment, as well as to expand to meet future demandsdemand for electricity and
gas, will depend upon itstheir ability to attract the necessary financial capital
on reasonable terms. The Company recoversSCANA'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 Company expands itsregulated subsidiaries continue their ongoing
construction program,programs, it ismay be necessary to seek increases in rates. As a
result the Company's future financial position and results of operations will be
affected by itsthe regulated subsidiaries' ability to obtain adequate and timely
rate and other regulatory relief.
Due to continuing customer growth, the Company entered into
a contract with Duke/Fluor Daniel in 1991 to design, engineer and
build a 385 MW coal-fired electric generating plant near Cope,
South Carolina. Construction of the plant started in November
1992. Commercial operation began in January 1996.relief, if requested.
The estimated
cost of the Cope plant, excluding AFC, is $410.9 million. In
addition, the transmission lines for interconnection with the
Company's system are expected to cost $22.5 million.
On July 10, 1995 the Company filed an application with the
PSC for an increase in retail electric rates. On January 9, 1996
the PSC issued an order granting the Company an increase of 7.34%
which will produce additional revenues of approximately $67.5
million annually. The increase will be implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 annually based on a test year, or 6.47%,
commenced on January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates. The PSC authorized a return on common equity of 12.0%.
The PSC also approved establishment of a Storm Damage Reserve
Account capped at $50 million to be collected through rates over
a ten-year period. Additionally, the PSC approved accelerated
recovery of substantially all of the Company's electric
regulatory assets (excluding accumulated deferred income taxes)
and the remaining transition obligation for postretirement
benefits other than pensions, changing the amortization periods
to allow recovery by the end of the year 2000. The Company's
request to shift approximately $257 million of depreciation
reserves from transmission and distribution assets to nuclear
production assets was also approved.
23
Therevised estimated primary cash requirements for 1996,2001 and
the actual primary cash requirements for 2000, excluding requirements for fuel
liabilities and short-term borrowings, (including notes payable to affiliated companies), and the actual
primary cash requirements for 1995 are as follows:
1996 1995
(Thousands(Millions of Dollars) 2001 2000
- ------------------------------------------------------------- --------------
Property additions and construction
expenditures, net of allowance for
funds used during construction $197,179 $250,870$501 $332
Nuclear fuel expenditures 21,147 21,04526 29
Investments 25 20
Maturing obligations, redemptions and
sinking and purchase fund requirements 21,197 15,81214 284
- ------------------------------------------------------------- --------------
Total $239,523 $287,727$566 $665
============================================================= ==============
Approximately 45%39 percent of total cash requirements (after payment of
dividends) was provided from internal sources in 19952000 as compared to 22%16 percent
in 1994.1999.
The Company'sCompany anticipates that its 2001 cash requirements of $566 million
will be met through internally generated funds (approximately 61 percent, after
payment of dividends), and the incurrence of additional short-term and long-term
indebtedness. Sales of additional equity securities may also occur. 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.
SCANA and PSNC each have in effect a medium-term note
program for the issuance from time to time of unsecured medium-term debt
securities. At December 31, 2000 SCANA had registered with the SEC and available
for issuance $1 billion under this program, the proceeds of which may be used to
refinance indebtedness incurred in connection with the acquisition of PSNC, to
fund additional business activities in nonutility subsidiaries, to reduce
short-term debt or for general corporate purposes. On February 14, 2001 PSNC
registered $150 million of medium-term notes with the SEC.
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 twelve12 consecutive months out of the fifteen18 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, 19952000 the
Bond Ratio was 3.97.6.43. The Old Mortgage allows the issuance of additional Class A
Bonds also is restricted to an additional principal amount equal to (i) 60%70 percent of unfunded net
property additions (which unfunded net property additions totaled approximately
$162.3$1,452 million at December 31, 1995)2000), (ii) retirements of Class A Bonds (which
retirement credits totaled $64.8$68.4 million at December 31, 1995)2000), and (iii) and cash
on deposit with the Trustee.
The Company hasSCE&G is subject to a newbond indenture (New Mortgage) 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 $185$665 million were available for such purpose as ofat December 31,
1995), until such time as all
presently outstanding Class A Bonds are retired. Thereafter, New
Bonds will be issuable on the basis of property additions in a
principal amount equal to 70% of the original cost of electric
and common plant properties (compared to 60% of value for Class A
Bonds under the Old Mortgage), cash deposited with the Trustee,
and retirement of New Bonds.2000). New Bonds will be issuable under the New Mortgage only if adjusted net
earnings (as therein defined) for twelve12 consecutive months out of the eighteen18 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, 19952000
the New Bond Ratio was 5.31.6.34.
The following additional financing transaction hastransactions have occurred since
December 31, 1994:January 1, 2000:
o On April 12, 1995February 8, 2000 the Company issued $100$400 million of two-year floating
rate notes maturing February 8, 2002. The interest rate on the notes is
reset quarterly based on three-month LIBOR plus 50 basis points. The
proceeds from these privately sold notes were used to consummate SCANA's
acquisition of PSNC. On February 10, 2000 SCANA borrowed $300 million for a
three-year term under a credit agreement with several banks. The interest
rate is reset every one, two, three or six months and is based on LIBOR
plus 100 basis points. These funds also were used to consummate SCANA's
acquisition of PSNC.
o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds 7 5/8% serieshaving
an annual interest rate of 7.50 percent and maturing on June 15, 2005. The
proceeds from the sale of these bonds were used to pay the maturity of
SCE&G's $100 million First Mortgage Bonds due April 1, 2025June 15, 2000, to reduce
short-term debt and for general corporate purposes.
o On July 13, 2000 SCANA issued $300 million two-year floating rate notes
maturing on July 15, 2002. The interest rate is reset quarterly based on
three-month LIBOR plus 65 basis points. Proceeds from the debt were used to
repay medium-term notes totaling $170 million, to reduce short-term borrowings.debt
and for general corporate purposes.
o On January 24, 2001 SCANA issued $202 million two-year floating rate notes
maturing on January 24, 2003. The interest rate is reset quarterly based on
three-month LIBOR plus 110 basis points. Proceeds from the debt were used
to reduce short-term debt and for general corporate purposes.
o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having
an annual interest rate of 6.70 percent and maturing on February 1, 2011.
The proceeds from the sale of these bonds were used to reduce short-term
debt and for general corporate purposes.
o On February 16, 2001 PSNC issued $150 million of medium-term notes having
an annual interest rate of 6.625 percent and maturing on February 15, 2011.
These funds were used to reduce short-term debt and for general corporate
purposes.
The Company's electric and natural gas businesses are seasonal in nature,
with the primary demand for electricity being experienced during summer and
winter and the primary demand for natural gas being experienced during winter.
As a result of the significant increase during the latter half of 2000 in the
cost to the Company of natural gas and the colder than normal weather
experienced in December, the Company experienced significant increases in its
working capital requirements, contributing to the need for the financings by
SCANA and PSNC in early 2001 described above.
Without the consent of at least a majority of the total voting power of
the Company'sSCE&G's preferred stock, the CompanySCE&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%ten percent of the aggregate
principal amount of all of the Company'sSCE&G's secured indebtedness and capital and surplus;
provided, however, that no such consent shall beis required to enter into agreements for payment of
principal, interest and premium for securities issued for pollution control
purposes.
Pursuant to Section 204 of the Federal Power Act, the
CompanySCE&G and GENCO must
obtain the FERC authority to issue short-term indebtedness. Thedebt. FERC hahas authorized the CompanySCE&G to
issue up to $200$250 million of unsecured promissory notes or commercial paper with
maturity dates of twelve12 months or less, but not later than December 31, 1997.
The Company2002. GENCO
has not sought such authorization.
At December 31, 2000 SCE&G had $165$250 million of unused authorized and unused lines of
credit which consist of a credit agreement for a maximum of $250 million to
support the issuance of commercial paper SCE&G's commercial paper outstanding at
December 31, 1995.2000 and 1999 was $117.5 million and $143.1 million, respectively.
In addition, theFuel Company has a credit agreement for a maximum of $125 million
with the full amount available at December 31, 1995.2000. 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, 19952000 was $76.8$70.2 million. 24
The Company'sThis
commercial paper and amounts outstanding under the revolving credit agreement,
if any, are guaranteed by SCE&G.
At December 31, 2000 PSNC had $125 million authorized lines of credit
which consist of a credit agreement for a maximum of $125 million to support the
issuance of commercial paper. Unused lines of credit at December 31, 2000
totaled $125 million. PSNC's commercial paper outstanding on December 31, 2000
was $125 million.
SCE&G's Restated Articles of Incorporation prohibit issuance of
additional shares of preferred stock without consent of the preferred
stockholders unless net earnings (as defined therein) for the twelve12 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, 19952000 the
Preferred Stock Ratio was 2.58.2.09.
As a result of SCANA's acquisition of PSNC on February 10, 2000, PSNC
shareholders were paid $212 million in cash and 17.4 million shares of SCANA
common stock valued at approximately $488 million. In connection with this
transaction, certain SCANA shareholders were paid $488 million in cash for 16.3
million shares of SCANA common stock. During 2000, shares for the Stock Purchase
Savings Plan and the Investor Plus Plan were purchased on the open market.
On September 21, 1999 SCE&G announced a $256 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 Company anticipatesturbine project is
scheduled to be completed by June 2002.
On October 15, 1999 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. Until discussions are concluded it is
not possible to finalize the cost of the project; however, it is possible that
its 1996 cash requirementsthe costs could range up to $250 million. Although any costs incurred by SCE&G
are expected to be recoverable through electric rates, SCE&G also is exploring
alternative sources of $378.9funding. The project is expected to be completed in 2004.
On October 7, 2000 Summer Station was removed from service for a
planned maintenance and refueling outage scheduled to last 38 1/2 days. During
initial inspection activities, plant personnel discovered a small leak coming
from a hole in a weld in a primary coolant system pipe. SCE&G performed
extensive ultrasonic testing of similar welds in the cooling system, which
confirmed that the problem was limited to this single weld. A root cause
analysis determined that the cause of the crack was primary water stress
corrosion cracking. The repair involved cutting out a twelve-inch long spool of
the pipe, which included the entire weld, and installing a new spool piece.
Repairs have been completed and the integrity of the new welds have been
verified through extensive testing. The plant was returned to service in March
2001. The NRC was closely involved throughout this process and approved SCE&G's
actions to repair the crack, as well as the restart schedule. SCE&G will
continue to monitor primary coolant system pipes during the next outage,
scheduled for Spring of 2002. SCE&G recorded a pretax charge of approximately $6
million willin the fourth quarter of 2000 to expense repair costs to date.
Additional costs that may be metrecorded in the first quarter of 2001 are not
expected to be material. The cost of replacement power is expected to be
recovered through internally generated funds
(approximately 77%, after paymentSCE&G's electric fuel adjustment clause.
In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
was taken out of dividends),service due to an electrical ground in the salesgenerator. The unit
is expected to be returned to service in Spring 2001. The cost of additional equity securities, additional equity contributionsreplacement
power is expected to be recovered through SCE&G's fuel adjustment clause.
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. 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 as defendants in the suit. SCANA and the incurrenceother defendants believe the
suit is without merit and are mounting an appropriate defense. SCANA does not
believe that the resolution of additional short-term and long-
term indebtedness. The timing and amountthis issue will have a material impact on its
results of such financing will
depend upon market conditions and other factors. Actual 1996
expenditures may vary from the estimates set forth above due to
factors such as inflation and economic conditions, regulation and
legislation, rates of load growth, environmental protection
standards and the cost and availability of capital.
The Company expects that it hasoperations, cash flows or can obtain adequate
sources of financing to meet its projected cash requirements for
the next twelve months and for the foreseeable future.financial position.
Environmental Matters
The Clean Air Act requires(CAA) required electric utilities to reduce
substantially emissions
of sulfur dioxide and nitrogen oxide substantially by the year 2000. These
requirements are beingwere phased in over two periods. The first phase had a compliance
date of January 1, 1995 and the second, January 1, 2000. The Company's
facilities did not require modifications to meet the requirements of Phase I.
The Company will most likely meetis 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 are beinghave been
installed to reduce nitrogen oxide emissions to the levels required by Phase II.
Air toxicityThe EPA has indicated that it will propose regulations for the electric
generating industry are likely to be promulgated around the year
2000.
Bystricter limits on
mercury and other toxic pollutants generated by coal-fired plants by December
31, 1995 the Company had2003 and will begin developing these regulations shortly.
SCE&G and GENCO filed compliance plans with DHEC related to Phase II
sulfur dioxide requirements with DHEC.in 1995 and Phase II oxides of nitrogen (NOx)
requirements in 2000, 1999, 1998 and 1997. The Company currently estimates that
air emissions control equipment will require capital expenditures of $113$141
million over the 1996-20002001-2005 period to retrofit existing facilities, with
increased operation and maintenance costcosts of approximately $1$3 million per year.
To meet compliance requirements for the years 2006 through the year 2005,2010, the Company
anticipates totaladditional capital expenditures of approximately $150$5 million.
In October 1998 the EPA issued a final rule requiring 22 states,
including South Carolina, to modify their state implementation plans (SIP) to
address the issue of NOx pollution. On May 25, 1999 a federal appeals court
delayed indefinitely the implementation of the rule. On March 3, 2000 the court
affirmed the EPA's NOx rule for the affected states. South Carolina was
subsequently ordered to amend its SIP to achieve significant NOx reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and the
EPA has issued official notice to South Carolina (and a number of other states)
to comply. While not final, South Carolina has proposed NOx reductions that
would require the Company to install pollution control equipment. Because DHEC
had not amended its SIP as of December 31, 2000 to set out or allocate any NOx
reductions, it is not possible to estimate what, if any, capital expenditures
will be required to comply with any potential mandated reductions.
The EPA has undertaken an aggressive enforcement initiative against the
industry and the Department of Justice (DOJ) has brought suit against a number
of utilities in federal court alleging violations of the CAA. Prior to the
suits, those utilities had received requests for information under Section 114
of the CAA, and were issued Notices of Violation prior to the suits. The basis
for these suits is the claim by the EPA that maintenance activities undertaken
by the utilities over the past 20 or more years constitute "major modifications"
which would have required the installation of costly Best Available Control
Technology (BACT). The Company and SCE&G have received and responded to Section
114 requests for information related to Canadys, Wateree and Williams Stations.
Similar requests have been sent to a number of other utilities nationwide. The
regulations under the CAA provide certain exemptions to the definition of "major
modifications," particularly an exemption for routine repair, replacement or
maintenance. The Company has analyzed each of the activities covered by the
EPA's requests and believes each activity represents prudent practice regularly
performed throughout the utility industry as necessary to maintain the
operational efficiency and safety of equipment. As such, the Company believes
that each of these activities is covered by the exemption for routine repair,
replacement and maintenance and that the EPA is changing, or attempting to
change through enforcement actions, the intent and meaning of its regulations.
The Company also believes that, even if some of the activities in question were
found not to qualify for the routine exemption, there were no increases either
in annual emissions or in the maximum hourly emissions achievable at any of the
units caused by any of the activities. The regulations provide an exemption for
increased hours of operation or production rate and for increases in emissions
resulting from demand growth. It is possible that the EPA will eventually
commence enforcement actions against SCE&G relative to those plants. The EPA has
the authority to seek penalties for the alleged violations in question at the
rate of up to $27,500 per day for each violation. The EPA also would seek
installation of BACT (or equivalent) at the three plants as well. The Company
believes that the EPA's and DOJ's claims are without merit, and that any
enforcement action, up to and including a lawsuit resulting from this issue,
will not have a material adverse effect on the Company's financial position or
results of operations.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require various levels of treatment for each wastewaterwaste
water discharge. Under this Act, compliance with applicable limitations is
achieved under a national permit program. Discharge permits have been issued for
all and renewed for nearly all of SCE&G's and GENCO's generating units.
Concurrent with renewal of these permits, the permitting agency has implemented
a more rigorous control programs.program in monitoring and controlling thermal discharges and
strategies for toxicity reduction in wastewater streams. The Company has been
developing compliance plans for this program.these initiatives. Amendments to the Clean Water
Act proposed in Congress include several provisions which, if passed, could
prove costly to the
Company.SCE&G and GENCO. These include, but are not limited to,
limitations to mixing zones and the implementation of technology-based
standards. In December 2000 SCE&G entered into a Consent Order with DHEC related
to a malfunction of the waste water treatment facility at Hagood Station.
The South Carolina Solid Waste Policy and Management Act of
1991 directed DHECorder requires SCE&G to promulgate regulations forcorrect the disposal of
industrial solid waste. DHEC has promulgated a proposed
regulation which, if adopted as a final regulation in its present
form, would significantly increase the Company's and GENCO's
costs of construction and operation of existing and future ash
management facilities.
25
violation.
The Company hasmaintains an environmental assessment program to identify
and assess current and former operations sites that could require environmental
cleanup. As site assessments are initiated, estimates are made of the cost,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; suchoperations. Such amounts are deferred and
are being amortized andwith recovery provided through rates.
SCE&G has also recovered portions of its environmental liabilities
through settlements with various insurance carriers, including all amounts
previously deferred for its electric operations. SCE&G expects to recover all
deferred amounts related to its gas operations by December 2005. Deferred
amounts, net of amounts recovered through rates over a ten-year period for electric operations and an eight-
year period for gas operations. Deferred amountsinsurance settlements,
totaled $18.0$20.2 million and $20.2$23.7 million at December 31, 19952000 and 1994,1999,
respectively. Estimates include, among other items,The deferral includes the estimated costs associated with the
matters discussed in the following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.matters.
o In September 1992 the EPA notified the Company,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 Sitearea site in Charleston,
South Carolina. This site originally encompassedencompasses approximately eighteen30 acres and
includedincludes properties which were the locations for industrial operations,
including a wood preserving (creosote) plant, and one of the
Company'sSCE&G's
decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacentMGPs, properties owned by the National Park Service and
the City of Charleston and private properties. The site has not been
placed on the National PriorityPriorities List, but may be added before cleanup is initiated.in the
future. The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigation process to be
compressed significantly. The PRPs have negotiated an administrative order by consent for the
conduct of a Remedial Investigation/Feasibility Study and a
corresponding Scope of Work. Field work began in November 1993.1993, 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 Work Plan 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 $2 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. SCE&G submitted a Comprehensive Remedial
Design Work Plan (RDWP) on December 17, 1999 and proceeded with
implementation pending agency approval. The Company
is also working withRDWP was approved by the
EPA in July 2000, and its implementation continues.
In October 1996 the City of Charleston to investigate
potential contamination fromand SCE&G settled all
environmental claims the manufactured gas plant whichCity may have migrated to the City's aquarium site. In 1994 the City of
Charleston notified the Company that it considers the Company to
be responsible for a $43.5 million increase in costs of the
aquarium project attributable to delays resulting from
contamination ofhad against SCE&G involving the
Calhoun Park Area Site. The Company
believes it has meritorious defenses against this claim andarea 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 expect its resolutionencompass 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 constructed an 1,100 space parking
garage on the Calhoun Park site (construction was completed in April
2000) and transferred the facility to the City in exchange for a $16.5
million, 18-year municipal bond collaterized by revenues from, and a
mortgage on, the parking garage.
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. For the site located in
Florence, South Carolina, SCE&G entered into a similar Remedial Action
Plan Contract with DHEC effective September 5, 2000. SCE&G is
continuing to investigate the remaining site in Columbia, and is
monitoring the nature and extent of residual contamination.
In addition, PSNC owns, or has owned, all or portions of seven 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. An environmental due diligence review of PSNC
conducted in February 1999 estimated that the cost to remediate the remaining
sites would range between $11.3 million to $21.9 million. During the second
quarter of 2000, the review was finalized and the estimated liability was
recorded. 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. PSNC's associated actual costs for these sites will depend on a
material impact on its
financial position or resultsnumber of operations.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. At December 31, 2000 PSNC has recorded a liability and
associated regulatory asset of $10.2 million, which reflects the minimum amount
of the range, net of shared cost recovery from other PRPs. Amounts incurred to
date are not material. Management intends to request recovery of additional MGP
cleanup costs not recovered from other PRPs in future rate case filings, and
believes that all costs incurred will be recoverable in gas rates.
Regulatory Matters
TheSouth Carolina Electric & Gas Company
filedOn July 20, 2000 the PSC issued an order approving SCE&G's request for
electric rate reliefan out-of-period adjustment to increase the cost of gas component of its rates
for natural gas service from 54.334 cents per therm to 68.835 cents per therm,
effective with the first billing cycle in 1995 to
encompass primarily the remainingAugust 2000. As part of its regularly
scheduled annual review of gas costs, of completing the Cope
Generating Station. As discussed under "Liquidity and Capital
Resources," the PSC issued an order on November 9,
2000 which further increased the cost of gas component to 78.151 cents per
therm, effective with the first billing cycle in November 2000. On December 21,
2000 the PSC issued an order approving SCE&G's request for another out-of-period
adjustment to increase the cost of gas component to 99.340 cents per therm,
effective with the first billing cycle in January 2001. In March 2001 the PSC
approved SCE&G's request to decrease the cost of gas component to 79.340 cents
per therm, effective with the first billing cycle in March 2001.
On July 5, 2000 the PSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and will result in a reduction in annual
depreciation expense of approximately $2.9 million.
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 may 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 may be carried
forward for possible use in the following year. As of December 31, 2000 no
accelerated depreciation has been recorded. 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 12.0 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, ruled that no further rate action was required, and reaffirmed
SCE&G's authorized return on equity of 12.0 percent. The rate reductions were
placed into effect with the first billing cycle of January 1999.
On January 9, 1996 increasingthe 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.
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 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 November 2000, 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 $20.1 million.
In September 1992 the PSC issued an order granting SCE&G's request for 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. In response to
an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May
25, 2000, which remanded the matter to the PSC for review of SCE&G's original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC issued an order granting the relief requested by SCE&G. On
September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay
of this order to which SCE&G filed a response. On October 3, 2000 the PSC
accepted the Consumer Advocate's motion and issued a stay of its order. The
Consumer Advocate and other intervenors have petitioned the Circuit Court for
judicial review of the PSC's order granting relief. Action by the Circuit Court
is pending.
Public Service Company of North Carolina, Incorporated
A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. 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. On June 29, 2000 the NCUC approved PSNC's requests for
reinstatement of its exclusive franchises for Madison, Jackson and Swain
Counties and disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million.
On December 7, 1999 the NCUC issued an order approving the acquisition
of PSNC by the Company. As specified in the NCUC order, PSNC reduced its rates
by approximately $1 million in August 2000, will reduce rates another $1 million
in August 2001 and has agreed to a five-year moratorium on general rate cases.
General rate relief can be obtained during this period to recover costs
associated with materially adverse governmental actions and force majeure
events.
On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County and
authorized disbursements from the fund of approximately $4.3 million based upon
budgeted construction cost of approximately $6.2 million. Most of Alexander
County lies within PSNC's certificated service territory and did not previously
have natural gas service. The project was completed and customers began
receiving natural gas service in March 2000.
On October 30, 1998 the NCUC issued an order in PSNC's general rate case
filed in April 1998. The order, effective November 1, 1998, granted PSNC
additional revenue of $12.4 million and allowed a 9.82 percent overall rate of
return on PSNC's net utility investment. It also approved the continuation of
the Weather Normalization Adjustment and Rider D Mechanisms and full margin
transportation rates. PSNC's Rider D rate mechanism authorizes the recovery of
all prudently incurred gas costs from customers on a monthly basis. Any
difference in amounts paid and collected for these costs is deferred for
subsequent refund to or collection from customers. On February 4, 2000, in
response to an appeal by CUCA, the Supreme Court of North Carolina affirmed the
NCUC order.
On November 6, 1997 the NCUC issued an order permitting PSNC, on a trial
basis, to establish its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas. PSNC's
request for permanent approval of this mechanism was approved by the NCUC via an
order issued April 6, 2000.
The Company's regulated business operations are likely to bewere impacted by the NEPA
and FERC OrderOrders No. 636.636, 888 and 2000. NEPA iswas designed to create a more
competitive wholesale power supply market by creating "exempt wholesale
generators" and by potentially requiring utilities owning transmission
facilities to provide transmission access to wholesalers. Order No. 636 iswas
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. Orders No. 888 and 2000 require 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 to themselves and to submit plans for the possible
formulation of an RTO. In the opinion of the Company, it willcontinues to be able to
meet successfully the challenges of these altered business climates and does not
anticipate there to be any material adverse impact on the results of its operations, itscash flows,
financial position or its business prospects.
26
StatementsOther
At December 31, 2000 SCANA Communications Holdings, Inc. (SCH), a wholly
owned, indirect subsidiary of SCANA, held the following investments in ITC
Holding Company, Inc. (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns and
operates personal communications services (PCS) systems in several
major Southeastern markets. SCH owns approximately 4.9 million common
shares of Powertel at a cost of approximately $77.7 million. Powertel
common stock closed at $61.9375 per share on December 31, 2000,
resulting in a pre-tax unrealized holding gain of $228.8 million (a
decline of $189.0 million from December 31, 1999). Accumulated other
comprehensive income includes the after-tax amount of all unrealized
holding gains and losses on common shares. 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). Cumulative dividends on preferred series E
shares are generally paid in common shares of Powertel and are accrued
quarterly. Preferred series B shares become convertible in March 2002
at a conversion price of $16.50 per common share or approximately 4.6
million common shares. Preferred series D shares become 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
become 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
$606.9 million at December 31, 2000, reflecting an unrecorded pre-tax
holding gain of $434.3 million (a decline of $368.4 million from
December 31, 1999).
OnAugust 28, 2000 SCH announced that under terms of separate definitive
agreements, Powertel has agreed to be acquired by either Deutsche
Telekom AG or VoiceStream Wireless Corporation (VoiceStream). If
Deutsche Telekom's previously announced acquisition of VoiceStream is
successfully completed, then Deutsche Telekom would also acquire
Powertel. If the Deutsche Telekom - VoiceStream transaction is not
completed, then VoiceStream would acquire Powertel. In connection with
these transactions, SCH entered into stockholder agreements with each
of Deutsche Telekom and VoiceStream pursuant to which SCH agreed to
vote its Powertel shares in support of either of these transactions.
In addition, SCH agreed to certain restrictions on disposition of its
Powertel shares and the shares it would receive in either of these
transactions. On March 13, 2001 Powertel shareholders approved the
acquisition agreements.
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 $43.0 million. ITCD common stock closed at
$5.39 per share on December 31, 2000, resulting in a pre-tax
unrealized holding loss of $15.4 million (a decline of $113.7 million
from December 31, 1999). Accumulated other comprehensive income
includes the after-tax amount of all unrealized holding gains and
losses on common shares. 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 become 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 $16.0 million at December
31, 2000, reflecting an unrecorded pre-tax holding gain of $4.8
million (a decline of $65.8 million from December 31, 1999).
o Knology, Inc. (Knology) is a broad-band service provider of cable
television, telephone and internet services. SCH owns $71,050,000 face
amount of 11.875 percent Senior Discount Notes due 2007 of Knology
Broadband, Inc., a wholly-owned subsidiary of Knology. The Senior
Discount Notes have a book basis at December 31, 2000 of approximately
$57.9 million. In addition, SCH owns approximately 7.2 million shares
of Knology Series A Convertible Preferred Stock with a cost basis of
approximately $5.0 million and warrants to purchase approximately 0.2
million shares of Series A Convertible Preferred Stock. On January 12,
2001 SCH invested $25.0 million for approximately 8.3 million shares
of Series C Convertible Preferred Stock of Knology. The market value
of these investments is not readily determinable.
o ITC holds ownership interests in several Southeastern communications
companies, including those discussed above. 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 $5.8 million, $7.2 million, and $4.0
million, respectively. The market values of these investments are not
readily determinable.
In June 1998 the Financial Accounting Standards To Be Adopted
The Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 121,(SFAS) 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 2000, the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." TheFASB issued
SFAS 138, which amends certain provisions of SFAS 133 to expand the Statement, whichnormal
purchase and sale exemption for supply contracts and to redefine interest rate
risk to reduce sources of ineffectiveness, among other things. The Company
utilizes various derivatives in its risk management activities, including swaps
and commodities futures. The Company adopted SFAS 133, as amended, on January 1,
2001. As a result of adopting SFAS 133, the Company recorded a credit of
approximately $23.0 million, net of tax, as the effect of a change in accounting
principle (transition adjustment) to other comprehensive income on January 1,
2001. This amount represents the reclassification of unrealized gains that were
deferred and reported as liabilities at December 31, 2000. In the future, all
gains/losses related to qualifying cash flow hedges deferred in other
comprehensive income will be implementedreclassified to earnings at the time the hedged
transaction affects earnings.
In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition
in Financial Statements" was issued by the Company forSEC, and provides the fiscal year beginning January
1, 1996, require theSEC staff's
views in applying generally accepted accounting principles to selected revenue
recognition issues. The Company's adoption of a lossthis bulletin in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amountfourth
quarter of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will have a material2000 had no impact on its results of operations, cash flows or
financial position.
The Financial Accounting Standards Board issued StatementServiceCare, Inc. has announced the sale of Financial Accounting Standards No. 123, "Accountingits home security business,
expected to be completed in March 2001. SCANA Communications, Inc. has signed a
letter of intent to sell its 800 Mhz radio service network, expected to be
completed in April 2001.
RESULTS OF OPERATIONS
Earnings and Dividends
Earnings per share of common stock and the rate of return earned on common
equity for Stock-
Based Compensation," which will be implemented2000, 1999 and 1998 were as follows:
2000 1999 1998
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Earnings derived from:
Continuing operations $2.12 $1.39 $2.07
Non-recurring gains - .34 .05
Cumulative effect of accounting change,
net of taxes .28 - -
--------------------------------------------------------------------------
Earnings per weighted average share $2.40 $1.73 $2.12
==========================================================================
Return earned on common equity 12.3% 8.5% 12.8%
--------------------------------------------------------------------------
o 2000 vs 1999 Earnings derived from continuing operations increased
$0.73, primarily as a result of improved
results from retail gas marketing ($.04 net earnings for
2000 compared to $.45 loss in 1999) and
the acquisition of PSNC ($.21). In addition, electric
margin improved $.36 (see discussion at
Electric Operations), regulated gas margin (excluding
PSNC) improved $.07 and pension income
increased $.05. These improvements were partially offset
by increased interest expense of $.36, a
charge for repairs at Summer Station ($.04) and other
increases in operations and maintenance ($.05).
o 1999 vs 1998 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 ($.03), the impact of fewer
common shares outstanding ($.03), and other ($.03).
Pension income recorded by the Company on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results ofreduced operations or financial position.
RESULTS OF OPERATIONS
Net Income
Net incomeexpense by
$22.7 million, $17.3 million and the percent increase (decrease) from the
previous year$16.9 million for the years 1995, 1994ended December 31,
2000, 1999 and 19931998, respectively. In addition pension income increased other
income by $12.8 million, $10.5 million and $9.0 million for the years ended
December 31, 2000, 1999 and 1998, respectively. The reductions to operations
expense for 1999 and 1998 were substantially offset by accelerated amortization
of a significant portion of the transition obligation for postretirement
benefits other than pensions and certain regulatory assets as follows:
1995 1994 1993
Netapproved by the
PSC. Effective July 1, 2000 the Company's pension plan was amended to provide a
cash balance formula. The effect of this plan amendment was to reduce net
periodic benefit income $169,185 $152,043 $145,968
Percentfor the year ended December 31, 2000 by approximately
$3.7 million.
Non-recurring gains resulted from the sale of retail propane assets
($.29) and telecommunications towers ($.05) in 1999 and a retroactive change in
electric depreciation rates ($.05) in 1998. In 2000 the cumulative effect of an
accounting change resulted from the recording of unbilled revenues by SCANA's
retail utility subsidiaries (see Note 2 of Notes To Consolidated Financial
Statements).
Return on common equity increased in 2000 primarily due to increased
earnings and decreased common equity due to a $197 million unrealized loss on
the Company's investment in telecommunications securities during the year.
Increased earnings related to the cumulative effect of accounting change
increased the return on common equity by 1.4 percent in 2000. In addition, the
$197 million unrealized loss on the Company's investments in telecommunications
securities increased the return on common equity by 1.1 percent in 2000. Return
on common equity decreased in 1999 due to decreased earnings and a $311 million
unrealized gain on the Company's investments in telecommunications securities.
The increase (decrease)in common equity, without a proportional increase in net income,
11.27% 4.16% 42.9%
1995 Net income increased fordecreased the year primarily due to
increasesreturn earned on common equity by 1.6 percent in electric and gas margins and lower operating
and maintenance expenses which more than offset increases
in fixed costs.
1994 Net income increased for the year primarily due to an
increase in the electric margin which more than
offset increases in operating expenses.1999.
The Company's financial statements include an allowance for
funds used during construction (AFC).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 7.9 %2.3 percent of
income before income taxes in 1995, 6.3%2000, 2.4 percent in 19941999 and 5.6%4.4 percent in 1993.
27
1998.
On February 22, 2000 the Board of Directors set the Company's indicated
annual dividend rate on common stock at $1.15 per share.
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G,
GENCO and Fuel Company. Electric operations sales margins, including
transactions with affiliates and excluding the cumulative effect of accounting
change, for 1995, 19942000, 1999 and 19931998 were as follows:
1995 1994 1993
(MillionsMillions of Dollars)
Electricdollars 2000 1999 1998
- ---------------------------------------------- ------------- ---------------
Operating revenues $1,006.6 $974.3 $940.2
(Provision) for rate refunds - 1.2 0.3
Net Electric operating revenues 1,006.6 975.5 940.5$1,343.8 $1,226.0 $1,219.8
Less: Fuel used in electric generation 177.6 176.6 164.2(294.9) (284.6) (262.3)
Purchased power 98.2 112.9 111.1(82.5) (35.9) (31.5)
- ------------------------------------------- ---------------- ---------------
Margin $ 730.8 $686.0 $665.2
1995 The electric sales$966.4 $905.5 $926.0
=========================================== ================ ===============
o 2000 vs 1999 Sales margin increased overprimarily due to more favorable
weather and customer growth, which were
partially offset by higher purchased power costs.
o 1999 vs 1998 Sales margin decreased primarily due to the prior
year primarily as a result of the combined impact of
warmer weather in the third quarter of 1995, colder
weather in the fourth quarter of 1995 and the base rate
increase received by the Company in mid-1994. These
factors more than offset the negative impact of milder
weather experienced during the first half of 1995. An
increase of 7,943 electric customers to 484,381 total
customers contributed to an all-time peak demand record of
3,683 MW set on August 14, 1995.
1994 The electric sales margin increased over the prior
year primarily as a result of an increase in retail
electric rates phased in over a two-year period beginning
in June 1993 and an increase in industrial sales which
more than offset the negative impact of a
six percent
decrease in residential sales of electricity due torate reduction at SCE&G and milder weather,
in 1994.which were partially offset by customer growth.
Increases (decreases) from the prior year in megawatt hourmegawatt-hour (MWH) sales
volume by classes, excluding volumes attributable to the cumulative effect of
accounting change, were as follows:
Classification 1995 19942000 % Change 1999 % Change
- ------------------------------------------- ----------- -----------------------
Residential 415,676 (339,620)396,179 6.3% (55,207) (0.9%)
Commercial 229,565 4,198354,350 6.0% 51,212 0.9%
Industrial 48,651 274,467
Sale524,969 8.5% 316,087 5.4%
Sales for Resale (excluding
interchange) 38,688 18,40833,505 2.8% 63,306 5.6%
Other 12,776 (6,907)34,676 6.7% (17,652) (3.3%)
---------- -------
- -------------------------------
Total territorial 745,356 (49,454)
Interchange 24,545 (27,013)1,343,679 6.7% 357,746 1.8%
Negotiated Market Sales Tariff 264,257 15.7% 183,442 12.3%
-- ------- -------
- -------------------------------
Total 769,901 (76,467)1,607,936 7.4% 541,188 2.6%
=========================================== =========== =======================
o 2000 vs 1999 Sales volume increased primarily due to more favorable
weather and customer growth.
o 1999 vs 1998 Sales volume decreased for residential primarily due to
milder weather, which was partially offset by
customer growth. Volumes for the remaining classes
increased primarily due to customer growth.
Gas OperationsDistribution
Gas Distribution is comprised of the local distribution operations of
SCE&G and PSNC. Gas distribution sales margins, including transactions with
affiliates and excluding the cumulative effect of accounting change, for 1995, 19942000,
1999 and 19931998 were as follows:
1995 1994 1993
(MillionsMillions of Dollars)
Gas operatingdollars 2000 1999 1998
- ----------------------------------------------- ------------- -------------
Operating revenues $200.6 $201.7 $174.0$745.9 $239.0 $230.4
Less: Gas purchased for resale 125.0 127.8 107.7(486.3) (152.6) (142.4)
- ----------------------------------------------- ------------- -------------
Margin $ 75.6 $ 73.9 $ 66.3
1995 The gas$259.6 $86.4 $88.0
=============================================== ============= =============
SCANA acquired PSNC effective January 1, 2000. Therefore the Company's prior
year sales do not include PSNC.
o 2000 vs 1999 Sales margin increased overprimarily due to the prior yearacquisition of
PSNC, which contributed $161.5 million,
and improved margin at SCE&G due primarily to more
favorable weather.
o 1999 vs 1998 Sales margin decreased primarily as a result of increases in interruptiblehigher
gas sales.
1994 The gas sales margin increased over the prior year
primarily as a result of increases in interruptible
gas sales.
28
costs.
Increases (decreases) from the prior year in dekatherm (DT) sales volume
by classes, including transportation gas and excluding volumes attributable to
the cumulative effect of accounting change were as follows:
Classification 1995 19942000 % Change 1999 % Change
- ----------------------------------- -------------- -------------- -------------
Residential 802,211 (477,886)23,541,979 199.1% (94,027) (0.8%)
Commercial 623,533 970,72613,227,028 113.1% 404,654 3.6%
Industrial 2,528,974 5,057,4044,478,371 24.9% 644,485 3.7%
Transportation gas (1,866,414) (1,524,089)29,482,223 1,492.8% (28,732) (1.4%)
Sales for resale 407 - - -
------------- -------------
- ---------------------
Total 2,088,304 4,026,155
Other Operating Expenses70,730,008 162.8% 926,380 2.2%
=================================== ============== ============== =============
o 2000 vs 1999 Sales volume increased primarily as a result of the
acquisition of PSNC, which accounted for 65.2
million DTs. SCE&G's sales volume increased approximately
2.0 million DTs due to colder weather and
Taxes
Increases (decreases) in other operating expenses,customer growth, which were partially offset by
curtailments and use of alternate fuels by
industrial customers.
o 1999 vs 1998 Sales volume increased primarily as a result of customer
growth. Residential volume decreased primarily due to
milder weather.
Gas Transmission
Gas Transmission is comprised of Pipeline Corporation. Gas transmission
sales margins for 2000, 1999 and 1998, including taxes,transactions with affiliates,
were as follows:
Classification 1995 1994
(MillionsMillions of Dollars)
Other operationdollars 2000 1999 1998
- -------------------------------------------- -------------- -------------
Operating revenues $489.0 $342.4 $329.8
Less: Gas purchased for resale (434.7) (295.1) (276.7)
- -------------------------------------------- -------------- -------------
Margin $54.3 $47.3 $53.1
============================================ ============== =============
o 2000 vs 1999 Sales margin increased primarily as a result
of increased contract and maintenance $(7.8) $ 3.9
Depreciationsales volumes from the sale for
resale classification and amortization 10.6 5.7
Income taxes 12.9 2.8
Other taxes 5.1 5.0
Total $20.8 $17.4
1995 Other operation and maintenance expensesmargin earned from the
competitive industrial customers.
o 1999 vs 1998 Sales margin decreased primarily as a result of lower pension costsincreased
competition with oil prices and lower costs
ata decrease
in the value of released capacity on the intrastate
pipeline system.
Increases (decreases) from the prior year in dekatherms (DT) sales volume
by classes including transportation were as follows:
Classification 2000 % Change 1999 % Change
----------------------------------- ---------------------------------------
Commercial 22,132 24.2% 200 0.2%
Industrial (5,212,904) (11.7%) (916,235) (2.0%)
Transportation 10,296 0.5% (179,029) (7.4%)
Sales for resale 3,542,185 6.0% 2,122,252 3.8%
=================================== ===========
Total (1,638,291) (1.6%) 1,027,188 1.0%
=================================== =======================================
o 2000 vs 1999 Sales for resale volumes increased as a result of colder
temperatures. The sales volume for industrial customers
decreased due to decreased sales to electric generating stations. The increasegeneration
facilities and decreased sales to other customers with
alternate fuel sources.
o 1999 vs 1998 Sales volumes for sales for resale customers increased for
1999 as a result of customer growth and customer expansion
on our sale for resale customers' systems. Transportation
and industrial volumes decreased due to increased
competition with oil prices.
Retail Gas Marketing
Retail Gas Marketing is comprised of SCANA Energy, a division of SCANA
Energy Marketing, Inc., which operates in depreciationGeorgia's deregulated natural gas
market. Retail gas marketing revenues and amortization expense primarily is
attributable to additions to plant-in-servicenet income for 2000, 1999 and the
expensing1998
were as follows:
Millions of software costs. The increase indollars 2000 1999 1998
-------------------------------------- --------------- ----------------
Operating revenues $547.3 $206.6 $3.5
Net income tax
expense corresponds to(loss) 4.4 (44.8) (7.9)
-------------------------------------- --------------- ----------------
o 2000 vs 1999Operating revenues increased as a result of
customer growth, favorable weather and a successful gas
supply and pricing strategy. Net income increased as a
result of the increase in revenue and significant
reductions in customer acquisition and advertising
expenditures.
o 1999 vs 1998 Operating revenues increased as a result of a full year of
operations being reflected in 1999's results. Net loss
increased as a result of large expenditures for marketing
and advertising reflected in 1999's results.
Delivered volumes for 2000, 1999 and 1998 totaled approximately 73.8
million, 40.9 million and 0.5 million DT, respectively, which includes
interruptible volumes of approximately 30.6 million, 18.9 million and 0.0
million DT for the same periods, respectively. The increases in volumes resulted
from customer growth.
Energy Marketing
Energy Marketing is comprised of the Company's non-regulated marketing
operations, excluding SCANA Energy. Energy marketing operating income.revenues and net
losses for 2000, 1999 and 1998 were as follows:
Millions of dollars 2000 1999 1998
------------------------------------------ --------------- ----------------
Operating revenues $543.3 $223.3 $564.6
Net loss (4.2) (3.9) (6.6)
------------------------------------------ --------------- ----------------
o 2000 vs 1999Operating revenues increased primarily due to increased prices
for natural gas. Net loss increased primarily due to increased bad debts.
o 1999 vs 1998Operating revenues and net loss decreased
primarily due to the closing of the Houston office.
Delivered volumes for 2000, 1999 and 1998 totaled approximately 83.9
million, 103.7 million and 218.5 million DT, respectively. The increasedecreases in
volumes resulted from the closing of the Houston office.
Other Operating Expenses
Increases in other taxes reflects higher property taxes
resulting from higher millages and assessments partially
offset by lower payroll taxes resulting from early
retirementsoperating expenses were as follows:
(Millions of employees.
1994dollars) 2000 % Change 1999 % Change
- ----------------------------------------- --------------------------------------
Other operation and maintenance $66.1 16.1% $60.4 17.2%
Depreciation and amortization 47.4 28.1% 24.3 16.8%
Other taxes 10.6 10.3% 1.9 1.8%
========================================= =============
Total $124.1 18.2% $86.6 14.5%
========================================= ======================================
o 2000 vs 1999 Other operating expenses and taxes increased primarily as a
result of the acquisition of PSNC. This acquisition
accounted for the following increases: other operation and
maintenance ($67.5 million), depreciation and amortization
($41.9 million, of which $13.4 million is attributable to
the amortization of the acquisition adjustment), and other
taxes ($6.4 million).
Apart from the PSNC acquisition, other operation and
maintenance expense decreased $1.4 million due to pension
income (see Earnings and Dividends), which was partially
offset by increased maintenance costs for electric
generating and distribution facilities. Depreciation and
amortization increased $5.5 million primarily due to
normal increases in utility plant. Other taxes increased
$4.2 million primarily due to increased property taxes.
o 1999 vs 1998 Other operation and maintenance increased primarily due to
costs associated with a cogeneration facility becoming
operational, costs associated with an increase in the costs of postretirement
benefitsearly retirement
program and other than pensions.operating costs. These costs are accruedwere
partially offset by pension income, which in accordance with Financial Accounting Standards Board
Statement No. 106. (See Note 1K1998 had been
offset by the accelerated amortization of Notes to Consolidated
Financial Statements.) The increase in depreciationthe electric
portion of the Company's transition obligation expense for
post-retirement benefits and other regulatory assets.
Depreciation and amortization expenses is attributableincreased primarily due to
property additionsthe 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 depreciation rates. The increaseutility plant. Other taxes
increased primarily due to increased property taxes.
Other Income
Other income decreased approximately $46.6 million for the year 2000
compared to 1999, primarily as a result of 1999 including the sale of
nonregulated propane assets and telecommunications towers, which was partially
offset by other income at PSNC in other taxes reflects an increase in property taxes2000. Other income increased approximately
$71.1 million for the year 1999 compared to 1998, primarily as a result of approximately $5 million.the
sale of assets discussed previously and pension income.
Interest Expense
Increases (decreases) in interest expense were as follows:
Classification 1995 1994
(Millions of Dollars)
Interest on long-term debt, net $11.0 $8.0
Other interest expense 4.1 (.6)
Total $15.1 $7.4
1995 The increase in interest expense, excluding the debt component of AFC, were
as follows:
(Millions of dollars) 2000 1999
----------------------------------------------- --------------------
Interest on long-term debt, net $73.8 $11.4
Other interest expense 10.6 3.9
----------------------------------------------- --------------------
Total $84.4 $15.3
=============================================== ====================
o 2000 vs 1999Interest expense increased primarily as a
result of financing the acquisition of PSNC and related
repurchase of SCANA shares ($46.0 million) and interest
incurred on PSNC debt that was assumed as a result of the
acquisition ($19.6 million). In addition, interest expense
increased as a result of increased borrowings and
increased weighted average interest rates on long-term and
short-term borrowings.
o 1999 vs 1998Interest expense increased as a result of
increased long-term debt and increased weighted average
interest rates on long-term and short-term borrowings.
Income Taxes
Income taxes increased approximately $29.7 million for the year 2000
compared to 1999 and decreased approximately $19.8 million for the year 1999
compared to 1998. Changes in income taxes are primarily due to changes in
operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by the Company described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about the
Company's financial instruments that are sensitive to changes in interest rates.
For debt obligations the table presents principal cash flows and related
weighted average interest rates by expected maturity dates.
December 31, 2000 Expected Maturity Date
(Millions of dollars)
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value
-------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- --------------
Long-Term Debt:
Fixed Rate ($)(1) 40.9 337.3 297.2 186.3 182.0 1,267.4 2,311.1 2,232.2
Average Fixed Interest Rate 7.27% 7.36% 6.38% 7.58% 7.43% 7.35% 7.25%
Variable Rate ($) - 550.0 150.0 - - - 700.0 699.7
Average Variable Interest
Rate - 7.26% 7.48% - - - 7.31%
December 31, 1999 Expected Maturity Date
(Millions of dollars)
Liabilities 2000 2001 2002 2003 2004 Thereafter Total Fair Value
-------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- --------------
Long-Term Debt:
Fixed Rate ($) (1) 152.5 32.5 32.5 289.3 178.8 1,150.5 1,836.1 1,680.7
Average Fixed Interest Rate 6.20% 6.85% 6.85% 6.17% 7.50% 7.33% 7.05%
Variable Rate ($) 150.0 - - - - - 150.0 150.0
Average Variable Interest
Rate 6.45% - - - - - -
(1) At December 31, 1999 there were no debt issuances outstanding under the
$300 million credit agreement. At December 31, 2000 the entire $300 million was
outstanding.
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 primarily2007. 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 effect, 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, 2000 Expected Maturity in
2001
(Millions of dollars) Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- ---------------------------------------------------- ------------- -------------
Future Contracts:
Long $6.5870 $57.2 $81.5
Short $6.2957 $1.4 $2.1
SET Futures Contracts (1):
Long $6.5239 $2.8 $4.4
Short - - -
December 31, 1999 Expected Maturity in
2000
(Millions of dollars) Weighted Avg Contract Fair
Natural Gas Derivatives: Settlement Price Amount Value
- ----------------------------------------------------- ------------ -------------
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
(1) SCANA Energy Trading, LLC (SET) is a 70 percent owned subsidiary of
SCANA Energy Marketing, Inc. Amounts shown are
at 100 percent.
Equity price risk - Certain investments in telecommunications companies'
marketable equity securities are carried at their market value of $597.8
million. A ten percent decline in market value would result in a $59.8 million
reduction in fair value and a corresponding adjustment, net of tax effect, to
the issuance of
additional debt including commercial paper during the latter
part of 1994 and early 1995.
1994 The increase in interest expense, excluding the debtrelated equity account for unrealized gains/losses, a component of AFC, is primarily attributable to the issuance of
$100 million of First Mortgage Bonds in July and $30 million
of Pollution Control Facilities Revenue Bonds in November,
both to finance utility construction, and to the issuance of
long-term debt during 1993.
29
other
comprehensive income.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TOTABLE OF CONTENTS OF CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA
Page
Independent Auditors' Report....................................... 31Report............................................. 43
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 19952000 and 1994... 321999............. 44
Consolidated Statements of Income and Retained Earnings
for the years endedYears Ended December 31, 1995, 19942000, 1999 and 1993............. 341998................ 46
Consolidated Statements of Cash Flows for the years endedYears Ended
December 31, 1995, 19942000, 1999 and 1993............................. 351998.................................... 47
Consolidated Statements of Capitalization as of
December 31, 19952000 and 1994................................... 361999.......................................... 48
Consolidated Statements of Changes in Common Equity for the Years
Ended December 31, 2000, 1999 and 1998............................... 52
Notes to Consolidated Financial Statements..................... 38
Supplemental financial statement schedules are omitted because of the
absence of conditions under which they are required or because the required
information is included in the consolidated financial statements or in the
notes thereto.
30Statements............................... 53
INDEPENDENT AUDITOR'SAUDITORS' REPORT
South Carolina Electric & Gas Company:SCANA Corporation:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of South Carolina Electric & Gas
CompanySCANA Corporation (Company) as of December 31, 19952000 and 19941999
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, 1995.2000. Our audits also include 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 thethese financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
auditing standards.in the United States of America. 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, 19952000
and 19941999 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 19952000 in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial 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.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting principles.for operating
revenues associated with its regulated utility operations.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 1996
312001 (February 16, 2001 as to Note 15)
SOUTH CAROLINA ELECTRIC & GAS COMPANYSCANA Corporation
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------- ------------------- ---------------------
December 31, 1995 1994
(Thousands(Millions of Dollars)
ASSETSdollars) 2000 1999
- ----------------------------------------------------------------------------- ------------------- ---------------------
Assets
Utility Plant (Notes 1 3 and 4)& 6):
Electric $3,277,530 $3,165,391$4,747 $4,633
Gas 320,847 307,929
Transit 3,768 3,785
Common 91,616 77,3271,435 632
Other 187 191
- ----------------------------------------------------------------------------- ------------------- ---------------------
Total 3,693,761 3,554,4326,369 5,456
Less accumulated depreciation and amortization 1,196,279 1,171,7582,212 1,829
- ----------------------------------------------------------------------------- ------------------- ---------------------
Total 2,497,482 2,382,6744,157 3,627
Construction work in progress 613,683 571,867261 159
Nuclear fuel, net of accumulated amortization 46,492 43,59157 43
Acquisition adjustment-gas, net of accumulated amortization (Note 3) 474 22
- ----------------------------------------------------------------------------- ------------------- ---------------------
Utility Plant, Net 3,157,657 2,998,1324,949 3,851
- ----------------------------------------------------------------------------- ------------------- ---------------------
Nonutility Property, net of accumulated depreciation 79 61
Investments (Note 12) 203 938
- ----------------------------------------------------------------------------- ------------------- ---------------------
Nonutility Property and Investments, net of accumulated depreciation (Note 8) 11,603 11,931282 999
- ----------------------------------------------------------------------------- ------------------- ---------------------
Current Assets:
Cash and temporary cash investments (Note 8) 6,798 346(Notes 1 & 12) 159 116
Receivables - customer(net of provision for uncollectible
accounts of $31 million in 2000 and other 154,816 127,679
Receivables - affiliated companies (Note 1) 7,132 18,121$7 million in 1999) 699 318
Inventories (At average cost) (Note 7):
Fuel (Notes 1, 3 and 4) 35,812 31,310107 82
Materials and supplies 43,583 43,22856 51
Emission allowances 20 17
Prepayments 10,158 14,389
Accumulated deferred16 18
Investments (Note 12) 479 -
Deferred income taxes, 19,420 17,931net (Notes 1 & 11) - 16
- ----------------------------------------------------------------------------- ------------------- ---------------------
Total Current Assets 277,719 253,0041,536 618
- ----------------------------------------------------------------------------- ------------------- ---------------------
Deferred Debits:
Emission allowances 28,514 19,409
Unamortized debt expense 11,445 11,690
Unamortized deferred return on plant investment (Notes 1 and 2) 6,369 10,6143 14
Environmental 30 24
Nuclear plant decommissioning fund (Note 1) 36,070 30,38372 64
Pension asset, net (Note 5) 196 144
Other regulatory assets (Note 1) 273,056 251,928213 175
Other 139 122
- ----------------------------------------------------------------------------- ------------------- ---------------------
Total Deferred Debits 355,454 324,024653 543
- ----------------------------------------------------------------------------- ------------------- ---------------------
Total $3,802,433 $3,587,091
32$7,420 $6,011
============================================================================= =================== =====================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS169
----------------------------------------------------------------------- --------------------- ---------------------
December 31, (Millions of dollars) 2000 1999
----------------------------------------------------------------------- --------------------- ---------------------
Capitalization and Liabilities
Stockholders' Investment:
December 31, 1995 1994
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Stockholders' Investment:
Common equityEquity (Note 5) $1,315,072 $1,133,4329) $2,032 $2,099
Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027(Note
10) 106 106
----------------------------------------------------------------------- --------------------- ---------------------
Total Stockholders' Investment 1,341,099 1,159,4592,138 2,205
Preferred Stock, Netnet (Subject to purchase or sinking funds)(Notes 6 and 8) 46,243 49,528 10 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 10) 50 50
Long-Term Debt, Netnet (Notes 3, 4 and 8) 1,279,379 1,231,1916 & 12) 2,850 1,563
----------------------------------------------------------------------- --------------------- ---------------------
Total Capitalization 2,666,721 2,440,1785,048 3,829
----------------------------------------------------------------------- --------------------- ---------------------
Current Liabilities:
Short-term borrowings (Notes 7, 8 and 9) 80,500 100,000
Notes payable - affiliated companies - 19,409& 12) 398 266
Current portion of long-term debt (Note 3) 36,033 33,042
Current portion of preferred stock (Note 6) 2,439 2,41841 303
Accounts payable 71,731 61,466
Accounts payable - affiliated companies396 189
Customer deposits 25 16
Taxes accrued 54 86
Interest accrued 42 29
Dividends declared 32 31
Deferred income taxes, net (Notes 1 and 3) 26,212 33,357
Customer deposits 12,518 12,668
Taxes accrued 64,008 46,646
Interest accrued 21,626 21,534
Dividends declared 33,126 28,489& 11) 98 -
Other 12,507 15,52525 13
----------------------------------------------------------------------- --------------------- ---------------------
Total Current Liabilities 360,700 374,5541,111 933
----------------------------------------------------------------------- --------------------- ---------------------
Deferred Credits:
Accumulated deferredDeferred income taxes, net (Notes 1 and 7) 488,310 503,723
Accumulated deferred& 11) 721 805
Deferred investment tax credits (Notes 1 and 7) 78,316 81,546
Accumulated reserve& 11) 119 116
Reserve for nuclear plant decommissioning (Note 1) 36,070 30,38372 64
Postretirement benefits (Note 5) 113 98
Other regulatory liabilities 75 64
Other (Note 1) 172,316 156,707161 102
----------------------------------------------------------------------- --------------------- ---------------------
Total Deferred Credits 775,012 772,3591,261 1,249
----------------------------------------------------------------------- --------------------- ---------------------
Commitments and Contingencies (Note 10)13) - -
----------------------------------------------------------------------- --------------------- ---------------------
Total $3,802,433 $3,587,091$7,420 $6,011
======================================================================= ===================== =====================
See Notes to Consolidated Financial Statements.
33
SOUTH CAROLINA ELECTRIC & GAS COMPANYSCANA Corporation
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
- -------------------------------------------------------------------------- ---------------- --------------- -------------- --
For the Years Ended December 31, 1995 1994 1993
(Thousands2000 1999 1998
- -------------------------------------------------------------------------- ---------------- --------------- -------------- --
(Millions of Dollars)Dollars, except per share amounts)
Operating Revenues (Notes 1, and 2)2 & 4):
Electric $1,006,566 $ 975,526 $ 940,547$1,344 $1,226 $1,220
Gas 200,632 201,746 174,035
Transit 3,889 4,002 3,851- Regulated 998 422 411
Gas - Nonregulated 1,091 430 475
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Total Operating Revenues 1,211,087 1,181,274 1,118,4333,433 2,078 2,106
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Operating Expenses:
Fuel used in electric generation 177,579 176,581 164,187295 285 262
Purchased power (including affiliated
purchases)(Note 1) 98,231 112,900 111,11182 36 31
Gas purchased from affiliate for resale 1,694 721 746
Other operation and maintenance (Note 1) 125,032 127,846 107,722
Other operation 211,318 214,344 207,126
Maintenance 53,071 57,801 61,107477 411 351
Depreciation and amortization (Note 1) 117,584 106,952 101,220
Income taxes (Notes 1 and 7) 96,956 84,066 81,280217 169 145
Other taxes (Note 12) 75,462 70,366 65,361114 103 101
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Total Operating Expenses 955,233 950,856 899,1142,879 1,725 1,636
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Operating Income 255,854 230,418 219,319554 353 470
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Other Income (Note 1):
AllowanceIncome:
Other income, including allowance for equity funds
used during construction 9,499 7,989 7,496
Other income (loss), net(Note 1) 41 22 19
Gain on sale of income taxes 54 (718) (911)subsidiary assets 3 68 -
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Total Other Income 9,553 7,271 6,58544 90 19
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Interest Charges, 265,407 237,689 225,904Income Taxes, Preferred Stock
Dividends and Cumulative Effect of Accounting Change 598 443 489
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Interest Charges (Credits):Charges:
Interest expense on long-term debt, net 98,361 87,361 79,410206 132 121
Other interest expense, (Notes 1 and 3) 9,324 5,189 5,812
Allowancenet of allowance for borrowed funds
used during construction (Note 1) (11,463) (6,904) (5,286)19 10 2
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Total Interest Charges, Net 96,222 85,646 79,936
Net225 142 123
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Income 169,185 152,043 145,968Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 373 301 366
Income Taxes (Note 11) 141 111 131
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 232 190 235
Preferred Dividend Requirement of SCE&G - Obligated Mandatorily
Redeemable Preferred Securities 4 4 4
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Cash Dividends on Preferred Stock of Subsidiary
and Cumulative Effect of Accounting Change 228 186 231
Cash Dividends on Preferred Stock of Subsidiary (At stated rates) (5,687) (5,955) (6,217)
Earnings Available for Common Stock 163,498 146,088 139,7517 7 8
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Income Before Cumulative Effect of Accounting Change 221 179 223
Cumulative Effect of Accounting Change, net of taxes (Note 2) 29 - -
- -------------------------------------------------------------------------- ---------------- --------------- ----------------
Net Income 250 179 223
Retained Earnings at Beginning of Year 324,101 291,713 262,262720 678 617
Common Stock Cash Dividends Declared (Note 5) (121,363) (113,700) (110,300)(120) (137) (162)
========================================================================== ================ =============== ================
Retained Earnings at End of Year $ 366,236 $ 324,101 $ 291,713$850 $720 $678
========================================================================== ================ =============== ================
Basic and Diluted Earnings Per Share of Common Stock:
Before Cumulative Effect of Accounting Change $2.12 $1.73 $2.12
Cumulative Effect of Accounting Change, net of taxes (Note 2) .28 - -
========================================================================== ================ =============== ================
Basic and diluted earnings per share $2.40 $1.73 $2.12
========================================================================== ================ =============== ================
Weighted average shares outstanding (millions) 104.5 103.6 105.3
========================================================================== ================ =============== ================
See Notes to Consolidated Financial Statements.
34
SOUTH CAROLINA ELECTRIC & GAS COMPANYSCANA Corporation
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993
(Thousands(Millions of Dollars)dollars) 2000 1999 1998
- ------------------------------------------------------------------------------ -------------- ------------ ------------
Cash Flows From Operating Activities:
Net income $169,185 $152,043 $145,968$250 $179 $223
Adjustments to reconcile net income to net cash provided from operating
activities:
Cumulative effect of accounting change, net of taxes (29) - -
Depreciation and amortization 117,839 107,103 101,370227 177 152
Amortization of nuclear fuel 20,017 13,487 18,156
Deferred income taxes, net (17,632) 13,133 56,982
Deferred investment tax credits, net (3,230) (2,901) (3,245)
Net regulatory asset arising from adoption16 18 20
Gain on sale of SFAS No. 109 13,560 (1,985) (40,398)subsidiary assets (3) (68) -
Equity in losses of affiliates 3 1 -
Preferred stock dividends 7 7 8
Allowance for funds used during construction (20,962) (14,893) (12,782)
Unamortized loss on reacquired debt (3,325) (129) (17,094)
Early retirements (24,823) (7,086) (11,840)
Nuclear refueling accrual 6,957 (4,881) (6,086)(9) (7) (16)
Over (under) collections,collection, fuel adjustment clause 18,986 (17,965) (13,728)
Emission allowances (9,105) (19,409) -clauses (33) (6) 1
Changes in certain current assets and liabilities:
(Increase) decreaseIncrease in receivables (16,148) (26,260) (27,920)(263) (42) (28)
Increase in deferred income taxes, net 61 19 15
Increase in pension asset (43) (29) (33)
Increase in postretirement benefits 15 11 26
Decrease in other regulatory assets 4 19 16
Increase (decrease) in other regulatory liabilities 11 (7) 4
(Increase) decrease in inventories (4,857) 26 1,4013 (14) (16)
Increase (decrease) in accounts payable 3,120 (430) 16,757
Increase (decrease) in estimated rate
refunds and related interest - (2,509) (15,302)157 (30) 88
Increase (decrease) in taxes accrued 17,362 6,681 (11,162)
Increase (decrease) in interest accrued 92 3,770 (8,669)(55) 14 13
Other, net (14,623) 14,106 8,00272 (17) (6)
- ------------------------------------------------------------------------------ -------------- ------------ ------------
Net Cash Provided From Operating Activities 252,413 211,901 180,410391 225 467
- ------------------------------------------------------------------------------ -------------- ------------ ------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of AFC (271,804) (406,054) (287,838)
Nonutility(334) (238) (281)
Purchase of subsidiary, net of cash acquired (212) - -
Proceeds on sale of subsidiary assets 8 112 -
Increase in nonutility property and investments, (111) (287) (248)
Transfer of assets from SCANAnet:
Nonutility property (27) (23) (22)
Investments (20) (74) (106)
- 6,285 ------------------------------------------------------------------------------- -------------- ------------ ------------
Net Cash Used For Investing Activities (271,915) (400,056) (288,086)(585) (223) (409)
- ------------------------------------------------------------------------------ -------------- ------------ ------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of notes payable - affiliated company - 19,409First Mortgage Bonds 148 99 -
Issuance of mortgagenotes and loans 998 200 249
Repayments and repurchases:
Mortgage bonds 99,583 99,207 592,884
Issuance of pollution control bonds - 30,000 -
Equity contributions from parent 139,505 43,426 58,142(100) (10) (50)
Notes and loans (175) (77) (96)
Other long-term debt 2,543 11,200 2,562
Repayments:
Notes payable(8) (10) - affiliated company (19,409) - -
Mortgage bonds (64,779) - (430,000)
Other long-term debt (12,548) (1,662) (405)
Preferred stock (3,264) (3,398) (3,295)
Dividend Payments:(1) - (1)
Common stock (116,663) (115,100) (108,641)(488) - (110)
Dividend payments:
Common Stock (124) (148) (162)
Preferred stock (5,750) (6,048) (6,247)(7) (7) (8)
Short-term borrowings, net (19,500) 98,989 978(6) 71 136
Fuel and emission allowance financings, net 26,236 13,844 (18,948)
Advances - affiliated companies, net(66) (14)
- (1,559) (3,463)------------------------------------------------------------------------------ -------------- ------------ ------------
Net Cash Provided From (Used For) Financing Activities 25,954 188,308 83,567237 52 (56)
- ------------------------------------------------------------------------------ -------------- ------------ ------------
Net Increase (Decrease) in Cash and Temporary Cash Investments 6,452 153 (24,109)43 54 2
Cash and Temporary Cash Investments, January 1 346 193 24,302116 62 60
============================================================================== ============== ============ ============
Cash and Temporary Cash Investments, December 31 $159 $116 $ 6,798 $ 346 $ 19362
============================================================================== ============== ============ ============
Supplemental Cash FlowsFlow Information:
Cash paid for - Interest (includes(net of capitalized interest of $11,463, $6,904$6, $4 and $5,286) $105,537 $ 87,255 $ 92,367$7) $207 $138 $120
- Income taxes 95,827 77,295 79,612139 84 114
Noncash Investing and Financing Activities:
DepartmentUnrealized gain (loss) on securities available for sale, net of Energy decontamination and decommissioning
fund obligation - - 4,965tax (197) 311 7
In conjunction with the acquisition of Public Service Company of North Carolina, Incorporated, liabilities were
assumed as follows:
Fair value of assets acquired $1,177
Cash paid for capital stock (212)
Stock issued as consideration (488)
---------
Liabilities assumed $477
See Notes to Consolidated Financial Statements.
35
SOUTH CAROLINA ELECTRIC & GAS COMPANYSCANA Corporation
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
December 31, 1995 1994(Millions of dollars) 2000 1999
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
Common Equity (Note 5)9):
(Thousands of Dollars)
Common Stock, $4.50stock, without par value, authorized 50,000,000150,000,000 shares; issued and
outstanding,
40,296,147
104,729,131 shares $ 181,333 $181,333
Premiumin 2000 and 103,572,623 shares in 1999 $1,043 $1,043
Unrealized gain on common stock 395,072 395,072
Other paid-in capital 377,822 238,369
Capital stock expense (5,391) (5,443)securities available for sale, net of taxes 139 336
Retained earnings 366,236 324,101850 720
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Common Equity 1,315,072 49% 1,133,432 47%2,032 40% 2,099 55%
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Not subject to purchase or sinking funds):
$100 Par Value - Authorized 200,0001,200,000 shares
$50 Par Value - Authorized 125,209 shares
Shares
Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum2000 1999
------ ---- ----
$100
Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,7676.52% 1,000,000 1,000,000 100.00 100 100
$50
Par 5.00% 125,209 125,209 52.50 6 6
- 52.50 6,260 6,260--------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1%(Note 10) 106 2% 106 3%
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
South Carolina Electric & Gas Company:
Cumulative Preferred Stock (Subject to purchase orand sinking funds)(Notes 6 and 8):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 2000
and 1999 $50 Par Value - Authorized 1,560,287 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
7.70% 86,965 89,984 101.00 - 101.00 8,696 8,998
8.12% 123,045 126,835 102.03 - 102.03 12,305 12,6842000 1999
------ ---- ----
4.50% 9,600 11,200 51.00 1 1
4.60% (A) 16,052 18,052 51.00 1 1
4.60%
(B) 57,800 61,200 50.50 3 3
5.125% 67,000 68,000 51.00 3 3
6.00% 69,835 73,035 50.50 3 4
--------- ------------
Total 210,010 216,819
$50 Par Value - Authorized 1,614,405 shares
Shares Outstanding Redemption Price
Eventual
Series 1995 1994 Current Through Minimum
4.50% 17,519 19,088 51.00 - 51.00 876 954
4.60% 834 2,334 50.50 - 50.50 42 117
4.60%(A) 26,052 28,052 51.00 - 51.00 1,303 1,403
4.60%(B) 74,800 78,200 50.50 - 50.50 3,740 3,910
5.125% 72,000 73,000 51.00 - 51.00 3,600 3,650
6.00% 83,200 86,400 50.50 - 50.50 4,160 4,320
8.72% 95,985 127,956 51.00 12-31-98 50.00 4,799 6,398
9.40% 183,219 190,245 51.175 - 51.175 9,161 9,512
Total 553,609 605,275220,287 231,487
========= ============
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 19952000 and 19941999
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock (Subject to purchase or sinking funds) 48,682 51,94611 12
Less: Current portion, including sinking fund requirements 2,439 2,418(1) (1)
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock, Net (Subject to purchase or sinking funds) 46,243 (Notes 10 & 12) 10 -% 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 (Note 10) 50 1% 50 1%
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
-------------------------------------------------------------------- -- -------------- -------- -------------- -----------
December 31, (Millions of dollars) 2000 1999
-------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Long-Term Debt (Notes 6 & 12)
SCANA Corporation:
Medium-Term Notes: Series Year of Maturity
5.52% 2000 - 150
6.15% 2000 - 20
7.45% 2002 300 -
5.91%(1) 2002 400 -
6.51% 2003 20 20
6.05% 2003 60 60
6.25% 2003 75 75
7.44% 2004 50 50
6.90% 2007 25 25
5.81% 2008 115 115
(1) Current rate, based on LIBOR, reset quarterly
Bank note, due 2002-2003, LIBOR rate, reset 1, 2, 3 or 6 months,
currently 6.57% 300 -
South Carolina Electric & Gas Company:
First Mortgage Bonds: Series Year of Maturity
6% 2000 - 100
6 1/4% 2003 100 100
7.70% 2004 100 100
7 1/2% 49,528 2005 150 -
6 1/8% 2009 100 100
7 1/8% 2013 150 150
7 1/2% 2023 150 150
7 5/8% 2023 100 100
7 5/8% 2025 100 100
First and Refunding Mortgage
Bonds: Series Year of Maturity
9% 2006 131 131
8 7/8% 2021 103 103
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 17
Charleston Franchise Agreement due 1997-2002 7 11
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 49
Public Service Company of North Carolina, Incorporated:
Senior Debentures: Series Year of Maturity
10% 2004 17 -
8.75% 2012 32 -
6.99% 2026 50 -
7.45% 2026 50 -
South Carolina Pipeline Corporation Notes, 6.72%, due 2013 16 17
Other 4 3
-------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Long-Term Debt 2,894 1,869
Less - Current maturities, including sinking fund requirements (41) (303)
- Unamortized discount (3) (3)
-------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Long-Term Debt, Net 2,850 57% 1,563 41%
-------------------------------------------------------------------- -- -------------- -------- -------------- -----------
Total Capitalization $5,048 100% $3,829 100%
==================================================================== == ============== ======== ============== ===========
See Notes to Consolidated Financial Statements.
SCANA Corporation
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
- ----------------- ------------- -- --------- ------------------ ------------- ---------------- ----------- --------------
For the Years Ended December
31, 2000 1999 1998
- ------------------------------- -- ---------------------------- ------------------------------ --------------------------
(Millions of dollars)
Common Comprehensive Common Comprehensive Common Comprehensive
Equity Income Equity Income Equity Income
- ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Retained
Earnings:
Balance at
January 1 $720 $678 $617
Net Income 250 $250 179 $179 223 $223
Dividends declared on common
stock (120) (137) (162)
- ---------------------------------- ----------- ---------------- ------------- ---------------- ----------- --------------
Balance at December 31 850 720 678
- ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Accumulated other comprehensive income:
Balance at
January 1 336 25 18
Unrealized gains (losses)
on securities,
net of taxes ($(106),
$165 and $4 in
2000, 1999 and 1998,
respectively) (197) (197) 311 311 7 7
- ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Comprehensive income $53 $490 $230
- ------------------------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Balance at
December 31 139 336 25
- ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Common Stock:
Balance at
January 1 1,043 1,043 1,153
Shares issued 488 - -
Shares
repurchased (488) - (110)
- ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Balance at
December 31 1,043 1,043 1,043
- ----------------- ------------- -- ----------- ---------------- ------------- ---------------- ----------- --------------
Total Common
Equity $2,032 $2,099 $1,746
================= ============= == =========== ================ ============= ================ =========== ==============
Accumulated other comprehensive income at December 31, 2000, 1999 and 1998 was
comprised of unrealized holding gains and losses on securities, net of taxes.
There were no realized gains or losses from these securities for the years ended
December 31, 2000, 1999 and 1998.
See Notes to Consolidated Financial Statements.
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
registered public utility holding company within the meaning of the Public
Utility Holding Company Act of 1935 (PUHCA). 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, North Carolina and Georgia. 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 Nonregulated businesses
South Carolina Electric & Gas Company (SCE&G) SCANA Energy Marketing, Inc.
South Carolina Fuel Company, Inc. (Fuel Company) SCANA Communications, Inc.
(SCI)
South Carolina Generating Company, Inc. (GENCO) ServiceCare, Inc.
South Carolina Pipeline Corporation Primesouth, Inc.
(Pipeline Corporation) SCANA Resources, Inc.
Public Service Company of North Carolina, SCANA Services, Inc.
Incorporated (PSNC) 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 (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. This 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, 2000, approximately $243 million and $75 million of
regulatory assets and liabilities, respectively, including amounts recorded for
deferred income tax assets and liabilities of approximately $140 million and $57
million, respectively. The electric and gas regulatory assets of approximately
$45 million and $58 million, respectively (excluding deferred income tax
assets), are recoverable through rates. 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
either the Federal Energy Regulatory Commission (FERC) or the National
Association of Regulatory Utility Commissioners (NARUC) and as adopted by the
Public Service Commission of South Carolina (PSC) or, in the case of PSNC, the
North Carolina Utilities Commission (NCUC). The NARUC system of accounts is
substantially the same as the FERC system of accounts.
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 the South Carolina Public Service Authority (Santee Cooper) 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 $965.0 million
and $959.7 million as of December 31, 2000 and 1999, respectively. Accumulated
depreciation associated with SCE&G's share of Summer Station was approximately
$387.7 million and $365.1 million as of December 31, 2000 and 1999,
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)
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 8.3%, 8.1% and 8.7% for 2000, 1999 and 1998, respectively. These rates
do not exceed the maximum allowable rate as calculated under FERC Order No. 561.
Interest on nuclear fuel in process is capitalized at the actual interest amount
incurred.
F. Revenue Recognition
Revenues are recorded during the accounting period in which services
are provided to customers, and include estimated amounts for electricity and
natural gas delivered, but not yet billed. Prior to January 1, 2000 revenues
related to regulated electric and gas services were recorded only as customers
were billed (see Note 2).
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 amounts 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 $35.5 million and $10.1 million at
December 31, 2000 and 1999, respectively, which are included in "Deferred Debits
- - Other regulatory assets."
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 amounts contained in rates
is deferred and included when establishing gas costs during the next annual gas
cost recovery hearing. At December 31, 2000 and 1999 the Company had
undercollected through the gas cost recovery procedure approximately $22.0
million and $4.1 million, respectively, which are included in "Deferred Debits
Other regulatory assets."
SCE&G's and PSNC'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 and amortization are recorded using the
straight-line method and are based on the estimated service lives of the various
classes of property.
The composite weighted average depreciation rates for utility plant assets were
as follows:
2000 1999 1998
- ---------------------------------- --------------- ---------------
SCE&G 2.98% 2.99% 3.02%
GENCO 2.67% 2.56% 2.65%
Pipeline Corporation 2.58% 2.62% 2.63%
PSNC 4.15% - -
Aggregate of Above 3.09% 2.95% 2.98%
Nuclear fuel amortization, which is included in "Fuel used in electric
generation" and 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. The acquisition adjustment related to the purchase of PSNC
in 2000 is being amortized over a 35-year period using the straight-line method.
H. Nuclear Decommissioning
SCE&G's share of estimated site-specific nuclear decommissioning costs
for Summer Station, including the cost of decommissioning plant components not
subject to radioactive contamination, totals approximately $357.3 million,
stated in 1999 dollars, based on a decommissioning study completed in 2000.
Santee Cooper is responsible for decommissioning costs related to its ownership
interest in the station. The cost estimate is based on a decommissioning
methodology acceptable to the Nuclear Regulatory Commission (NRC) under which
the site would be maintained over a period of approximately 60 years in such a
manner as to allow for subsequent decontamination that permits release for
unrestricted use.
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 2000, 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 NRC. Management intends for the fund, including
earnings thereon, to provide for all eventual decommissioning expenditures on an
after-tax basis. SCE&G records its liability for decommissioning costs in
deferred credits.
In addition to the above, 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 $2.8 million at
December 31, 2000, 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
The Company files a consolidated income tax return. Under a joint
consolidated income tax allocation agreement, each subsidiary's current and
deferred tax expense is computed on a stand-alone basis. 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. 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.
K. Environmental
The Company maintains 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 remediate 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 also has recovered
portions of its environmental liabilities through settlements with various
insurance carriers, including all amounts previously deferred for its electric
operations. The Company expects to recover all deferred amounts related to
SCE&G's gas operations by December 2005. Deferred amounts for SCE&G, net of
amounts recovered through rates and insurance settlements, totaled $20.2 million
and $23.7 million at December 31, 2000 and 1999, respectively. Deferred amounts
for PSNC totaled $10.2 million at December 31, 2000. The deferral includes the
estimated costs associated with the matters discussed in Note 13C.
L. 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.
M. 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. Changes in the market value of
such financial contracts pertaining to nonregulated operations are deferred and
included in income in the period in which the offsetting physical transactions
occur. 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.
N. Recently Issued Accounting Standard and Bulletin
In June 1998 the Financial Accounting Standards Board (FASB) issued
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." In
June 2000, the FASB issued SFAS 138, which amends certain provisions of SFAS 133
to expand the normal purchase and sale exemption for supply contracts and to
redefine interest rate risk to reduce sources of ineffectiveness, among other
things. The Company utilizes various derivatives in its risk management
activities, including swaps and commodities futures. The Company adopted SFAS
133, as amended, on January 1, 2001. As a result of adopting SFAS 133, the
Company recorded a credit of approximately $23.0 million, net of tax, as the
effect of a change in accounting principle (transition adjustment) to other
comprehensive income on January 1, 2001. This amount represents the
reclassification of unrealized gains that were deferred and reported as
liabilities at December 31, 2000. In the future, all gains/losses related to
qualifying cash flow hedges deferred in other comprehensive income will be
reclassified to earnings at the time the hedged transaction affects earnings.
In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition
in Financial Statements" was issued by the Securities and Exchange Commission
(SEC), and provides the SEC staff's views in applying generally accepted
accounting principles to selected revenue recognition issues. The Company's
adoption of this bulletin in the fourth quarter of 2000 had no impact on its
results of operations, cash flows or financial position.
O. Stock Option Plan
On April 27, 2000 the Company adopted the SCANA Corporation Long-Term
Equity Compensation Plan (the Plan). Under the Plan, certain employees and
non-employee directors may receive nonqualified stock options and other forms of
equity compensation. The Company accounts for this equity-based compensation
under Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees" (APB 25). In addition the Company has adopted the disclosure
provisions of SFAS 123, "Accounting for Stock-Based Compensation."
P. Earnings Per Share
Earnings per share amounts have been computed in accordance with SFAS
128, "Earnings Per Share." Under SFAS 128, basic earnings per share are computed
by dividing net income by the weighted average number of common shares
outstanding for the period. Diluted earnings per share are computed as net
income divided by the weighted average number of shares of common stock
outstanding during the period after giving effect to securities considered to be
dilutive potential common stock. The Company uses the treasury stock method in
determining total dilutive potential common stock.
Q. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2000.
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. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues associated with its regulated utility operations from
cycle billing to full accrual. The cumulative effect of this change was $29
million, net of tax. Accruing unbilled revenues more closely matches revenues
and expenses. Unbilled revenues represent the estimated amount customers will be
charged for service rendered but not yet billed as of the end of the accounting
period.
If this method had been applied retroactively, net income would have
been $181 million ($1.75 per share) and $216 million ($2.05 per share) for the
years ended December 31, 1999 and 1998, respectively, compared to $179 million
($1.73 per share) and $223 million ($2.12 per share), respectively, as reported.
3. ACQUISITION
On February 10, 2000 the Company completed its acquisition of PSNC in a
business combination accounted for as a purchase. PSNC became a wholly owned
subsidiary of the Company. PSNC is a public utility engaged primarily in
transporting, distributing and selling natural gas to approximately 370,000
residential, commercial and industrial customers in 25 of its 28 franchised
counties in North Carolina. Pursuant to the Agreement and Plan of Merger, PSNC
shareholders were paid approximately $212 million in cash and 17.4 million
shares of SCANA common stock valued at approximately $488 million. In connection
with the acquisition, 16.3 million shares of SCANA common stock were repurchased
for approximately $488 million. The results of operations of PSNC are included
in the accompanying financial statements as of January 1, 2000, the effective
date of acquisition . The total cost of the acquisition was approximately $700
million, which exceeded the fair value of the net assets acquired by
approximately $466 million. The excess is being amortized over 35 years on a
straight-line basis.
The following represents the unaudited pro forma results of operations of the
Company for 1999 as if the acquisition were consummated on January 1, 1999. The
unaudited pro forma results of operations exclude the effects of the accounting
change discussed in Note 2 and include certain pro forma adjustments, including
the amortization of the acquisition adjustment and interest on acquisition
financing. The unaudited pro forma results of operations do not necessarily
reflect the results that would have occurred had the acquisition occurred at
January 1, 1999 or the results that may occur in the future.
In millions of dollars, except per share amount
- ----------------------------------------------------------- ------------------
Operating revenues $2,385
Net income 163
Basic and diluted earnings per share 1.56
4. RATE AND OTHER REGULATORY MATTERS
South Carolina Electric & Gas Company
A. On July 20, 2000 the PSC issued an order approving SCE&G's request
for an out-of-period adjustment to increase the cost of gas component of its
rates for natural gas service from 54.334 cents per therm to 68.835 cents per
therm, effective with the first billing cycle in August 2000. As part of its
regularly scheduled annual review of gas costs, the PSC issued an order on
November 9, 2000 which further increased the cost of gas component to 78.151
cents per therm, effective with the first billing cycle in November 2000. On
December 21, 2000 the PSC issued an order approving SCE&G's request for another
out-of-period adjustment to increase the cost of gas component to 99.340 cents
per therm, effective with the first billing cycle in January 2001.
B. On July 5, 2000 the PSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million.
C. 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 may 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 may be carried
forward for possible use in the following year. As of December 31, 2000, no
accelerated depreciation has been recorded. The accelerated capital recovery
plan will be accomplished through existing customer rates.
D. 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 12.0 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, ruled that no further rate action was required, and reaffirmed
SCE&G's authorized return on equity of 12.0 percent. The rate reductions were
placed into effect with the first billing cycle of January 1999.
E. 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 South Carolina
Circuit Court (Circuit Court), which affirmed the PSC's decisions, and,
subsequently, to the South Carolina Supreme Court (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.
F. 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 November 2000, 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 $20.1 million.
G. In September 1992 the PSC issued an order granting SCE&G's request
for 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. In response to
an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May
25, 2000, which remanded the matter to the PSC for review of SCE&G's original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC issued an order granting the relief requested by SCE&G. On
September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay
of this order to which SCE&G filed a response. On October 3, 2000 the PSC
accepted the Consumer Advocate's motion and issued a stay of its order. The
Consumer Advocate and other intervenors have petitioned the Circuit Court for
judicial review of the PSC's order granting relief. Action by the Circuit Court
is pending.
Public Service Company of North Carolina, Incorporated
H. On April 6, 2000 the NCUC issued an order permanently approving
PSNC's request to establish its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas. The NCUC
previously allowed PSNC use of this mechanism on a trial basis. This procedure
allows PSNC to manage its deferred gas costs better by ensuring that the amount
paid for natural gas to serve these customers approximates the amount collected
from them.
I. A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties, North Carolina. 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. On June 29, 2000 the NCUC approved PSNC's requests for
reinstatement of its exclusive franchises for Madison, Jackson and Swain
Counties and disbursement of up to $28.4 million from PSNC's expansion fund for
this project. PSNC estimates that the cost of this project will be approximately
$31.4 million.
J. On December 7, 1999 the NCUC issued an order approving the
acquisition of PSNC by the Company. As specified in the NCUC order, PSNC reduced
its rates by approximately $1 million in August 2000, will reduce rates another
$1 million in August 2001 and has agreed to a five-year moratorium on general
rate cases. General rate relief can be obtained during this period to recover
costs associated with materially adverse governmental actions and force majeure
events.
K. On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County and
authorized disbursements from the fund of approximately $4.3 million based upon
budgeted construction cost of approximately $6.2 million. Most of Alexander
County lies within PSNC's certificated service territory and did not previously
have natural gas service. The project was completed and customers began
receiving natural gas service in March 2000.
L. On October 30, 1998 the NCUC issued an order in PSNC's general rate
case filed in April 1998. The order, effective November 1, 1998, granted PSNC
additional revenue of $12.4 million and allowed a 9.82 percent overall rate of
return on PSNC's net utility investment. It also approved the continuation of
the Weather Normalization Adjustment and Rider D Mechanisms and full margin
transportation rates. PSNC's Rider D rate mechanism authorizes the recovery of
all prudently incurred gas costs from customers on a monthly basis. Any
difference in amounts paid and collected for these costs is deferred for
subsequent refund to or collection from customers. On February 4, 2000, in
response to an appeal by the Carolina Utility Customers Association, Inc., the
Supreme Court of North Carolina affirmed the NCUC order.
5. EMPLOYEE BENEFIT PLANS AND EQUITY COMPENSATION PLAN
Employee Benefit Plans
The Company sponsors a noncontributory defined benefit pension plan, which
covers substantially all permanent employees. 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.
Effective July 1, 2000 the Company's pension plan was amended to provide a
cash balance formula. With certain exceptions, employees were allowed to either
remain under the final average pay formula or elect the cash balance formula.
Under the final average pay formula, benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment. Under the cash balance formula, the monthly benefit
earned under the final average pay formula at July 1, 2000 was converted to a
lump sum amount for each employee and increased by transition credits for
eligible employees. Under the cash balance formula, benefits based upon this
opening balance increase going forward as a result of compensation credits and
interest credits. The effect of this plan amendment was to reduce the Company's
net periodic benefit income for the year ended December 31, 2000 by
approximately $3.7 million.
In addition to pension benefits, the Company provides certain unfunded
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 services 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 and $15.7 million for the years
ended December 31, 1999 and 1998, respectively. (See Note 4E.)
Effective July 1, 2000 PSNC's pension and postretirement benefit plans were
merged with SCANA's plans. At the time of the merger of the plans, PSNC had
recorded a prepaid pension cost of approximately $9.0 million and a
postretirement welfare plan obligation of approximately $9.1 million in its
consolidated balance sheet.
Disclosures required for these plans under SFAS 132, "Employer's Disclosures
about Pensions and Other Postretirement Benefits" are set forth in the following
tables:
Components of Net Periodic Benefit Cost
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
Millions of dollars 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
Service cost $ 8.3 $10.0 $ 8.3 $ 2.7 $ 3.0 $ 2.6
Interest cost 33.5 27.9 25.9 10.2 9.5 9.4
Expected return on assets (76.6) (65.5) (59.3) n/a n/a n/a
Prior service cost amortization 3.0 1.1 1.1 0.8 0.7 0.7
Actuarial (gain) loss (12.2) (8.6) (9.6) - 1.2 1.0
Transition amount amortization 0.8 0.8 0.8 0.8 1.7 19.1
-
Special termination benefit cost - 5.5 - 1.0 -
----- --- -- - ---- --- -
Net periodic benefit (income)
cost $(43.2) $(28.8) $(32.8) $14.5 $17.1 $32.8
======= ====== ====== ===== ===== =====
Weighted-Average Assumptions
Retirement Benefits Other Postretirement Benefits
-------------------------------------- --------------------------------------
As of December 31, 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
Discount rate 8.0% 8.0% 7.0% 8.0% 8.0% 7.0%
Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Changes in Benefit Obligation
Retirement Benefits Other Postretirement Benefits
------------------------------ ---------------------------------
Millions of dollars 2000 1999 2000 1999
---- ---- ---- ----
Benefit obligation, January 1 $362.3 $389.3 $129.8 $137.0
Service cost 8.3 10.0 2.7 3.0
Interest cost 33.5 27.9 10.2 9.5
Plan participants' contributions 0.1 0.1 0.5 0.5
Plan amendment 65.4 - 0.9 -
Actuarial (gain) loss 1.6 (51.6) (7.8) (14.5)
Acquisition/merger of plans 39.8 - 11.2 -
Benefits paid (31.7) (18.9) (8.5) (6.7)
Special termination benefit cost - 5.5 - 1.0
----------- ------ --- -- ------ ---
Benefit obligation, December 31 $479.3 $362.3 $139.0 $129.8
====== ====== ====== ======
Change in Plan Assets
Retirement Benefits
----------------------------------------------------
Millions of dollars 2000 1999
---- ----
Fair value of plan assets, January 1 $783.0 $698.8
Actual return on plan assets 96.7 103.0
Company contribution - -
Plan participants' contributions 0.1 0.1
Acquisition/merger of plans 46.2 -
Benefits paid (31.7) (18.9)
----- -----
Fair value of plan assets, December 31 $894.3 $783.0
====== ======
Funded Status of Plans
Retirement Benefits Other Postretirement Benefits
------------------------ -------------------------------
Millions of dollars 2000 1999 2000 1999
---- ---- ---- ----
Funded status, December 31 $415.0 $420.7 $(139.0) $(129.8)
Unrecognized actuarial (gain) loss (297.6) (294.0) 13.0 18.8
Unrecognized prior service cost 73.7 11.4 4.5 4.3
Unrecognized net transition obligation 4.8 5.6 8.3 9.1
---------- ------ --- ----- --- ----- ---
Net amount recognized in Consolidated Balance Sheet $195.9 $143.7 $(113.2) $(97.6)
= ====== ====== ======== ======
Health Care Trends
The determination of net periodic other postretirement benefit cost is based on
the following assumptions:
2000 1999 1998
---------------------------------------------------------------- ---------- ---------- ----------
Health care cost trend rate 7.5% 8.0% 8.5%
Ultimate health care cost trend rate 5.5% 5.5% 5.0%
Year achieved 2005 2005 2005
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 other postretirement health care benefit cost and the
accumulated other postretirement benefit obligation for health care benefits are
as follows:
Millions of dollars 1% 1%
Increase Decrease
--------------- -----------------
Effect on health care cost $0.2 $(0.3)
Effect on postretirement obligation 2.9 (3.4)
Long-Term Equity Compensation Plan
The Long-Term Equity Compensation Plan (the Plan) became effective January
1, 2000. The Plan provides for grants of incentive and nonqualified stock
options, stock appreciation rights, restricted stock, performance shares and
performance units to certain key employees. The Plan currently authorizes the
issuance of up to five million shares of the Company's common stock, no more
than one million of which may be granted in the form of restricted stock. As of
December 31, 2000 only nonqualified stock options had been granted. One-third of
the options vest on each anniversary of the date of grant until full vesting
occurs in the third year. The options expire ten years after the grant date. At
December 31, 2000, no stock options were exercisable, and none were forfeited
during the year.
A summary of activity related to grants of nonqualified stock options
follows:
Weighted
Number of Average
Options Exercise Price
----------------- --------------------
Outstanding - December 31, 1999 - -
Granted 160,508 $25.53
================= ====================
Outstanding - December 31, 2000 160,508 $25.53
================= ====================
The Company applies the intrinsic value method prescribed by APB 25 and
related interpretations in accounting for grants made under the Plan. Because
all options were granted with exercise prices equal to the fair market value of
the Company's stock on the respective grant dates , no compensation expense has
been recognized in connection with such grants. If the Company had determined
compensation expense for the issuance of options based on the fair value method
described in SFAS 123, "Accounting for Stock-Based Compensation," net income and
earnings per share for 2000 would have been reduced to the pro forma amounts
presented below:
Net income - as reported (millions) $250.4
Net income - pro forma (millions) 250.3
Basic earnings per share and diluted - as reported 2.40
Basic earnings per share and diluted - pro forma 2.40
For purposes of the above pro forma information, the weighted average
fair value at grant date (the value at grant date of the right to purchase stock
at a fixed price for an extended time period) for options granted in 2000 was
$4.43 and was estimated using the Black-Scholes Option pricing model with the
following weighted average assumptions.
Expected life of options (years) 10
Risk free interest rate 5.99%
Volatility of underlying stock 21%
Dividend yield of underlying stock 4.4%
6. LONG-TERM DEBT
The annual amounts of long-term debt maturities and sinking fund
requirements for the years 2001 through 2005 are summarized as follows:
Year Amount Year Amount
----------------- ----------------- ------------------ -----------------
(Millions of dollars)
2001 $41.0 2004 $186.3
2002 887.3 2005 182.0
2003 447.5
----------------- ----------------- ------------------ -----------------
Approximately $23.5 million of the portion of long-term debt payable in
2001 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).
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
$117.5 million and $143.1 million at December 31, 2000 and 1999, at weighted
average interest rates of 6.59 percent and 6.63 percent, respectively.
Substantially all utility plant is pledged as collateral in connection
with long-term debt.
The Company has a $300 million credit agreement with banks. At December 31,
2000 the entire amount was outstanding.
7. 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 364-day
revolving credit agreement which expires December 19, 2001. The credit agreement
provides for a maximum amount of $125 million to be outstanding at any time.
Since the credit agreement expires within one year, commercial paper amounts
outstanding have been classified as short-term debt.
Commercial paper outstanding totaled $70.2 million at December 31, 2000
and 1999, at weighted average interest rates of 6.59 percent and 6.44 percent,
respectively.
8. 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 6), at December 31, 2000 and
1999, are as follows:
Millions of dollars 2000 1999
- -------------------------------------------------------------- ---------------
Authorized lines of credit at year-end $649.0 $558.3
Unused lines of credit at year-end $564.0 $505.0
Short-term borrowings outstanding at year-end:
Bank loans $85.0 $53.2
Weighted average interest rate 7.48% 7.80%
Commercial paper $312.7 $213.3
Weighted average interest rate 6.63% 6.63%
9. COMMON EQUITY
The changes in "Common Stock," without par value, during 2000, 1999 and
1998 are summarized as follows:
Number of Shares Millions of Dollars
- -----------------------------------------------------------------------------
Balance at December 31, 1997 107,321,113 $1,152.9
Repurchase of common stock (3,748,490) (110.0)
- -----------------------------------------------------------------------------
Balance at December 31, 1998 103,572,623 1,042.9
Changes in common stock - -
- -----------------------------------------------------------------------------
Balance at December 31, 1999 103,572,623 1,042.9
Issuance of common stock 17,413,011 487.7
Repurchase of common stock (16,256,503) (487.7)
- -----------------------------------------------------------------------------
Balance at December 31, 2000 104,729,131 $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, 2000
approximately $32.7 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 2000, 1999 and 1998
at an annual rate per share of $1.15, $1.32 and $1.54, respectively.
10. 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 2001 through 2005 is
$2.8 million.
The changes in "Total Preferred Stock (Subject to purchase or sinking
funds)" during 2000, 1999 and 1998 are summarized as follows:
Number of Shares Millions of Dollars
- --------------------------------------------------------- ----------------------
Balance at December 31, 1997 251,094 $12.5
Shares Redeemed - $50 par value (11,042) (0.5)
- --------------------------------------------------------- ----------------------
Balance at December 31, 1998 240,052 12.0
Shares Redeemed - $50 par value (8,565) (0.4)
- --------------------------------------------------------- ----------------------
Balance at December 31, 1999 231,487 11.6
Shares Redeemed - $50 par value (11,200) (0.6)
- --------------------------------------------------------- ----------------------
Balance at December 31, 2000 220,287 $11.0
========================================================= ======================
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.
11. INCOME TAXES
Total income tax expense attributable to income before cumulative effect
of accounting change for 2000, 1999 and 1998 is as follows:
Millions of dollars 2000 1999 1998
- ----------------------------------------------------------------------- --------
Current taxes:
Federal $88.2 $94.5 $114.8
State 9.2 0.6 2.2
- ----------------------------------------------------------------------- --------
- ----------------------------------------------------------------------- --------
Total current taxes 97.4 95.1 117.0
- ----------------------------------------------------------------------- --------
- ----------------------------------------------------------------------- --------
Deferred taxes, net:
Federal 29.8 6.1 2.3
State 4.7 1.5 2.0
- ----------------------------------------------------------------------- --------
- ----------------------------------------------------------------------- --------
Total deferred taxes 34.5 7.6 4.3
- ----------------------------------------------------------------------- --------
- ----------------------------------------------------------------------- --------
Investment tax credits:
Deferred - State 5.0 13.4 14.3
Amortization of amounts deferred - State (1.3) (1.2) (0.9)
Amortization of amounts deferred - Federal (4.0) (3.6) (3.6)
- ----------------------------------------------------------------------- --------
Total investment tax credits (0.3) 8.6 9.8
- ----------------------------------------------------------------------- --------
Non-conventional fuel tax credits:
Deferred - Federal 9.4 n/a n/a
- ----------------------------------------------------------------------- --------
Total income tax expense $141.0 $111.3 $131.1
======================================================================= ========
The difference between actual income tax expense and the amount
calculated from the application of the statutory Federal income tax rate (35%
for 2000, 1999 and 1998) to pre-tax income before cumulative effect of
accounting change is reconciled as follows:
Millions of dollars 2000 1999 1998
- --------------------------------------------------------------- ----------------- ----------------- -----------------
Income before cumulative effect of accounting change $221.6 $179.0 $223.4
Total income tax expense:
Charged to operating expense 152.0 112.9 136.2
Credited to other items (11.0) (1.6) (5.1)
Preferred stock dividends 7.4 7.4 7.5
- --------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
Total pre-tax income $370.0 $297.7 $362.0
=============================================================== ================= ================= =================
=============================================================== ================= ================= =================
Income taxes on above at statutory Federal income tax rate $129.5 $104.2 $126.7
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 11.4 9.3 11.4
Non-deductible book amortization of acquisition
adjustments 5.0 0.4 0.4
Amortization of Federal investment tax credits (4.0) (3.6) (3.6)
Other differences, net (0.9) 1.0 (3.8)
- --------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
Total income tax expense $141.0 $111.3 $131.1
=============================================================== ================= ================= =================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $819.2 million at December 31, 2000 and
$789.2 million at December 31, 1999 (see Note 1I), are as follows:
Millions of dollars 2000 1999
- --------------------------------------------- ---------------- -----------------
Deferred tax assets:
Unamortized investment tax credits $63.0 $62.8
Other postretirement benefits 40.6 36.6
Early retirement programs 14.6 14.8
Deferred compensation 8.8 8.8
Cycle billing - 15.5
Other 27.4 19.0
- --------------------------------------------- ---------------- -----------------
Total deferred tax assets 154.4 157.5
- --------------------------------------------- ---------------- -----------------
Deferred tax liabilities:
Property, plant and equipment 765.5 665.4
Investments in equity securities 80.0 184.7
Pension plan benefit income 65.3 50.7
Research and experimentation costs 26.8 27.3
Deferred fuel costs 18.5 5.5
Cycle billing 1.9 -
Other 15.6 13.1
- --------------------------------------------- ---------------- -----------------
Total deferred tax liabilities 973.6 946.7
- --------------------------------------------- ---------------- -----------------
Net deferred tax liability $819.2 $789.2
============================================= ================ =================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of the Company through 1995, has examined and proposed
adjustments to the Company's 1996 and 1997 Federal returns, and is currently
examining the Company's Federal returns for 1998 and 1999. The Company does not
anticipate that any adjustments which might result from these examinations will
have a significant impact on its results of operations, cash flows or financial
position.
12. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 2000 and 1999 are as follows:
Millions of dollars 2000 1999
- --------------------------------------------------------- ----------------------------- -----------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------- -------------- -------------- -------------- --------------
Assets:
Cash and temporary cash investments $158.7 $158.7 $116.0 $116.0
Investments 681.7 1,234.5 941.8 1,952.4
Liabilities:
Short-term borrowings 397.7 397.7 266.5 266.5
Long-term debt 2,890.5 2,931.9 1,865.8 1,830.7
Preferred stock (subject to purchase or sinking
funds) 11.0 8.7 11.6 8.5
The information presented herein is based on pertinent available
information as of December 31, 2000 and 1999. 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, 2000, 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. For debt
instruments for which there are no quoted market prices
available, fair values are based on net present value
calculations. For investments for which the fair value is not
readily determinable, fair value approximates cost. Settlement of
long-term debt may not be possible or may not be considered
prudent.
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.
At December 31, 2000, SCANA Communications Holdings, Inc. (SCH), a wholly owned,
indirect subsidiary of SCANA, held the following investments in ITC Holding
Company, Inc. (ITC) and its affiliates:
o Powertel, Inc. (Powertel) is a publicly traded company that owns
and operates personal communications services (PCS) systems in
several major Southeastern markets. SCH owns approximately 4.9
million common shares of Powertel at a cost of approximately
$77.7 million. Powertel common stock closed at $61.9375 per share
on December 31, 2000, resulting in a pre-tax unrealized holding
gain of $228.8 million (a decline of $189.0 million from December
31, 1999). Accumulated other comprehensive income includes the
after-tax amount of all unrealized holding gains and losses on
common shares. 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). Cumulative dividends on preferred series E
shares are generally paid in common shares of Powertel and are
accrued quarterly. Preferred series B shares become convertible
in March 2002 at a conversion price of $16.50 per common share or
approximately 4.6 million common shares. Preferred series D
shares become 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 become 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 $606.9 million
at December 31, 2000, reflecting an unrecorded pre-tax holding
gain of $434.3 million (a decline of $368.4 million from December
31, 1999).
On August 28, 2000 SCH announced that under terms of separate
definitive agreements, Powertel has agreed to be acquired by
either Deutsche Telekom AG or VoiceStream Wireless Corporation
(VoiceStream). If Deutsche Telekom's previously announced
acquisition of VoiceStream is successfully completed, then
Deutsche Telekom would also acquire Powertel. If the Deutsche
Telekom - VoiceStream transaction is not completed, then
VoiceStream would acquire Powertel. In connection with these
transactions, SCH entered into stockholder agreements with each
of Deutsche Telekom and VoiceStream pursuant to which SCH agreed
to vote its Powertel shares in support of either of these
transactions. In addition, SCH agreed to certain restrictions on
disposition of its Powertel shares and the shares it would
receive in either of these transactions. On March 13, 2001
Powertel shareholders approved the acquisition agreements.
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 $43.0 million. ITCD common stock
closed at $5.39 per share on December 31, 2000, resulting in an
unrealized pre-tax holding loss of $15.4 million (a decline of
$113.7 million from December 31, 1999). Accumulated other
comprehensive income includes the after-tax amount of all
unrealized holding gains and losses on common shares. 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 become 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 $16.0 million at
December 31, 2000, reflecting an unrecorded pre-tax holding gain
of $4.8 million (a decline of $65.8 million from December 31,
1999).
o Knology, Inc. (Knology) is a broad-band service provider of cable
television, telephone and internet services. SCH owns $71,050,000
face amount of 11.875 percent Senior Discount Notes due 2007 of
Knology Broadband, Inc., a wholly-owned subsidiary of Knology.
The Senior Discount Notes have a book basis at December 31, 2000
of approximately $57.9 million. In addition, SCH owns
approximately 7.2 million shares of Knology Series A Convertible
Preferred Stock with a cost basis of approximately $5.0 million
and warrants to purchase approximately 0.2 million shares of
Series A Convertible Preferred Stock. On January 12, 2001 SCH
invested $25.0 million for approximately 8.3 million shares of
Series C Convertible Preferred Stock of Knology. The market value
of these investments is not readily determinable.
o ITC holds ownership interests in several Southeastern
communications companies, including those discussed above. 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 $5.8
million, $7.2 million, and $4.0 million, respectively. The market
values of these investments are not readily determinable.
13. COMMITMENTS AND CONTINGENCIES
A. Lake Murray Dam Reinforcement
On October 15, 1999 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. Until discussions are concluded, it
is not possible to finalize the cost of the project; however, it is possible
that the cost could range up to $250 million. Although any costs incurred by
SCE&G are expected to be recoverable through electric rates, SCE&G also is
exploring alternative sources of funding. The project is expected to be
completed in 2004.
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). The policies covering
the nuclear facility for property damage, excess property damage and outage cost
permit assessments under certain conditions to cover insurer's losses. Based on
the current annual premium, SCE&G's portion of the retrospective premium
assessment would not exceed $8.1 million.
To the extent that insurable claims for property damage, decontamination,
repair and replacement and other costs and expenses arising from a nuclear
incident at Summer Station exceed the policy limits of insurance, or to the
extent such insurance becomes unavailable in the future, and to the extent that
SCE&G's rates would not recover the cost of any purchased replacement power,
SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to
anticipate a serious nuclear incident at Summer Station. If such an incident
were to occur, it could have a material adverse impact on the Company's results
of operations, cash flows and financial position.
C. Environmental
South Carolina Electric & Gas Company
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)
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 Work Plan 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 $2 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. SCE&G submitted a Comprehensive Remedial Design Work Plan (RDWP) on
December 17, 1999 and proceeded with implementation pending agency approval. The
RDWP was approved by the EPA in July 2000, and its implementation continues.
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 constructed an 1,100 space parking
garage on the Calhoun Park site (construction was completed in April 2000) and
transferred the facility to the City in exchange for a $16.5 million, 18-year
municipal bond collateralized by revenues from, and a mortgage on, the parking
garage.
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. For the site located in Florence, South
Carolina, SCE&G entered into a similar Remedial Action Plan Contract with DHEC
effective September 5, 2000. SCE&G is continuing to investigate the remaining
site in Columbia, and is monitoring the nature and extent of residual
contamination.
Public Service Company of North Carolina, Incorporated
PSNC owns, or has owned, all or portions of seven 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. An environmental due diligence review of PSNC
conducted in February 1999 estimated that the cost to remediate the remaining
sites would range between $11.3 million and $21.9 million. During the second
quarter of 2000, the review was finalized and the estimated liability was
recorded. 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. 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 December 31, 2000, PSNC has recorded a liability
and associated regulatory asset of $10.2 million, which reflects the minimum
amount of the range, net of shared cost recovery from other PRPs. Amounts
incurred to date are not material. Management intends to request recovery of
additional MGP cleanup costs not recovered from other PRPs in future rate case
filings, and believes that all costs incurred will be recoverable in gas rates.
D. Franchise Agreement
See Note 6 for a discussion of the electric franchise agreement between
SCE&G and the City of Charleston.
E. Claims and Litigation
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. 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 the Company
were also named as defendants 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.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
14. 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, Retail Gas Marketing and Energy Marketing. 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.
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 FERC. GENCO owns and operates the Williams Station generating
facility and sells all of its electric generation to SCE&G. GENCO is regulated
by 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 the local distribution operations of SCE&G
and PSNC, is engaged in the purchase and sale, primarily at retail, of natural
gas. SCE&G's operations extend to 31 counties in South Carolina covering
approximately 21,000 square miles. PSNC was acquired by SCANA in 2000. PSNC's
operations cover 25 counties in North Carolina and approximately 11,500 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
state commission in their respective state of operations.
Retail Gas Marketing markets natural gas in Georgia's deregulated natural
gas market. Energy Marketing markets electricity, natural gas and other light
hydrocarbons, primarily in the Southeast.
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. The marketing segments are
non-regulated, but differ from each other primarily based on their respective
markets.
Disclosure of Reportable Segments
Millions of dollars
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
2000 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
External Customer
Revenue $1,344 $745 $253 $548 $544 $41 $(42) $3,433
Intersegment Revenue 318 1 236 - - 9 (564) -
Operating Income
(Loss) 446 85 28 n/a n/a - (5) 554
Interest Expense 13 20 4 5 1 26 156 225
Depreciation &
Amortization 155 53 7 1 - 5 (4) 217
Income Tax Expense
(Benefit) 1 23 8 1 (1) (4) 113 141
Net Income (loss) 7 19 16 4 (4) (6) 214 250
Segment Assets 4,953 1,628 309 103 215 685 (473) 7,420
Expenditures for
Assets 229 58 18 - - 8 48 361
Deferred Tax Assets 6 - 3 5 4 1 (19) -
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
Millions of dollars
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
1999 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
External Customer
Revenue $1,226 $234 $188 $207 $224 $73 $(74) $2,078
Intersegment Revenue 308 5 154 - - 11 (478) -
Operating Income
(Loss) 390 22 20 n/a n/a (79) 353
Interest Expense 12 n/a 4 4 1 23 98 142
Depreciation &
Amortization 148 13 7 1 1 7 (8) 169
Income Tax Expense
(Benefit) 1 n/a 9 (24) (2) 21 106 111
Net Income (loss) 6 n/a 14 (45) (4) 22 186 179
Segment Assets 4,751 399 253 (24) 168 932 (468) 6,011
Expenditures for
Assets 201 19 8 2 1 6 24 261
Deferred Tax Assets 6 n/a 3 - 1 1 5 16
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
Millions of dollars
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
Electric Gas Gas Retail Gas Energy All Adjustments/ Consolidated
1998 Operations Distribution Transmission Marketing Marketing Other Eliminations Total
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
External Customer
Revenue $1,220 $225 $185 $3 $565 $68 $(160) $2,106
Intersegment Revenue 286 5 145 - - 8 (444) -
Operating Income
(Loss) 436 29 27 n/a n/a - (22) 470
Interest Expense 11 n/a 4 - - 19 89 123
Depreciation &
Amortization 126 12 7 - - 7 (7) 145
Income Tax Expense
(Benefit) - n/a 8 (4) (3) (2) 132 131
Net Income (loss) 6 n/a 16 (8) (7) (4) 220 223
Segment Assets 4,600 381 239 2 71 503 (515) 5,281
Expenditures for
Assets 205 19 11 2 2 17 47 303
Deferred Tax Assets 5 n/a 3 - - 4 10 22
- --------------------- ----------- ------------ -------------- ----------- ------------ ---------- ------------- ---------------
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 energy-related and telecommunications
industries. None of these subsidiaries met any of the quantitative thresholds
for determining reportable segments in 2000, 1999 or 1998.
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 and PSNC do have interest charges, income taxes and
deferred tax assets, which are included in Electric Operations and Gas
Distribution, respectively. Interest income is not reported by segment and is
not material. For 2000, adjustments to net income and income tax expense include
the effect of the accounting change described in Note 2.
The Consolidated Financial Statements report operating revenues which are
comprised of the reportable segments. Revenues from non-reportable segments are
included in Other Income. Therefore, the adjustments to total revenue remove
revenues from non-reportable 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 Expense, 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 Expense is also adjusted to eliminate
inter-affiliate charges. Adjustments to depreciation and amortization consist of
non-reportable 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.
15. SUBSEQUENT EVENTS
On January 24, 2001 SCANA issued $202 million two-year floating rate
notes maturing on January 24, 2003. The interest rate is reset quarterly based
on three-month LIBOR plus 110 basis points. Also on January 24, 2001 SCE&G
issued $150 million First Mortgage Bonds having an annual interest rate of 6.70
percent and maturing on February 1, 2011. On February 16, 2001 PSNC issued $150
million of medium-term notes having an annual interest rate of 6.625 percent and
maturing on February 15, 2011. The proceeds from these borrowings were used to
reduce short-term debt and for general corporate purposes.
16. QUARTERLY FINANCIAL DATA (UNAUDITED)
(Millions of dollars, except per share amounts)
- ---------------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
2000 Quarter Quarter Quarter Quarter Annual
- ------------------------------------------------- ------------- ------------ ------------- -------------- -----------
Total operating revenues $821 $662 $816 $1,134 $3,433
Operating income 172(1) 99 146 137 554
Income before cumulative effect of
accounting change 75 28 59 59 221
Cumulative effect of accounting change,
net of taxes 29 - - - 29
Net income 104 28 59 59 250
Basic and diluted earnings per share
before cumulative effect
of accounting change .72 .27 .56 .57 2.12
Cumulative effect of accounting change,
net of taxes .28 - - - .28
Basic and diluted earnings per share 1.00 .27 .56 .57 2.40
- ---------------------------------------------------------------------------------------------------------------------------
First Second Third Fourth
1999 Quarter Quarter Quarter Quarter Annual
- ------------------------------------------------- ------------- -------------- ----------- -------------- -----------
(Millions of Dollars, except per share amounts)
Total operating revenues $546 $435 $558 $539 $2,078
Operating income 88 69 135 61 353
Net income 37 24 67 51 179
Basic and diluted earnings per share .36 .23 .65 .49 1.73
- ------------------------------------------------- ------------- -------------- ----------- -------------- -----------
(1) Excludes $52 million of income taxes that were formerly reported in first
quarter operating income.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.............................. 74
Item 7A. Quantitative Disclosures About Market Risk................. 84
Item 8. Financial Statements and Supplementary Data................ 84
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,
especially in SCE&G's service territory, (4) the impact of competition from
other energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in SCE&G's accounting policies, (8) weather conditions,
especially in areas served by SCE&G, (9) inflation, (10) changes in
environmental regulations and (11) 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
Regulated Electric and Gas Markets
Efforts to restructure electric markets at the state level have slowed
considerably. Dwindling operating reserves and rolling blackouts in parts of
California in January and February 2001 have been widely reported nationwide.
These shortages of electricity have been attributed to flawed state
restructuring legislation, unplanned generating plant shutdowns and other
economic factors. In response, many states that had passed or considered
legislation to restructure the electric industry have stopped such efforts or
are proceeding more slowly.
In South Carolina, electric restructuring efforts have also stalled. The
developments unfolding in California, and several unrelated, contentious issues
before the General Assembly have combined to make consideration of electric
restructuring legislation unlikely in 2001. Legislation or regulatory action at
the Federal level, particularly as a part of a larger energy policy initiative,
may be considered in 2001. SCE&G is not able to predict whether any
restructuring legislation or regulatory action will be enacted and, if it is,
the conditions it will impose on utilities.
SCE&G has undertaken a variety of initiatives aimed at preparing for a
restructured electric market. These initiatives include obtaining accelerated
recovery of electric regulatory assets, establishing open access transmission
tariffs and selling bulk power to wholesale customers at market-based rates.
Marketing of services to commercial and industrial customers has also increased
significantly, and 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 $211 million and $65 million
of regulatory assets and liabilities, respectively, including amounts recorded
for deferred income tax assets and liabilities of approximately $129 million and
$52 million, respectively, on its balance sheet at December 31, 2000.
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, 2000, SCE&G's net investment in
fossil/hydro and nuclear generation assets was $1,154.9 million and $587.2
million, respectively.
LIQUIDITY AND CAPITAL RESOURCES
The cash requirements of SCE&G arise primarily from its operational
needs, funding its construction program and payment of dividends to SCANA. 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.
The revised estimated primary cash requirements for 2001, excluding
requirements for fuel liabilities and short-term borrowings and including notes
payable to affiliated companies, and the actual primary cash requirements for
2000 are as follows:
Millions of dollars 2001 2000
- -------------------------------------------------------------- --------------
Property additions and construction
expenditures, net of allowance for
funds used during construction $396 $248
Nuclear fuel expenditures 26 29
Investments - 1
Maturing obligations, redemptions and
sinking and purchase fund requirements 5 104
- ------------------------------------------------------------- --------------
Total $427 $382
============================================================== ==============
Approximately 63 percent of total cash requirements (after payment of
dividends) was provided from internal sources in 2000 as compared to 69 percent
in 1999.
SCE&G anticipates that its 2001 cash requirements of $427 million will be
met through internally generated funds (approximately 64 percent, 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.
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, 2000 the Bond Ratio
was 6.43. 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 $1,452
million at December 31, 2000), (ii) retirements of Class A Bonds (which
retirement credits totaled $68.4 million at December 31, 2000), and (iii) cash
on deposit with the Trustee.
SCE&G is subject to 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 $665 million were available for such purpose as of December
31, 2000). 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, 2000
the New Bond Ratio was 6.34.
The following additional financing transactions have occurred since
January 1, 2000:
o On June 14, 2000 SCE&G issued $150 million of First Mortgage Bonds having
an annual interest rate of 7.50 percent and maturing on June 15, 2005.
The proceeds from the sale of these bonds were used to pay the maturity
of SCE&G's $100 million First Mortgage Bonds due June 15, 2000, to reduce
short-term debt and for general corporate purposes.
o On January 24, 2001 SCE&G issued $150 million First Mortgage Bonds having
an annual interest rate of 6.70 percent and maturing on February 1, 2011.
The proceeds from the sale of these bonds were used to reduce short-term
debt and for general corporate purposes.
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 ten 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, 2002.
At December 31, 2000 SCE&G had $250 million of unused authorized lines
of credit which consists of a credit agreement for a maximum of $250 million to
support the issuance of commercial paper. SCE&G's commercial paper outstanding
at December 31, 2000 and 1999 was $117.5 million and $143.1 million,
respectively. In addition, Fuel Company has a credit agreement for a maximum of
$125 million with the full amount available at December 31, 2000. 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, 2000 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, 2000 the
Preferred Stock Ratio was 2.09.
On September 21, 1999 SCE&G announced a $256 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 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 are discussing possible reinforcement
alternatives for the dam over the past several years as part of SCE&G's ongoing
hydroelectric operating license with FERC. Until discussions are concluded, it
is not possible to finalize the cost of the project; however, it is possible
that the cost could range up to $250 million. Although any costs incurred by
SCE&G are expected to be recoverable through electric rates, SCE&G also is
exploring alternative sources of funding. The project is expected to be
completed in 2004.
On October 7, 2000 Summer Station was removed from service for a planned
maintenance and refueling outage scheduled to last 38 1/2 days. During initial
inspection activities, plant personnel discovered a small leak coming from a
hole in a weld in a primary coolant system pipe. SCE&G performed extensive
ultrasonic testing of similar welds in the cooling system, which confirmed that
the problem was limited to this single weld. A root cause analysis determined
that the cause of the crack was primary water stress corrosion cracking. The
repair involved cutting out a twelve-inch long spool of the pipe, which included
the entire weld, and installing a new spool piece. Repairs have been completed
and the integrity of the new welds have been verified through extensive testing.
The plant was returned to service in March 2001. The NRC was closely involved
throughout this process and approved SCE&G's actions to repair the crack, as
well as the restart schedule. SCE&G will continue to monitor primary coolant
system pipes during the next outage, scheduled for Spring of 2002. SCE&G
recorded a pretax charge of approximately $6 million in the fourth quarter of
2000 to expense repair costs to date. Additional costs that may be recorded in
the first quarter of 2001 are not expected to be material. The cost of
replacement power is expected to be recovered through SCE&G's electric fuel
adjustment clause.
In January 2001 SCE&G's 385 megawatt coal-fired Cope Generating Station
was taken out of service due to an electrical ground in the generator. The unit
is expected to be returned to service in Spring 2001. The cost of replacement
power is expected to be recovered through SCE&G's fuel adjustment clause.
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. 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 as defendants 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.
Environmental Matters
The CAA required electric utilities to reduce emissions of sulfur
dioxide and nitrogen oxide substantially by the year 2000. These requirements
were 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. The EPA has indicated that
it will propose regulations for stricter limits on mercury and other toxic
pollutants generated by coal-fired plants by December 2003 and will begin
developing these regulations shortly.
SCE&G filed compliance plans with DHEC related to Phase II sulfur
dioxide requirements in 1995 and Phase II oxides of nitrogen oxide (NOx)
requirements in 2000, 1999, 1998 and 1997. SCE&G currently estimates that air
emissions control equipment will require capital expenditures of $82 million
over the 2001-2005 period to retrofit existing facilities, with increased
operation and maintenance costs of approximately $2 million per year. To meet
compliance requirements for the years 2006 through 2010, SCE&G anticipates
additional capital expenditures of approximately $5 million.
In October 1998, the EPA issued a final rule requiring 22 states,
including South Carolina, to modify their state implementation plans (SIP) to
address the issue of NOx pollution. On May 25, 1999, a federal appeals court
delayed indefinitely the implementation of the rule. On March 3, 2000, the court
affirmed the EPA's NOx rule for the affected states. South Carolina was
subsequently ordered to amend its SIP to achieve significant NOx reductions.
South Carolina failed to submit a revised SIP as required under the CAA, and EPA
has issued official notice to South Carolina (and a number of other states) to
comply. While not final, South Carolina has proposed NOx reductions that would
require SCE&G to install pollution control equipment. Because DHEC had not
amended its SIP as of December 31, 2000 to set out or allocate any NOx
reductions, it is not possible to estimate what, if any, capital expenditures
will be required to comply with any potential mandated reductions.
The EPA has undertaken an aggressive enforcement initiative against the
industry and the Department of Justice (DOJ) has brought suit against a number
of utilities in federal court alleging violations of the CAA. Prior to the
suits, those utilities had received requests for information under Section 114
of the CAA, and were issued Notices of Violation prior to the suits. The basis
for these suits is the claim by the EPA that maintenance activities undertaken
by the utilities over the past 20 or more years constitute "major modifications"
which would have required the installation of costly Best Available Control
Technology (BACT). SCE&G has received and responded to Section 114 requests for
information related to its Canadys and Wateree Stations. Similar requests have
been sent to a number of other utilities nation wide. The regulations under the
CAA provide certain exemptions to the definition of "major modifications,"
particularly an exemption for routine repair, replacement or maintenance. SCE&G
has analyzed each of the activities covered by the EPA's requests and believes
each activity represents prudent practice regularly performed throughout the
utility industry as necessary to maintain the operational efficiency and safety
of equipment. As such, SCE&G believes that each of these activities is covered
by the exemption for routine repair, replacement and maintenance and that the
EPA is changing, or attempting to change through enforcement actions, the intent
and meaning of its regulations. SCE&G also believes that, even if some of the
activities in question were found not to qualify for the routine exemption,
there were no increases either in annual emissions or in the maximum hourly
emissions achievable at any of the units caused by any of the activities. The
regulations provide an exemption for increased hours of operation or production
rate and for increases in emissions resulting from demand growth. It is possible
that the EPA will eventually commence enforcement actions against SCE&G relative
to those plants. The EPA has the authority to seek penalties for the alleged
violations in question at the rate of up to $27,500 per day for each violation.
The EPA also would also seek installation of BACT (or equivalent) at the three
plants as well. SCE&G believes that the EPA's and DOJ's claims are without
merit, and that any enforcement action, up to and including a lawsuit resulting
from this issue, will not have a material adverse effect on SCE&G's financial
position or results of operations.
The Federal Clean Water Act, as amended, provides for the imposition of
effluent limitations that require various levels of treatment for each waste
water 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 December 2000, SCE&G
entered into a Consent Order with DHEC related to a malfunction of the waste
water treatment facility at Hagood Station. The order requires SCE&G to correct
the violation.
SCE&G maintains 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.
SCE&G has also recovered portions of its environmental liabilities
through settlements with various insurance carriers, including all amounts
previously deferred for its electric operations. SCE&G 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 $20.2 million and $23.7 million at December 31, 2000 and 1999,
respectively. The deferral includes the estimated costs associated with the
following matters.
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 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 Work Plan 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 $2 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. SCE&G submitted a Comprehensive Remedial
Design Work Plan (RDWP) on December 17, 1999, and proceeded with
implementation pending agency approval. The RDWP was approved by the
EPA in July 2000, and its implementation continues.
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
constructed an 1,100 space parking garage on the Calhoun Park
site (construction was completed in April 2000) and transferred
the facility to the City in exchange for a $16.5 million, 18-year
municipal bond collaterized by revenues from, and a mortgage on,
the parking garage.
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. For the site located in Florence, South Carolina, SCE&G
entered into a similar Remedial Action Plan Contract with DHEC
effective September 5, 2000. SCE&G is continuing to investigate
the remaining site in Columbia, and is monitoring the nature and
extent of residual contamination.
Regulatory Matters
On July 20, 2000 the PSC issued an order approving SCE&G's request for
an out-of-period adjustment to increase the cost of gas component of its rates
for natural gas service from 54.334 cents per therm to 68.835 cents per therm,
effective with the first billing cycle in August 2000. As part of its regularly
scheduled annual review of gas costs, the PSC issued an order on November 9,
2000 which further increased the cost of gas component to 78.151 cents per
therm, effective with the first billing cycle in November 2000. On December 21,
2000 the PSC issued an order approving SCE&G's request for another out-of-period
adjustment to increase the cost of gas component to 99.340 cents per therm,
effective with the first billing cycle in January 2001. In March 2001 the PSC
approved SCE&G's request to decrease the cost of gas component to 79.340 cents
per therm, effective with the first billing cycle in March 2001.
On July 5, 2000 the PSC approved SCE&G's request to implement lower
depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and will result in a reduction in annual
depreciation expense of approximately $2.9 million.
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 may 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 may be carried
forward for possible use in the following year. As of December 31, 2000 no
accelerated depreciation has been recorded. 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 12.0 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, ruled that no further rate action was required, and reaffirmed
SCE&G's authorized return on equity of 12.0 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.
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 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 November 2000, 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 $20.1 million.
In September 1992 the PSC issued an order granting SCE&G's request for 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. In response to
an appeal of the PSC's order by SCE&G, the Circuit Court issued an order on May
25, 2000, which remanded the matter to the PSC for review of SCE&G's original
application and request to terminate the low income rider fare. On September 27,
2000 the PSC issued an order granting the relief requested by SCE&G. On
September 29, 2000 the Consumer Advocate filed a motion with the PSC for a stay
of this order to which SCE&G filed a response. On October 3, 2000 the PSC
accepted the Consumer Advocate's motion and issued a stay of its order. The
Consumer Advocate and other intervenors have petitioned the Circuit Court for
judicial review of the PSC's order granting relief. Action by the Circuit Court
is pending.
Other
In June 1998 the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) 133, "Accounting for
Derivative Instruments and Hedging Activities." In June 2000 the FASB issued
SFAS 138, which amends certain provisions of SFAS 133 to expand the normal
purchase and sale exemption for supply contracts and to redefine interest rate
risk to reduce sources of ineffectiveness, among other things. SCE&G's adoption
of SFAS 133, as amended, on January 1, 2001 did not have a material impact on
SCE&G's results of operations, cash flows or financial position.
In December 1999, Staff Accounting Bulletin No. 101, "Revenue
Recognition in Financial Statements" was issued by the SEC, and provides the SEC
staff's views in applying generally accepted accounting principles to selected
revenue recognition issues. SCE&G's adoption of the bulletin in the fourth
quarter of 2000 had no impact on its results of operations, cash flows or
financial position.
RESULTS OF OPERATIONS
Net Income
Net income and the percent change from the previous year for the years 2000,
1999 and 1998 were as follows:
Millions of dollars 2000 1999 1998
- --------------------------------------------------------------------------------
Net income derived from:
Continuing operations $231.3 $189.2 $227.2
Cumulative effect of accounting change $22.3 - -
================================================================================
Net income $253.6 $189.2 $227.2
================================================================================
Percent increase (decrease) in net income 34.04% (16.75%) 16.72%
- --------------------------------------------------------------------------------
o 2000 vs 1999 Net income increased primarily as a result of more
favorable weather, customer growth and pension
income. These were partially offset by higher purchased
power costs and a charge for repairs at Summer Station.
o 1999 vs 1998 Net income decreased 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. Also
affecting the decrease in net income was the depreciation
reduction recorded in 1998 (as discussed below).
Pension income recorded by SCE&G reduced operations expense by $20.9
million, $16.3 million and $16.6 million for the years ended December 31, 2000,
1999 and 1998, respectively. In addition, pension income increased other income
by $12.9 million, $10.5 million and $9.0 million for the years ended December
31, 2000, 1999 and 1998, respectively. The reductions to operations expense for
1999 and 1998 were substantially offset by accelerated amortization of a
significant portion of the transition obligation for postretirement benefits
other than pensions and certain regulatory assets as approved by the PSC.
Effective July 1, 2000 SCE&G's pension plan was amended to provide a cash
balance formula. The effect of this plan amendment was to reduce net periodic
benefit income for the year ended December 31, 2000 by approximately $3.4
million.
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 1.7 percent of income before income
taxes in 2000, 2.0 percent in 1999 and 3.8 percent in 1998.
Electric Operations
Electric Operations is comprised of the electric portion of SCE&G and Fuel
Company. Electric operations sales margins, excluding the cumulative effect of
accounting change, for 2000, 1999 and 1998 were as follows:
Millions of dollars 2000 1999 1998
- ------------------------------------------------------------------------------
Electric revenue $1,343.8 $1,226.0 $1,219.8
Less: Fuel used in electric generation (231.6) (214.4) (212.3)
Purchased power (182.7) (141.5) (116.4)
- ------------------------------------------------------------------------------
Margin $929.5 $870.1 $891.1
==============================================================================
o 2000 vs 1999 Sales margin increased primarily due to more favorable
weather and customer growth, which was
partially offset by higher purchased power costs.
o 1999 vs 1998 Sales margin decreased primarily due to the impact of a
rate reduction, milder weather and higher
purchased power costs, which were partially offset by
customer growth.
Increases (decreases) from the prior year in megawatt-hour (MWH) sales
volume by classes, excluding volumes attributable to the cumulative effect of
accounting change, were as follows:
Classification 2000 % Change 1999 % Change
------------------------------------------ ------------ ------------- -------------
Residential 396,179 6.3% (55,208) (0.9%)
Commercial 353,621 5.9% 52,440 0.9%
Industrial 524,969 8.5% 316,087 5.4%
Sales for Resale
(excluding interchange) 33,505 2.8% 63,306 5.6%
Other 34,676 6.7% (17,652) (3.3%)
------------------------------------------ -------------
Total territorial 1,342,950 6.7% 358,973 -
Negotiated Market Sales Tariff 264,257 15.7% 183,442 12.3%
------------------------------------------ -------------
Total 1,607,207 7.4% 542,415 2.6%
========================================== ============ ============= =============
o 2000 vs 1999 Sales volume increased primarily due to more favorable
weather and customer growth.
o 1999 vs 1998 Sales volume decreased for residential primarily due to
milder weather, which was partially offset by
customer growth. Volumes for the remaining classes
increased primarily due to customer growth.
Gas Distribution
Gas Distribution is comprised of the local distribution operations of SCE&G.
Gas distribution sales margins, excluding the cumulative effect of accounting
change, for 2000, 1999 and 1998 were as follows:
Millions of dollars 2000 1999 1998
--------------------------------------------- -------------- ------------
Gas operating revenues $325.1 $239.0 $230.4
Less: Gas purchased for resale 233.8 152.6 142.4
--------------------------------------------- -------------- ------------
Margin $91.3 $86.4 $88.0
============================================= ============== ============
o 2000 vs 1999 Sales margin increased primarily as a result of more
favorable weather, which was partially offset
by higher gas costs.
o 1999 vs 1998 Sales margin decreased primarily as a result of higher gas
costs.
Increases (decreases) from the prior year in dekatherm (DT) sales volume by
classes, including transportation gas and excluding volumes attributable to the
cumulative effect of accounting change, were as follows:
Classification 2000 % Change 1999 % Change
------------------------------- ------------- ------------ ------------
Residential 411,985 3.5% (94,027) (0.8%)
Commercial 377,347 3.2% 404,654 3.6%
Industrial (828,737) (4.6%) 644,485 3.7%
Transportation gas 110,220 5.6% (28,732) (1.4%)
------- --------
Total 70,815 0.2% 926,380 2.2%
=============================== ============= ============ ============
o 2000 vs 1999Sales volume increased approximately 2.0
million DTs due to colder weather and customer growth,
which was partially offset by curtailments and use of
alternate fuels by industrial customers.
o 1999 vs 1998 Sales volume increased primarily as a result of customer
growth. Residential volume decreased
primarily due to milder weather.
Other Operating Expenses
Increases (decreases) in other operating expenses were as follows:
Millions of dollars 2000 1999
- -------------------------------------------------- ---------------------
Other operation and maintenance $(8.2) $7.0
Depreciation and amortization 4.8 22.3
Other taxes 3.5 1.8
- -------------------------------------------------- ---------------
Total $0.1 $31.1
================================================== ===============
o 2000 vs 1999Other operation and maintenance decreased due
to pension income (see Net Income), which was partially
offset by increased maintenance costs for electric
generating and distribution facilities. Depreciation and
amortization increased primarily due to normal increases
in utility plant. Other taxes increased primarily due to
increased property taxes.
o 1999 vs 1998 Other 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. These costs were partially offset by
pension income, which in 1998 had been offset by the
accelerated amortization of SCE&G'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. Other taxes increased primarily due to
increased property taxes.
Interest Expense
Increases (decreases) in interest expense, excluding the debt component of
AFC, were as follows:
Millions of dollars 2000 1999
- ------------------------------------------------ ---------------------
Interest on long-term debt, net $4.0 $1.9
Other interest expense (0.5) 2.4
- ------------------------------------------------- ---------------------
Total $3.5 $4.3
================================================= =====================
Interest expense in 2000 increased as a result of increased borrowings and
increased weighted average interest rates on short-term and long-term
borrowings. Interest expense in 1999 increased as a result of increased
borrowings.
Income Taxes
Income taxes increased approximately $23.4 million for the year 2000
compared to 1999 and decreased approximately $22.4 million for the year ended
1999 compared to 1998. Changes in income taxes are primarily due to changes in
operating income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by SCE&G described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about SCE&G's
financial instruments that are sensitive to changes in interest rates. For debt
obligations the table presents principal cash flows and related weighted average
interest rates by expected maturity dates.
December 31, 2000 Expected Maturity Date
Millions of dollars
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Fair Value
- ----------- ---- ---- ---- ---- ---- ---------- ----- ----------
- --------------------------- ------------ ----------- ----------- ----------- ----------- ------------- ------------- ------------
Long-Term Debt:
Fixed Rate ($) 27.6 27.6 129.5 123.9 173.9 932.5 1,415.0 1,331.6
- -------------------
Average Interest Rate 6.72% 6.72% 6.37% 7.52% 7.40% 7.55% 7.39%
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%
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............................................... 85
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2000 and 1999........... 86
Consolidated Statements of Income and Retained Earnings
for years ended December 31, 2000, 1999 and 1998................... 88
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998.................................... 89
Consolidated Statements of Capitalization as of December
31, 2000 and 1999................................................. 90
Notes to Consolidated Financial Statements............................. 92
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, 2000 and 1999 and the related Consolidated Statements of Income and Retained
Earnings and Cash Flows for each of the three years in the period ended December
31, 2000. 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 auditing standards generally accepted
in the United States of America. 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, 2000
and 1999 and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such financial 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.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for operating
revenues.
s/Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 2001
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
- ----------------------------------------------------------------------------- ----------------- -------------------
December 31, (Millions of dollars) 2000 1999
- ----------------------------------------------------------------------------- ----------------- -------------------
Assets
Utility Plant (Notes 1 & 5):
Electric $4,453 $4,337
Gas 409 392
Other 186 191
- ----------------------------------------------------------------------------- ----------------- -------------------
Total 5,048 4,920
Less accumulated depreciation and amortization 1,720 1,611
- ----------------------------------------------------------------------------- ----------------- -------------------
Total 3,328 3,309
Construction work in progress 230 149
Nuclear fuel, net of accumulated amortization 57 43
- ----------------------------------------------------------------------------- ----------------- -------------------
Utility Plant, Net 3,615 3,501
- ----------------------------------------------------------------------------- ----------------- -------------------
Nonutility Property and Investments, net of accumulated depreciation 21 19
- ----------------------------------------------------------------------------- ----------------- -------------------
Current Assets:
Cash and temporary cash investments (Notes 1 &11) 60 78
Receivables 287 195
Inventories (At average cost) (Note 6):
Fuel 21 30
Materials and supplies 46 48
Emission allowances 20 17
Prepayments 5 8
Deferred income taxes, net (Notes 1 & 10) - 16
- ----------------------------------------------------------------------------- ----------------- -------------------
Total Current Assets 439 392
- ----------------------------------------------------------------------------- ----------------- -------------------
Deferred Debits:
Emission allowances 3 14
Environmental 20 24
Nuclear plant decommissioning fund (Note 1) 72 64
Pension asset, net (Note 4) 196 144
Other regulatory assets (Note 1) 191 164
Other 107 82
- ----------------------------------------------------------------------------- ----------------- -------------------
Total Deferred Debits 589 492
- ----------------------------------------------------------------------------- ----------------- -------------------
Total $4,664 $4,404
============================================================================= ================= ===================
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------- -------------------- --------------------
December 31, (Millions of dollars) 2000 1999
----------------------------------------------------------------------- -------------------- --------------------
Capitalization and Liabilities
Stockholders' Investment:
Common equity (Note 8) $1,657 $1,558
Preferred stock (Not subject to purchase or sinking funds) (Note
9) 106 106
----------------------------------------------------------------------- -------------------- --------------------
Total Stockholders' Investment 1,763 1,664
Preferred Stock, net (Subject to purchase or sinking funds) 10 11
Company-Obligated Mandatorily Redeemable Preferred Securities of the
Company's Subsidiary Trust, SCE&G Trust I, holding solely $50 million
principal amount of the 7.55%
Junior Subordinated Debentures of SCE&G, due 2027 50 50
Long-Term Debt, net (Notes 5 & 11) 1,267 1,121
----------------------------------------------------------------------- -------------------- --------------------
Total Capitalization 3,090 2,846
----------------------------------------------------------------------- -------------------- --------------------
Current Liabilities:
Short-term borrowings (Notes 6, 7 & 11) 188 213
Current portion of long-term debt (Note 5) 28 128
Accounts payable 103 78
Accounts payable - affiliated companies (Note 1) 58 33
Customer deposits 17 17
Taxes accrued 51 60
Interest accrued 22 22
Dividends declared 44 28
Deferred income taxes, net (Notes 1 & 10) 20 -
Other 10 10
----------------------------------------------------------------------- -------------------- --------------------
Total Current Liabilities 541 589
----------------------------------------------------------------------- -------------------- --------------------
Deferred Credits:
Deferred income taxes, net (Notes 1 & 10) 584 560
Deferred investment tax credits (Notes 1 & 10) 109 108
Reserve for nuclear plant decommissioning (Note 1) 72 64
Postretirement benefits (Note 4) 113 98
Other regulatory liabilities 65 59
Other (Note 1) 90 80
----------------------------------------------------------------------- -------------------- --------------------
Total Deferred Credits 1,033 969
----------------------------------------------------------------------- -------------------- --------------------
Commitments and Contingencies (Note 12) - -
----------------------------------------------------------------------- -------------------- --------------------
Total $4,664 $4,404
======================================================================= ==================== ====================
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
For the Years Ended December 31, 2000 1999 1998
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
(Millions of Dollars, except per share amounts)
Operating Revenues (Notes 1, 2 & 3):
Electric $1,344 $1,226 $1,220
Gas 325 239 230
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Total Operating Revenues 1,669 1,465 1,450
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Operating Expenses:
Fuel used in electric generation 232 214 212
Purchased power (including affiliated purchases of $100, $106 and
$185) 183 142 116
Gas purchased for resale 234 153 142
Other operation and maintenance (Note 1) 308 316 309
Depreciation and amortization (Note 1) 158 153 131
Other taxes 97 94 92
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Total Operating Expenses 1,212 1,072 1,002
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Operating Income 457 393 448
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Other Income:
Other Income, including allowance for equity funds used
during construction (Note 1) 14 9 9
Gain on sale of assets 2 3 -
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Total Other Income 16 12 9
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Interest Charges, Income Taxes, Preferred Stock
Dividends
and Cumulative Effect of Accounting Change 473 405 457
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Interest Charges:
Interest expense on long-term debt, net 101 97 95
Other interest expense, net of allowance for borrowed funds used
during construction (Note 1) 4 5 (1)
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Total Interest Charges, Net 105 102 94
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Income Taxes, Preferred Stock Dividends
and Cumulative Effect of Accounting Change 368 303 363
Income Taxes (Note 10) 133 110 132
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Preferred Stock Dividends and Cumulative
Effect of Accounting Change 235 193 231
Preferred Dividend Requirement of Company - Obligated
Mandatorily Redeemable Preferred Securities 4 4 4
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Income Before Cumulative Effect of Accounting Change 231 189 227
Cumulative Effect of Accounting Change, net of taxes (Note 2) 22 - -
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Net Income 253 189 227
Preferred Stock Cash Dividends (At stated rates) (7) (7) (8)
- ----------------------------------------------------------------------- ------------------ ---------------- --------------- --
Earnings Available for Common Stockholder 246 182 219
Retained Earnings at Beginning of Year 550 491 438
Common Stock Cash Dividends Declared (147) (123) (166)
======================================================================= ================== ================ =============== ==
Retained Earnings at End of Year $649 $550 $491
======================================================================= ================== ================ =============== ==
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2000 1999 1998
- ---------------------------------------------------------------------- ------------ ------------- -------------
(Millions of dollars)
Cash Flows From Operating Activities:
Net income $253 $189 $227
Adjustments to reconcile net income to net cash provided from operating
activities:
Cumulative effect of accounting change, net of taxes (22) - -
Depreciation and amortization 159 154 131
Amortization of nuclear fuel 16 18 20
Allowance for funds used during construction (6) (6) (14)
Over (under) collection, fuel adjustment clause (42) (6) 1
Changes in certain assets and liabilities:
(Increase) decrease in receivables (56) (17) (13)
(Increase) decrease in pension asset (43) (29) (33)
(Increase) decrease in other regulatory assets 15 16 (23)
(Increase) decrease inventories 8 (16) (8)
Increase (decrease) in deferred income taxes, net 60 16 49
Increase (decrease) in postretirement benefits 15 11 26
Increase (decrease) in other regulatory liabilities 6 (6) 4
Increase (decrease) in accounts payable 50 (9) 35
Increase (decrease) in taxes accrued (23) (15) 30
Other, net (11) 10 9
- ---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From Operating Activities 379 310 441
- ---------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Investing Activities:
Utility property additions and construction expenditures, net of
AFC (277) (227) (252)
Proceeds on sales of assets 1 3 -
(Increase) decrease in nonutility property and investments (1) (6) (1)
- ---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Used For Investing Activities (277) (230) (253)
- ---------------------------------------------------------------------- ------------ ------------- -------------
Cash Flows From Financing Activities:
Proceeds:
Issuance of First Mortgage Bonds 148 99 -
Repayment and repurchases:
Mortgage bonds (100) (10) (50)
Notes and loans - - (10)
Other long-term debt (4) (9) -
Preferred stock (1) - (1)
Dividend payments:
Common Stock (131) (133) (187)
Preferred stock (7) (7) (8)
Short-term borrowings, net (25) 88 112
Fuel financings, net - (66) (14)
- ---------------------------------------------------------------------- ------------ ------------- -------------
Net Cash Provided From (Used For) Financing Activities (120) (38) (158)
- ---------------------------------------------------------------------- ------------ ------------- -------------
Net Increase (Decrease) in Cash and Temporary Cash Investments (18) 42 30
Cash and Temporary Cash Investments, January 1 78 36 6
====================================================================== ============ ============= =============
Cash and Temporary Cash Investments, December 31 $60 $78 $36
====================================================================== ============ ============= =============
Supplemental Cash Flow Information:
Cash paid for - Interest (net of capitalized interest of $4, $3
and $7) $102 $99 $94
- Income taxes 97 109 92
See Notes to Consolidated Financial Statements.
SOUTH CAROLINA ELECTRIC & GAS COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
December 31, (Millions of dollars) 2000 1999
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
Common Equity (Note 8):
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 649 550
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
Total Common Equity 1,657 54% 1,558 55%
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
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 2000 1999
------ ---- ----
$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) (Note 9) 106 3% 106 4%
- --------------------------------------------------------------------------------- ------------- ------ ------------- ------
Cumulative Preferred Stock (Subject to purchase and sinking funds):
$100 Par Value - Authorized 1,550,000 shares; None outstanding in 2000
and 1999 $50 Par Value - Authorized 1,560,287 shares
Shares Outstanding
Series 2000 1999 Redemption Price
------ ---- ---- ----------------
4.50% 9,600 11,200 51.00 1 1
4.60% (A) 16,052 18,082 51.00 1 1
4.60% (B) 57,800 61,200 50.50 3 3
5.125% 67,000 68,000 51.00 3 3
6.00% 69,835 73,035 50.50 3 4
------------- -----------
Total 220,287 231,487
============= ===========
$25 Par Value - Authorized 2,000,000 shares; None outstanding in 2000 and 1999
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock (Subject to purchase or sinking funds) 11 12
Less: Current portion, including sinking funds requirements (1) (1)
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Total Preferred Stock, Net (Subject to purchase or sinking funds) (Notes 9 & 11) 10 -% 11 -%
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
Company-Obligated Mandatorily Redeemable Preferred Securities of Company's
Subsidiary Trust, SCE&G Trust I, holding solely $50 million principal amount
of 7.55% Junior Subordinated Debentures of SCE&G, due 2027 (Note 9) 50 2% 50 2%
- ---------------------------------------------------------------------------------- ------------ -------- ----------- -------
----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
December 31, 1995 1994
(Thousands(Millions of Dollars)dollars) 2000 1999
----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Long-Term Debt (Notes 3, 4 and 8):5 & 11)
First Mortgage Bonds:
Series Year of
Series Maturity
6% 2000 100,000 100,000- 100
6 1/4% 2003 100,000 100,000100 100
7.70% 2004 100,000 100,000100 100
7 1/2% 2005 150 -
6 1/8% 2009 100 100
7 1/8% 2013 150,000 150,000150 150
7 1/2% 2023 150,000 150,000150 150
7 5/8% 2023 100,000 100,000100 100
7 5/8% 2025 100,000 -100 100
First and Refunding Mortgage Bonds:
Series Year of Series Maturity
4 7/8% 1995 - 16,000
5.45% 1996 15,000 15,000
6% 1997 15,000 15,000
6 1/2% 1998 20,000 20,000
7 1/4% 2002 30,000 30,000
9% 2006 130,771 145,000131 131
8 7/8% 2021 120,450 155,000103 103
Pollution Control Facilities Revenue Bonds:
5.95% Series, due 2003 6,560 6,660
Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820
Richland County Series 1985, due 2014 (6.50%) 5,210 5,210
Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090
Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,36557 57
Orangeburg County Series 1994, due 2024 (daily adjusted rate) 30,000 30,000
Department of Energy Decontamination and Decommissioning Obligation 3,560 3,922
Commercial Paper 76,830 61,794(5.70%) 30 30
Other 3,993 3,29417 17
Charleston Franchise Agreement due 1997-2002 7 11
Other 3 3
----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Long-Term Debt 1,319,649 1,269,155
Less:1,298 1,252
Less - Current maturities, including sinking fund
requirements 36,033 33,042(28) (128)
- Unamortized discount 4,237 4,922(3) (3)
----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Long-Term Debt, Net 1,279,379 48% 1,231,191 50%1,267 41% 1,121 39%
----------------------------------------------------------- ----------- -------------- -------- -------------- -----------
Total Capitalization $2,666,721$3,090 100% $2,440,178$2,846 100%
=========================================================== =========== ============== ======== ============== ===========
See Notes to Consolidated Financial Statements.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:POLICIES
A. Organization and Principles of Consolidation
TheSouth Carolina Electric & Gas Company (Company), a public utility, is a
South Carolina corporation organized in 1924 and a wholly owned subsidiary of
SCANA Corporation, (SCANA), a South Carolina corporation and a registered public utility
holding company.company within the meaning of the Public Utility Holding Company Act of
1935 (PUHCA). The Company through wholly owned subsidiaries is engaged predominately
engaged in the generation and sale of
electricity to wholesale and retail customers in South Carolina and in the
purchase, sale and transportation of natural gas to retail customers in South
Carolina.
The accompanying Consolidated Financial Statements includereflect the accounts
of the Company, and South Carolina Fuel Company, Inc. (Fuel Company). (See Note 1N.) and SCE&G Trust
I. Intercompany balances and transactions between the Company, and 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, 19952000 and 19941999, the Company had approximately
$17.5$45.9 million and $16.3$20.9 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, 19952000 and 19941999 the Company had approximately $8.2$8.3 million and
$8.8$9.2 million, respectively, payable to GENCO for unit power purchases. Such unit
power purchases, which are included in "Purchased power," amounted to
approximately $83.5$100.2 million, $92.8$105.5 million and $98.1$85.0 million in 1995, 19942000, 1999 and
1993,1998, respectively.
Total interest income, based on market interest rates, associated with
the Company's advances to affiliated companies was approximately $174,000, $5,000$1,086,000,
$921,000 and $143,000$281,000 in 1995, 19942000, 1999 and 1993,1998, respectively.
Included in "Other interest expense" for 1995, 1994 and 1993
is approximately $114,000, $279,000 and $29,000, respectively,
relating to advances from affiliated companies. Intercompany
interest is calculated at market rates.
B. Basis of Accounting
The Company preparesaccounts for its financial statementsregulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of
Certain Types of Regulations." The(SFAS) 71. This accounting standard allowsrequires cost-based
rate-regulated utilities such as the Company, to recognize in their financial statements revenues and
expenses in different time periods than do enterprises that are not
rate-
regulated.rate-regulated. As a result the Company has recorded, as of December 31, 1995,2000,
approximately $116$211 million and $4$65 million of regulatory assets and liabilities,
respectively, excluding net
accumulatedincluding amounts recorded for deferred income tax assets and
liabilities of approximately $33
million. As discussed in Note 2A, the PSC has approved
accelerated recovery of substantially all of the Company's$129 million and $52 million, respectively. The
electric and gas regulatory assets (approximately $84.8 million).of approximately $45 million and $37 million,
respectively (excluding deferred income tax assets) are recoverable through
rates. 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 wouldcould 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 recorded.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 FERCFederal Energy Regulatory
Commission (FERC) and as adopted by the PSC.
38
South Carolina Public Service Commission
(PSC).
D. Utility Plant
Utility plant is stated substantially at original cost. The costs of
additions, renewals and betterments to utility plant, including direct labor,
material and indirect charges for engineering, supervision and an allowance for
funds used during construction, are added to utility plant accounts. The
original cost of utility property retired or otherwise disposed of is removed
from utility plant accounts and generally charged, along with the cost of
removal, less salvage, to accumulated depreciation. The costs of repairs,
replacements and renewals of items of property determined to be less than a unit
of property are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station (Summer
Station), and PSAthe South Carolina Public Service Authority (Santee Cooper) are
joint owners of Summer Station in the proportions of two-thirds and one-third,
respectively. The parties share the operating costs and energy output of the
plant in these proportions. Each party, however, provides its own financing.
Plant-in-service related to the Company's portion of Summer Station was
approximately $925.1$965.0 million and $923.1$959.7 million as of December 31, 19952000 and
1994,1999, respectively. Accumulated depreciation associated with the Company's share
of Summer Station was approximately $261.0$387.7 million and $297.9$365.1 million as of
December 31, 19952000 and 1994,1999, respectively. (See Note 2A.) The Company's share of the direct
expenses associated with operating Summer Station is included in "Other
operation"operation and "Maintenance"maintenance" expenses.
E. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, reflects the period cost of capital devoted to plant
under construction. This accounting practice results in the inclusion of, as a
component of construction cost, the costs of debt and equity capital dedicated
to construction investment. AFC is included in rate base investment and
depreciated as a component of plant cost in establishing rates for utility
services. The Company has calculated AFC using composite rates of 8.6%8.1%, 7.7% and
8.5% for 2000, 1999 and 9.4% for 1995, 1994 and 1993,1998, 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.amount incurred.
F. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that
date, the Company ceased the deferral of carrying costs
associated with 400 MW of electric generating capacity previously
removed from rate base and began amortizing the accumulated
deferred carrying costs on a straight-line basis over a ten-year
period. Amortization of deferred carrying costs, included in
"Depreciation and amortization," was approximately $4.2 million
for each of 1995, 1994 and 1993.
G. Revenue Recognition
Customers' metersRevenues are read and bills are rendered on a
monthly cycle basis. Base revenue is recorded during the accounting period in which the metersservices
are read.provided to customers, and include estimated amounts for electricity and
natural gas delivered but not yet billed. Prior to January 1, 2000 revenues
related to regulated electric and gas services were recorded only as customers
were billed (see Note 2).
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 semiannualannual fuel cost hearings. Any
difference between actual fuel costs and thatamounts contained in the fuel cost
component is deferred and included when determining the fuel cost component
during the next semiannualannual fuel cost hearing. The Company had overcollectedundercollected through
the electric fuel cost component approximately $3.8$35.5 million and $10.1 million
at December 31, 19952000 and undercollected approximately $3.5 million at December 31, 19941999, respectively, which are included in "Deferred
Credits - Other" and "Deferral
Debits - Other regulatory assets." respectively.
Customers subject to the gas cost adjustment clause are billed based on a
fixed cost of gas determined by the PSC during annual gas cost recovery
hearings. Any difference between actual gas costcosts and thatamounts contained in the rates
is deferred and included when establishing gas costs during the next annual gas
cost recovery hearing. At December 31, 19952000 and 19941999 the Company had
undercollected through the gas cost recovery procedure approximately $4.6$12.7
million and $16.3$4.1 million, respectively, which are included in "Deferred Debits
- Other.Other regulatory assets."
39
The Company's gas rate schedules for residential, small commercial and
small industrial customers include a weather normalization adjustment, which
minimizes fluctuations in gas revenues due to abnormal weather conditions.
H.G. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the
straight-
linestraight-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 for
utility plant assets were 3.02%2.98%, 3.01%,2.99% and 2.97%3.02% for 1995, 19942000, 1999 and 1993,1998,
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-
productionunits-of-production method. Provisions for
amortization of nuclear fuel include amounts necessary to satisfy obligations to
the United
States DOEDepartment of Energy (DOE) under a contract for disposal of spent nuclear
fuel.
I.H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to
commence in the year 2022 when the operating license expires.
Based on a 1991 study, the expenditures (on a before-tax basis)
related to theThe Company's share of decommissioning activities are
estimated in 2022 dollars assuming a 4.5% annual rate of
inflation, to be $545.3 million including partial reclamation
costs. The Company is providing for its share of estimatedsite-specific nuclear decommissioning
costs offor Summer Station, including the cost of decommissioning plant components
not subject to radioactive contamination, totals approximately $357.3 million,
stated in 1999 dollars, based on a decommissioning study completed in 2000.
Santee Cooper is responsible for decommissioning costs related to its ownership
interest in the station. The cost estimate is based on a decommissioning
methodology acceptable to the Nuclear Regulatory Commission (NRC) under which
the site would be maintained over the lifea period of Summer
Station.approximately 60 years in such a
manner as to allow for subsequent decontamination that permits release for
unrestricted use.
The Company's method of funding decommissioning costcosts is referred to as
COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through
rates ($3.2 million in each of 19952000, 1999 and 1994)1998) are used to purchasepay premiums on
insurance policies on the lives of certain Company personnel. The Company is the
beneficiary of these policies. Through the purchase ofthese insurance contracts, the Company is
able to take advantage of income tax benefits and accrue earnings on the fund on
a tax-
deferred basis at a rate higher than can be achieved using more
traditional funding approaches.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.NRC. Management intends for the fund,
including earnings thereon, to provide for all eventual decommissioning
expenditures on an after-tax basis. The trust's sources of decommissioning funds
under the COMReP program include investment components of life
insurance policy proceeds, return on investment and the cash
transfers from the Company described above. The Company records its liability for
decommissioning costs in deferred credits.
The staff of the Securities and Exchange Commission has
questioned certain of the current accounting practices of the
electric utility industry regarding the recognition, measurement
and classification of decommissioning costs for the financial
statements of electric utilities with nuclear generating
facilities. In response to these questions, the Financial
Accounting Standards Board has agreed to review the accounting
for removal costs, including decommissioning. If the current
electric utility industry accounting practices for such
decommissioning are changed: (1) annual provisions for
decommissioning could increase, and (2) trust fund income from
the external decommissioning trusts could be reported as
investment income rather than as a reduction of decommissioning
expense.
Pursuantaddition to the NEPAabove, 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 amounts
required by the DOE for itsDOE's decontamination and
decommissioning fund.obligation. The liability, approximately $3.6$2.8 million at
December 31, 1995,2000, has been included in "Long-Term Debt, Net.net." The Company will recoveris
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."
J.I. Income Taxes
The Company is included in the consolidated Federalfederal income tax return filed by SCANA. Income taxes are allocated to the
Company basedof
SCANA Corporation. Under a joint consolidated income tax allocation agreement,
each subsidiary's current and deferred tax expense is computed on its contribution to the consolidated total.
As required by Statement of Financial Accounting Standards
No. 109, deferreda stand-alone
basis. 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.
40
K. Pension Expense
The Company participates in SCANA's noncontributory defined
benefit pension plan, which covers all permanent Company
employees. Benefits are based on years of accredited service and
the employee's average annual base earnings received during the
last three years of employment. SCANA's policy has been to fund
pension costs accrued to the extent permitted by the applicable
Federal income tax regulations as determined by an independent
actuary.
Net periodic pension cost for the years ended December 31,
1995, 1994 and 1993 included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 5,187 $ 8,684 $ 7,629
Interest cost on projected benefit obligation 19,473 21,711 20,413
Adjustments:
Return on plan assets (103,874) 2,365 (50,389)
Net amortization and deferral 74,769 (29,760) 25,936
Amounts contributed by the Company's
affiliates (203) (130) (175)
Net periodic pension (income) expense $ (4,648) $ 2,870 $ 3,414
The determination of net periodic pension cost is based upon
the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Expected long-term rate of
return on plan assets 8.0% 8.0% 8.0%
Annual rate of salary increases 2.5% 4.75% 5.5%
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Actuarial present value of benefit obligations:
Vested benefit obligation $228,434 $205,364
Nonvested benefit obligation 15,540 13,966
Accumulated benefit obligation $243,974 $219,330
Plan assets at fair value
(invested primarily in equity and debt securities) $447,760 $347,702
Projected benefit obligation 284,145 246,318
Plan assets greater than
projected benefit obligation 163,615 101,384
Unrecognized net transition liability 9,022 11,307
Unrecognized prior service costs 9,660 9,374
Unrecognized net gain (146,943) (102,284)
Pension asset recognized in
Consolidated Balance Sheets $ 35,354 $ 19,781
The accumulated benefit obligation is based on the plan's
benefit formulas without considering expected future salary
increases. The following table sets forth the assumptions used
in determining the amounts shown above for the years 1995 and
1994.
1995 1994
Annual discount rate used to determine
benefit obligations 7.5% 8.0%
Assumed annual rate of future salary increases
for projected benefit obligation 3.0% 2.5%
41
The change in the annual discount rate used to determine
benefit obligations from 8.0% to 7.5% and the change in the
expected salary increase rate from 2.5% to 3.0% as of December
31, 1995 increased the projected benefit obligation and decreased
the unrecognized net gain by approximately $28.6 million.
In addition to pension benefits, the Company provides
certain health care and life insurance benefits to active
and retired employees. The costs of postretirement benefits
other than pensions are accrued during the years the employees
render the service necessary to be eligible for the applicable
benefits. Prior to 1993, the Company expensed these benefits,
which are primarily health care, as claims were incurred. In its
June 1993 electric rate order, the PSC approved the inclusion in
rates of the portion of increased expenses related to electric
operations. The Company expensed approximately $8.5 million and
$8.6 million, net of payments to current retirees, for the years
ended December 31, 1995 and 1994, respectively. The PSC has
authorized accelerated amortization of the Company's remaining
transition obligation for postretirement benefits other than
pensions related to electric operations. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended
December 31, 1995, 1994 and 1993, included the following
components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned during the period $ 2,076 $ 2,417 $ 1,908
Interest cost on accumulated postretirement
benefit obligation 7,253 6,644 5,502
Adjustments:
Return on plan assets - - -
Amortization of unrecognized
transition obligation 3,344 3,344 3,344
Other net amortization and deferral 661 860 -
Amounts contributed by the Company's affiliates (610) (575) (525)
Net periodic postretirement benefit cost $12,724 $12,690 $10,229
The determination of net periodic postretirement benefit
cost is based upon the following assumptions:
1995 1994 1993
Annual discount rate 8.0% 7.25% 8.0%
Health care cost trend rate 11.0% 11.25% 13.0%
Ultimate health care cost trend rate (to be
achieved in 2004) 6.0% 5.25% 6.0%
42
The following table sets forth the funded status of the plan
at December 31, 1995 and 1994:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligations for:
Retirees $ 64,989 $ 59,174
Other fully eligible participants 6,685 4,995
Other active participants 27,076 24,889
Accumulated postretirement benefit obligation 98,750 89,058
Plan assets at fair value - -
Plan assets less accumulated postretirement benefit
obligation (98,750) (89,058)
Unrecognized net transition liability 58,237 61,581
Unrecognized prior service costs 5,320 3,453
Unrecognized net loss 13,840 11,156
Postretirement benefit liability recognized
in Consolidated Balance Sheets $(21,353) $(12,868)
The accumulated postretirement benefit obligation is based upon the
plan's benefit provisions and the following assumptions:
1995 1994
Assumed health care cost trend rate used to
measure expected costs 10.5% 12.0%
Ultimate health care cost trend rate
(to be achieved in 2004) 5.5% 6.0%
Annual discount rate 7.5% 8.0%
Annual rate of salary increases 3.0% 2.5%
The effect of a one percentage-point increase in the assumed
health care cost trend rate for each future year on the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for the year ended December 31, 1995
and the accumulated postretirement benefit obligation as of
December 31, 1995 would be to increase such amounts by $203,000
and $3.4 million, respectively.
L.J. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
Long-term debt premium, discount and expense are being amortized as
components of "Interest on long-term debt, net" over the terms of the respective
debt issues. Gains or losses on reacquired debt that is refinanced are deferred
and amortized over the term of the replacement debt.
M.K. Environmental
The Company hasmaintains an environmental assessment program to identify and
assess current and former operations sites that could require environmental
cleanup. As site assessments are initiated, an estimate isestimates are made of the
amount of expenditures, if any, deemed necessary to investigate and clean upremediate 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; suchoperations. Such amounts are deferred and
are being
amortized andwith recovery provided through rates. The Company also has recovered
portions of its environmental liabilities through settlements with various
insurance carriers, including 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 over a ten-year period for
electric operations and an eight-year period for gas operations.
Such deferred amountsinsurance settlements, totaled $18.0$20.2 million and $20.2$23.7 million
at December 31, 19952000 and 1994, respectively, and are included1999, respectively. The deferral includes the estimated
costs associated with the matters discussed in "Deferred Debits - Other."
43
N.Note 12C.
L. 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 4.6.)
O.M. Temporary Cash Investments
The Company considers temporary cash investments having original
maturities of three months or less to be cash equivalents. Temporary cash
investments are generally in the form of commercial paper, certificates of
deposit and repurchase agreements.
P.N. Recently Issued Accounting Standards
TheStandard and Bulletin
In June 1998 the Financial Accounting Standards Board has(FASB) issued Statement of Financial Accounting Standards No. 121,SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities." In June 2000 the
Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of." TheFASB issued SFAS 138, which amends certain provisions of SFAS 133 to expand the
Statement, which
will be implementednormal purchase and sale exemption for supply contracts and to redefine interest
rate risk to reduce sources of ineffectiveness, among other things. The
Company's adoption of SFAS 133, as amended, on January 1, 2001 did not have a
material impact on the Company's results of operations, cash flows or financial
position.
In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition in
Financial Statements" was issued by the Company forSecurities and Exchange Commission
(SEC), and provides the fiscal year beginning
January 1, 1996, require theSEC staff's views in applying generally accepted
accounting principles to selected revenue recognition issues. The Company's
adoption of a lossthis bulletin in the income
statement and related disclosures whenever events or changes in
circumstances indicate that the carrying amountfourth quarter of a long-lived
asset may not be recoverable. The Company does not believe that
adoption of the provisions of the Statement will have a material2000 had no impact on its
results of operations, cash flows or financial position.
The Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-
Based Compensation," which will be implemented by the Company on
January 1, 1996. The Company does not believe that adoption of
the provisions of the Statement will have a material impact on
its results of operations or financial position.
Q.O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with
the 1995 presentation.
R.presentation adopted for 2000.
P. 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.
442. Cumulative Effect of Accounting Change
Effective January 1, 2000 the Company changed its method of accounting
for operating revenues from cycle billing to full accrual. The cumulative effect
of this change was $22 million, net of tax. Accruing unbilled revenues more
closely matches revenues and expenses. Unbilled revenues represent the estimated
amount customers will be charged for service rendered but not yet billed as of
the end of the accounting period.
If this method had been applied retroactively, net income would have
been $191 million and $220 million for the years ended December 31, 1999 and
1998, respectively, compared to $189 million and $227 million, respectively, as
reported.
2.3. RATE MATTERS:AND OTHER REGULATORY MATTERS
A. On July 10, 1995,20, 2000 the PSC issued an order approving the Company's
request for an out-of-period adjustment to increase the cost of gas component of
its rates for natural gas service from 54.334 cents per therm to 68.835 cents
per therm, effective with the first billing cycle in August 2000. As part of its
regularly scheduled annual review of gas costs, the PSC issued an order on
November 9, 2000 which further increased the cost of gas component to 78.151
cents per therm, effective with the first billing cycle in November 2000. On
December 21, 2000 the PSC issued an order approving the Company's request for
another out-of-period adjustment to increase the cost of gas component to 99.340
cents per therm, effective with the first billing cycle in January 2001.
B. On July 5, 2000 the PSC approved the Company's request to implement
lower depreciation rates for its gas operations. The new rates were effective
retroactively to January 1, 2000 and resulted in a reduction in annual
depreciation expense of approximately $2.9 million.
C. 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 filedmay 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 may
be carried forward for possible use in the following year. As of December 31,
2000 no accelerated depreciation has been recorded. The accelerated capital
recovery plan will be accomplished through existing customer rates.
D. On December 11, 1998 the PSC issued an applicationorder 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 12.0
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 the Company's motion for
reconsideration, ruled that no further rate action was required, and reaffirmed
the Company's authorized return on equity of 12.0 percent. The rate reductions
were placed into effect with the PSC for an increase in retail electric rates.first billing cycle of January 1999.
E. On January 9, 1996 the PSC issued an order granting the Company an
increase of
7.34%in retail electric rates which will produce additional revenues of approximately
$67.5 million annually. The increase will bewere fully implemented in two
phases. The first phase, an increase in revenues of
approximately $59.5 million annually based on a test year, or
6.47%, commenced onby January 15, 1996. The second phase will be
implemented in January 1997 and will produce additional revenues
of approximately $8.0 million annually, or .87% more than current
rates.1997.
The PSC authorized a return on common equity of 12.0%.12.0 percent. The PSC also
approved establishment of a Storm Damage Reserve Account capped at $50 million
andto be collected through rates over a ten-year period. Additionally, the PSC
approved accelerated recovery of substantially all (excluding accumulated deferred
income taxes)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. B. On October 27,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.
F. 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.plants (MGPs). The
billing surcharge which was
effective with the first billing cycle in November 1994 and is subject to annual review and provides for the recovery of
approximately $16.2 million representing 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 1995,November 2000, as a result of the ongoing annual review,
the PSC approved the continued useCompany's request to maintain the billing surcharge at
$.011 per therm to provide for the recovery of the billing surcharge. Theremaining balance remaining to be recovered
amounts to approximately $14.5of $20.1
million.
C.G. In September 1992 the PSC issued an order granting the CompanyCompany's
request for a $.25 increase in transit fares from $.50 to $.75 in both Columbia, and Charleston,
South Carolina; however, the PSC also required $.40 fares for low-incomelow income
customers and denied the Company's request to reduce the number of routes and
frequency of service. The new rates were placed into effect in October 1992. The
Company appealed the PSC's order to the Circuit Court, which onin May 23, 1995 ordered
the case back to the PSC for reconsideration of several issues including the low-incomelow
income rider program, routing changes, and the $.75 fare. The Supreme Court
declined to review an appeal of the Circuit Court decision and dismissed the
case. Another Petition for Reconsideration was
filed by theThe PSC and other intervenors filed another Petition for Reconsideration,
which wasthe 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. In response to an appeal of the PSC's order by the Company, the
Circuit Court issued an order on May 25, 2000, which remanded the matter to the
PSC for review of the Company's original application and request to terminate
the low income rider fare. On September 27, 2000 the PSC issued an order
granting the relief requested by the Company. On September 29, 2000 the Consumer
Advocate filed a motion with the PSC for a stay of this order, to which the
Company filed a response. On October 3, 2000 the PSC accepted the Consumer
Advocate's motion and issued a stay of its order. The Consumer Advocate and
other intervenors have petitioned the Circuit Court for judicial review of the
PSC's order granting relief. Action by the Circuit Court. Procedural mattersCourt is pending.
4. EMPLOYEE BENEFIT PLANS
The Company participates in SCANA's noncontributory defined benefit
pension plan, which covers substantially all permanent employees. 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.
Effective July 1, 2000, SCANA's pension plan was amended to provide a
cash balance formula. With certain exceptions, employees were allowed to either
remain under the final average pay formula or elect the cash balance formula.
Under the final average pay formula, benefits are based on years of accredited
service and the employee's average annual base earnings received during the last
three years of employment. Under the cash balance formula, the monthly benefit
earned under the final average pay formula at July 1, 2000 was converted to a
lump sum amount for each employee and increased by transition credits for
eligible employees. Under the cash balance formula, benefits based upon this
caseopening balance increase going forward as a result of compensation credits and
interest credits. The effect of this plan amendment was to reduce the Company's
net periodic benefit income for the year ended December 31, 2000 by
approximately $3.4 million.
In addition to pension benefits, the Company provides certain unfunded
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 yetaccrued during the years the employees render
the services necessary to be resolvedeligible 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 and $15.7 million for the years
ended December 31, 1999 and 1998, respectively. (See Note 3E.)
Effective July 1, 2000, PSNC's pension and postretirement benefit plans
were merged with SCANA's plans. At the time of the merger of the plans, PSNC had
recorded a prepaid pension cost of approximately $9.0 million and a
postretirement welfare plan obligation of approximately $9.1 million in its
consolidated balance sheet.
Disclosures required for these plans under SFAS 132, "Employer's
Disclosures about Pensions and Other Postretirement Benefits" are set forth in
the court.
3.following tables:
Components of Net Periodic Benefit Cost
Retirement Benefits Other Postretirement Benefits
--------------------------------------- ---------------------------------------
Millions of dollars 2000 1999 1998 2000 1999 1998
- --------------------------------- ---------- --------------- ------------ -- ---------------- ------------ ---------
Service Cost $8.3 $10.0 $8.3 $2.7 $3.0 $2.6
Interest Cost 33.5 27.9 25.9 10.2 9.5 9.4
Expected return on assets (76.6) (65.5) (59.3) n/a n/a n/a
Prior service cost amortization 3.0 1.1 1.1 0.8 0.7 0.7
Actuarial (gain) loss (12.2) (8.6) (9.6) - 1.2 1.0
Transition amount amortization 0.8 0.8 0.8 0.8 1.7 19.1
Special termination benefit cost - 5.5 - - 1.0 -
Amount attributable to
Company affiliates 1.7 1.1 0.3 (1.6) (0.9) (0.7)
================================= ========== =============== ============ == ================ ============ =========
Net periodic benefit (income)
cost $(41.5) $(27.7) $(32.5) $12.9 $16.2 $32.1
================================= ========== =============== ============ == ================ ============ =========
Weighted-Average Assumptions
Retirement Benefits Other Postretirement Benefits
--------------------------------------- ---------------------------------------
As of December 31 2000 1999 1998 2000 1999 1998
- --------------------------------- ------------ ------------- ------------ -- ---------------- ------------ ---------
Discount rate 8.0% 8.0% 7.0% 8.0% 8.0% 7.0%
Expected return on plan assets 9.5% 9.5% 9.5% n/a n/a n/a
Rate of compensation increase 4.0% 4.0% 4.0% 4.0% 4.0% 4.0%
Changes in Benefit Obligation
Retirement Benefits Other Postretirement Benefits
------------------------------- ---------------------------------------
Millions of dollars 2000 1999 2000 1999
- --------------------------------- ---------------- -------------- -- ----------------- ---------------------
- --------------------------------- ---------------- -------------- -- ----------------- ---------------------
Benefit obligation, January 1 $362.3 $389.3 $129.8 $137.0
Service cost 8.3 10.0 2.7 3.0
Interest cost 33.5 27.9 10.2 9.5
Plan participants' contributions 0.1 0.1 0.5 0.5
Plan amendment 65.4 - 0.9 -
Actuarial (gain) loss 1.6 (51.6) (7.8) (14.5)
Acquisition/merger of plans 39.8 - 11.2 -
Benefits paid (31.7) (18.9) (8.5) (6.7)
Special termination benefit cost - 5.5 - 1.0
================================= ================ ============== == ================= =====================
Benefit obligation, December 31 $479.3 $362.3 $139.0 $129.8
================================= ================ ============== == ================= =====================
Change in Plan Assets
Retirement Benefits
- ------------------------------------------------- ---------------------------- --------------------------
Millions of dollars 2000 1999
- ------------------------------------------------- ---------------------------- --------------------------
Fair value of plan, assets, January 1 $783.0 $698.8
Actual return on plan assets 96.7 103.0
Company contribution - -
Plan participants' contributions 0.1 0.1
Acquisition/merger of plans 46.2 -
Benefits paid (31.7) (18.9)
- ------------------------------------------------- ---------------------------- --------------------------
Fair value of plan assets, December 31 $894.3 $783.0
================================================= ============================ ==========================
Funded Status of Plans
Retirement Benefits Other Postretirement Benefits
---------------------------------
Millions of dollars 2000 1999 2000 1999
- ------------------------------------------ ------------ -------------- ---- --------------- -----------------
Funded status, December 31 $415.0 $420.7 $(139.0) $(129.8)
Unrecognized actuarial (gain) loss (297.6) (294.0) 13.0 18.8
Unrecognized prior service cost 73.7 11.4 4.5 4.3
Unrecognized net transition obligation 4.8 5.6 8.3 9.1
- ------------------------------------------ ------------ -------------- ---- --------------- -----------------
Net asset (liability) recognized in
Consolidated Balance Sheet $195.9 $143.7 $(113.2) $(97.6)
========================================== ============ ============== ==== =============== =================
Health Care Trends
The determination of net periodic other postretirement benefit cost is based on
the following assumptions:
2000 1999 1998
- ------------------------------------------ ---------- ---------- ----------
Health care cost trend rate 7.5% 8.0% 8.5%
Ultimate health care cost trend rate 5.5% 5.5% 5.0%
Year achieved 2005 2005 2005
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 other postretirement benefit obligation for health care benefits are
as follows:
1% 1%
Millions of dollars Increase Decrease
------------------ -----------------
Effect on health care cost $0.2 $(0.3)
Effect on postretirement obligation 2.9 (3.4)
5. LONG-TERM DEBT:DEBT
The annual amounts of long-term debt maturities including
amounts due under nuclear and fossil fuel agreements (see Note
4), and sinking fund
requirements for the years 19962001 through 20002005 are summarized as follows:
----------------- ----------------- ------------------ -----------------
Year Amount Year Amount
(Thousands----------------- ----------------- ------------------ -----------------
(Millions of Dollars)
1996 $ 36,033 1999 $ 17,663
1997 33,252 2000 117,668
1998 114,4832001 $27.6 2004 $123.9
2002 27.6 2005 173.9
2003 129.8
----------------- ----------------- ------------------ -----------------
Approximately $17.3$23.5 million of the portion of long-term debt payable in
19962001 may be satisfied by either deposit and cancellation of bonds issued upon
the basis of property additions or bond retirement credits, or by deposit of
cash with the Trustee.
45
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).
The Company has three-year revolving lines of credit totaling $100$75
million, in addition to other lines of credit, that provide liquidity for
issuance of commercial paper. The three-
yearthree-year lines of credit provide back-up
liquidity when commercial paper outstanding is in excess of $100$175 million. The
long-term nature of the lines of credit allow commercial paper in excess of $100$175
million to be classified as long-term debt. The Company had
outstandingCompany's commercial paper
of $111.2outstanding totaled $117.5 million and $143.1 million at December 31, 1994,2000 and
1999, at weighted average interest rates of which $11.2 million was reclassified to long-term debt.
Certain outstanding long-term debt of an affiliated
company (approximately $35.9 million at both December 31, 19956.59 percent and 1994) is guaranteed by the Company.6.63 percent,
respectively.
Substantially all utility plant and fuel inventories areis pledged as collateral in connection
with long-term debt.
4.6. FUEL FINANCINGS:FINANCINGS
Nuclear and fossil fuel inventories and sulfur dioxide emission
allowances are financed through the issuance by Fuel Company of short-term
commercial paper. These short-term borrowings are supported by an irrevocablea 364-day
revolving credit agreement which expires July 31, 1998. Accordingly, the amounts
outstanding have been included in long-term debt.December 19, 2001. The credit agreement
provides for a maximum amount of $125 million that mayto be outstanding at any time.
Since the credit agreement expires within one year, commercial paper amounts
outstanding have been classified as short-term debt.
Commercial paper outstanding totaled $76.8 million and $50.6$70.2 million at December 31, 19952000 and
19941999 at weighted average interest rates of 5.76%6.59 percent and 6.06%,6.44 percent,
respectively.
5. COMMON EQUITY:7. SHORT-TERM BORROWINGS
The changes in "Stockholders' Investment" (Including
Preferred Stock Not SubjectCompany pays fees to Purchasebanks as compensation for its committed lines of
credit. Commercial paper borrowings are for 270 days or Sinking Funds) during
1995, 1994less. Details of lines
of credit (including uncommitted lines of credit) and 1993short-term borrowings,
excluding amounts classified as long-term (Note 5 ), at December 31, 2000 and
1999, are summarized as follows:
Common Preferred Thousands
Shares SharesMillions of Dollars
Balance December 31, 1992 40,296,147 322,877 $989,768
Changes in Retained Earnings:
Net Income 145,968
Cash Dividends Declared:
Preferred Stock (at stated rates) (6,217)
Common Stock (110,300)
Equity Contributions from Parent 58,142
Balance December 31, 1993 40,296,147 322,877 1,077,361
Changes in Retained Earnings:
Net Income 152,043
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,955)
Common Stock (113,700)
Equity Contributions from Parent 49,710
Balance December 31, 1994 40,296,147 322,877 1,159,459
Changes in Retained Earnings:
Net Income 169,185
Cash Dividends Declared:
Preferred Stock (at stated rates) (5,687)
Common Stock (121,363)
Equity Contributions from Parent
including transferdollars 2000 1999
- ------------------------------------------------------------- ---------------
Authorized lines of assets 139,505
Balance December 31, 1995 40,296,147 322,877 $1,341,099
46
credit at year-end $375.0 $410.0
Unused lines of credit at year-end $375.0 $410.0
Short-term borrowings outstanding at year-end:
Commercial paper $187.7 $213.3
Weighted average interest rate 6.59% 6.63%
8. RETAINED EARNINGS
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 thecertain earnings therefrom. At
December 31, 19952000 approximately $14.5$32.7 million of retained earnings were
restricted by this requirement as to payment of cash dividends on common stock.
6.9. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
The call premium of the respective series of preferred stock in no case
exceeds the amount of the annual dividend.
Retirements under sinking fund requirements are at par values. The
aggregate annual amountsamount of purchase fund or sinking fund requirements for
preferred stock for the years 19962001 through 2000 are summarized as follows:
Year Amount Year Amount
(Thousands of Dollars)
1996 $2,439 1999 $2,440
1997 2,440 2000 2,440
1998 2,4402005 is $2.8 million.
The changes in "Total Preferred Stock (Subject to Purchasepurchase or Sinking
Funds)sinking
funds)" during 1995, 19942000, 1999 and 19931998 are summarized as follows:
Number Thousands
of Shares Millions of Dollars
- -------------------------------------------------------- -----------------------
Balance at December 31, 1992 940,529 $ 58,6391997 251,094 $12.5
Shares Redeemed:
$100 par value (7,374) (737)Redeemed - $50 par value (51,187) (2,558)(11,042) (0.5)
- -------------------------------------------------------- -----------------------
Balance at December 31, 1993 881,968 55,3441998 240,052 12.0
Shares Redeemed:
$100 par value (8,072) (807)Redeemed - $50 par value (51,802) (2,591)(8,565) (0.4)
- -------------------------------------------------------- -----------------------
Balance at December 31, 1994 822,094 51,9461999 231,487 11.6
Shares Redeemed:
$100 par value (6,809) (681)Redeemed - $50 par value (51,666) (2,583)(11,200) (0.6)
- -------------------------------------------------------- -----------------------
Balance at December 31, 1995 763,619 $ 48,682
7.2000 220,287 $11.0
======================================================== =======================
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
$50.0 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.
10. INCOME TAXES:TAXES
Total income tax expense attributable to income before cumulative effect
of accounting change for 1995, 19942000, 1999 and 19931998 is as follows:
1995 1994 1993
(Thousands of Dollars)
Current taxes:
Federal $ 94,137 $66,597 $60,577
State 14,265 9,505 6,822
Total current taxes 108,402 76,102 67,399
Deferred taxes, net:
Federal (7,319) 7,727 12,197
State (603) 2,118 4,387
Total deferred taxes (7,922) 9,845 16,584
Investment tax credits:
Amortization of amounts
deferred (credit) (3,230) (3,231) (3,245)
Total income tax expense $ 97,250 $82,716 $80,738
47
The difference in actual income taxes and the income taxes
calculated from the application of the statutory Federal income
tax rate (35% for 1995, 1994 and 1993) to pretax income is
reconciled as follows:
1995 1994 1993
(Thousands of Dollars)
Net income $169,185 $152,043 $145,968
Total income tax expense:
Charged to operating expenses 96,956 84,066 81,280
Charged (credited) to other income 294 (1,350) (542)
Total pretax income $266,435 $234,759 $226,706
Income taxes on above at statutory
Federal income tax rate $ 93,252 $ 82,166 $ 79,347
Increases (decreases) attributable to:
Allowance for equity funds used
during construction (3,325) (2,796) (2,624)
Amortization of deferred
return on plant investment 1,486 1,486 1,486
Depreciation differences 3,268 2,994 2,531
Amortization of investment
tax credits (3,230) (3,231) (3,245)
State income taxes (less Federal
income tax effect) 8,880 7,555 7,286
Deferred income tax flowback at
higher than statutory rates (3,310) (3,647) (3,641)
Other differences, net 229 (1,811) (402)
Total income tax expense $ 97,250 $ 82,716 $ 80,738
The tax effects of significant temporary differences
comprising the Company's net deferred tax liability of $468.9
million at December 31, 1995 and $485.8 million at December 31,
1994 determined in accordance with Statement No. 109 (see Note
1J) are as follows:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credits $ 48,512 $ 50,513
Cycle billing 19,143 17,521
Nuclear operations expenses 3,755 206
Deferred compensation 5,562 5,450
Other postretirement benefits 6,371 3,187
Other 2,929 3,627
Total deferred tax assets 86,272 80,504
Deferred tax liabilities:
Property plant and equipment 520,294 533,394
Pension expense 14,191 9,022
Reacquired debt 6,680 7,146
Research and experimentation 6,196 2,276
Other 7,801 14,458
Total deferred tax liabilities 555,162 566,296
Net deferred tax liability $468,890 $485,792
Millions of dollars 2000 1999 1998
- ------------------------------------------------------------ ----------------- -----------------
Current taxes:
Federal $78.4 $91.3 $116.1
State 7.8 0.3 2.1
- ------------------------------------------------------------ ----------------- -----------------
- ------------------------------------------------------------ ----------------- -----------------
Total current taxes 86.2 91.6 118.2
- ------------------------------------------------------------ ----------------- -----------------
- ------------------------------------------------------------ ----------------- -----------------
Deferred taxes, net:
Federal 31.8 7.7 1.8
State 5.2 1.4 2.0
- ------------------------------------------------------------ ----------------- -----------------
- ------------------------------------------------------------ ----------------- -----------------
Total deferred taxes 37.0 9.1 3.8
- ------------------------------------------------------------ ----------------- -----------------
- ------------------------------------------------------------ ----------------- -----------------
Investment tax credits:
Deferred - State 5.0 13.4 14.3
Amortization of amounts deferred - State (1.3) (1.2) (0.9)
Amortization of amounts deferred - Federal (3.2) (3.2) (3.2)
- ------------------------------------------------------------ ----------------- -----------------
Total investment tax credits 0.5 9.0 10.2
- ------------------------------------------------------------ ----------------- -----------------
Non-conventional fuel tax credits:
Deferred - Federal 9.4 n/a n/a
- ------------------------------------------------------------ ----------------- -----------------
Total income tax expense 133.1 $109.7 $132.2
============================================================ ================= =================
The difference between actual income tax expense and the amount calculated
from the application of the statutory Federal income tax rate (35% for 2000,
1999 and 1998) to pre-tax income before cumulative effect of accounting change
is reconciled as follows:
Millions of dollars 2000 1999 1998
- --------------------------------------------------------------- ----------------- ----------------- -----------------
Income before cumulative effect of accounting change $223.9 $181.8 $219.7
Total income tax expense:
Charged to operating expense 123.8 103.1 127.9
Charged to other items 9.3 6.6 4.2
Preferred stock dividends 7.4 7.4 7.5
- --------------------------------------------------------------- ----------------- ----------------- -----------------
Total pre-tax income $364.4 $298.9 $359.3
=============================================================== ================= ================= =================
=============================================================== ================= ================= =================
Income taxes on above at statutory Federal income tax rate $127.5 $104.6 $125.8
Increases (decreases) attributed to:
State income taxes (less Federal income tax effect) 10.9 9.0 11.4
Amortization of Federal investment tax credits (3.2) (3.2) (3.2)
Other differences, net (2.1) (0.7) (1.8)
- --------------------------------------------------------------- ----------------- ----------------- -----------------
=============================================================== ================= ================= =================
Total income tax expense $133.1 $109.7 $132.2
=============================================================== ================= ================= =================
The tax effects of significant temporary differences comprising the
Company's net deferred tax liability of $604.1 million at December 31, 2000 and
$544.8 million at December 31, 1999 (see Note 1I), are as follows:
Millions of dollars 2000 1999
- --------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax assets:
Unamortized investment tax credits $57.3 $57.9
Other postretirement benefits 40.6 36.6
Early retirement programs 14.6 14.8
Deferred compensation 8.6 8.6
Cycle billing - 15.5
Other 7.7 11.1
- --------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax assets 128.8 144.5
- --------------------------------------------------------------------------------- ---------------- ------------------
Deferred tax liabilities:
Property, plant and equipment 609.5 593.5
Pension plan benefit income 65.3 50.7
Research and experimentation costs 26.8 27.3
Deferred fuel costs 18.5 5.5
Cycle billing 1.9 -
Other 10.9 12.3
- --------------------------------------------------------------------------------- ---------------- ------------------
Total deferred tax liabilities 732.9 689.3
- --------------------------------------------------------------------------------- ---------------- ------------------
Net deferred tax liability $604.1 $544.8
================================================================================= ================ ==================
The Internal Revenue Service has examined and closed consolidated Federal
income tax returns of SCANA Corporation through 19891995, has examined and proposed adjustments
to SCANA's 1996 and 1997 Federal returns, and is currently examining SCANA's
1990, 1991Federal returns for 1998 and 1992 Federal income
tax returns. Adjustments are currently proposed by the examining
agent. SCANA1999. The Company does not anticipate that any
adjustments which might result from this examinationthese examinations will have a significant
impact on the earningsits results of operations, cash flows or financial position of the Company.
48
8.position.
11. FINANCIAL INSTRUMENTS:INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 19952000 and 19941999 are as follows:
1995 1994Millions of dollars 2000 1999
-------------------------------------------------------- ---------------------- --------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
-------------------------------------------------------- ----------- ------------ ------------ -----------
Assets:
(Thousands of Dollars)
Assets:
Cash and temporary cash investments $ 6,798 $ 6,798 $ 346 $ 346$60.2 $60.2 $78.4 $78.4
Investments 61 61 61 616.4 6.4 4.7 4.7
Liabilities:
Short-term borrowings 81 81 100,000 100,000
Notes payable - affiliated
companies - - 19,409 19,409187.7 187.7 213.3 213.3
Long-term debt 1,315,412 1,412,213 1,264,233 1,195,0231,294.1 1,331.6 1,248.6 1,232.7
Preferred stock (subject to purchase or sinking
funds) 48,682 46,603 51,946 49,34811.0 8.7 11.6 8.5
-------------------------------------------------------- ----------- ------------ ------------ -----------
The information presented herein is based on pertinent information available
to the Company as of December 31, 19952000 and 1994.1999. Although the Company is not aware of any
factors that would significantly affect the estimated fair value amounts, such
financial instruments have not been comprehensively revalued since December 31,
1995,2000, 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 thoseinstruments. For debt
instruments for which there are no quoted market prices available,
fair values are based on net present value calculations. For
investments for which the fair value is not readily determinable,
fair value approximates cost. Settlement of long termlong-term debt may not
be possible or may not be a prudent management decision.considered prudent.
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.
49
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its
committed lines of credit. Commercial paper borrowings are for
270 days or less. Details of lines of credit and short-term
borrowings, excluding amounts classified as long-term (Notes 3
and 4), at December 31, 1995, 1994 and 1993 and for the years
then ended are as follows:
1995 1994 1993
(Millions of dollars)
Authorized lines of credit at year-end $165.0 $165.0 $212.0
Unused lines of credit at year-end $165.0 $165.0 $212.0
Short-term borrowings outstanding at
year-end:
Commercial paper $ 80.5 $100.0 $ 1.0
Weighted average interest rate 5.83% 6.04% 3.35%
10.12. COMMITMENTS AND CONTINGENCIES:
A. ConstructionLake Murray Dam Reinforcement
On October 15, 1999 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 entered into a contract with Duke/Fluor
Daniel in 1991 to design, engineer and build a 385 MW coal-fired
electric generating plant near Cope, South Carolina.
ConstructionFERC have been discussing
possible reinforcement alternatives for the dam over the past several years as
part of the plant started in November 1992. Commercial
operation began in January 1996. TheCompany's ongoing hydroelectric operating license with FERC. Until
discussions are concluded, it is not possible to finalize the cost of the
Cope plant,
excluding AFC,project; however, it is $410.9possible that the cost could range up to $250 million.
In addition, the transmission
lines for interconnection with the Company's system cost $22.5
million.
Under the Duke/Fluor Daniel contract the aggregate amount of
required minimum payments remaining at December 31, 1995 is $4.2
million due in 1996. Through December 31, 1995Although any costs incurred by the Company had
paid $378.7 million underare expected to be recoverable
through electric rates, the contract.Company also is exploring alternative sources of
funding. The project is expected to be completed in 2004.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the
Company's public
liability for a nuclear incident, currently establishes the liability limit for
third-party claims associated with any nuclear incident at $8.9$9.5 billion. Each
reactor licensee is currently liable for up to $79.3$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 $52.9$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
the PSA)Santee Cooper) with Nuclear Electric Insurance Limited (NEIL)
and American Nuclear Insurers (ANI) providing combined property
and decontamination insurance coverage of $1.9 billion. The policies
covering the nuclear facility for any
losses at Summer Station. The Company pays annual premiums and,
in addition, could be assessed a retroactive premium not to
exceed 7 1/2 times its annual premium in the event of property damage, lossexcess property damage and
outage cost permit assessments under certain conditions to any nuclear generating facilities covered under
the NEIL program.cover insurer's
losses. Based on the current annual premium, thisthe Company's portion of the
retroactive premium assessment would not exceed $8.2$8.1 million.
To the extent that insurable claims for property damage, decontamination,
repair and replacement and other costs and expenses arising from a nuclear
incident at Summer Station exceed the policy limits of insurance, or to the
extent such insurance becomes unavailable in the future, and to the extent that
the Company's rates would not recover the cost of any purchased replacement
power, the Company will retain the risk of loss as a self-insurer. The Company
has no reason to anticipate a serious nuclear incident at Summer Station. If
such an incident were to occur, it could have a material adverse impact on the
Company's financial position and results of operations.
50operations, cash flows and financial position.
C. Environmental
As described in Note 1M of Notes to Consolidated Financial
Statements, the Company has an environmental assessment program
to identify and assess current and former operations sites that
could require environmental cleanup. As site assessments are
initiated, estimates are made of the cost, if any, to investigate
and clean up each site. These estimates are refined as
additional information becomes available; therefore, actual
expenditures could differ significantly from original estimates.
Amounts estimated and accrued to date for site assessments and
cleanup relate primarily to regulated operations; such amounts
are deferred and are being amortized and recovered through rates
over a ten-year period for electric operations and an eight-year
period for gas operations. Such deferred amounts totaled $18.0
million and $20.2 million at December 31, 1995 and 1994,
respectively. Estimates to date include, among other items, the
costs estimated to be associated with the matters discussed in
the following paragraphs.
The Company owns four decommissioned manufactured gas plant
sites which contain residues of by-product chemicals. The
Company maintains an active review of the sites to monitor the
nature and extent of the residual contamination.
In September 1992 the EPAEnvironmental 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 Sitearea
site in Charleston, South Carolina. This site originally encompassedencompasses approximately eighteen30 acres
and includedincludes properties which were the locations for industrial operations,
including a wood preserving (creosote) plant, and one of the Company's
decommissioned manufactured gas plants. The original
scope of this investigation has been expanded to approximately 30
acres, including adjacentplants (MGP), properties owned by the National
Park Service and the City of Charleston, and private properties. The site has
not been placed on the National PriorityPriorities List, but may be added before cleanup is initiated.in the future.
The PRPs have agreed with
the EPA to participate in an innovative approach to site
investigation and cleanup called "Superfund Accelerated Cleanup
Model," allowing the pre-cleanup site investigation process to be
compressed significantly. The PRPs havePotentially Responsible Parties (PRPs) negotiated an administrative order by
consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a
corresponding Scope of Work. Field work began in November 1993.1993, 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 is also
workingcompleted Phase One of the
Removal Action Work Plan 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. The Company estimates that the Record of
Decision will result in costs of approximately $13.3 million, of which
approximately $2 million remains. 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 Company submitted a Comprehensive Remedial Design Work
Plan (RDWP) on December 17, 1999 and proceeded with implementation pending
agency approval. The RDWP was approved by the EPA in July 2000, and its
implementation continues.
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
discussed above. As part of the environmental settlement, the Company
constructed an 1,100 space parking garage on the Calhoun Park site (construction
was completed in April 2000) and transferred the facility to the City in
exchange for a $16.5 million, 18-year municipal bond collateralized by revenues
from, and a mortgage on, the parking garage.
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. For the site
located in Florence, South Carolina, the Company entered into a similar Remedial
Action Plan Contract with DHEC effective September 5, 2000. The Company is
continuing to investigate potential
contamination from the manufactured gas plant which may have
migrated toremaining site in Columbia, and is monitoring the
city's aquarium site. In 1994nature and extent of residual contamination.
D. Franchise Agreement
See Note 5 for a discussion of the electric franchise agreement between
SCE&G and the City of Charleston.
E. Claims and Litigation
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, notifiedSouth Carolina. The
facility began operations in March 1999. 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 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, the
Company that it considersand SCANA were also named as defendants in the Company to
be responsible for a $43.5 million increase in costs of the
aquarium project attributable to delays resulting from
contamination of the Calhoun Park Area Site.suit. The Company believes it has meritorious defenses against this claim and the
other defendants believe the suit is without merit and are mounting an
appropriate defense. The Company does not expect itsbelieve that the resolution toof this
issue will have a material impact on its financial position or results of operations.
D. Claims and Litigationoperations, cash flows or
financial position.
The Company is also engaged in various other claims and litigation
incidental to its business operations which management anticipates will be
resolved without material loss to the Company.
No13. SEGMENT OF BUSINESS INFORMATION
The Company's reportable segments, based on combined revenues from
external and internal sources, are Electric Operations and Gas Distribution. 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.
Electric Operations is comprised of the electric portion of the Company
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 and
the FERC. Fuel Company acquires, owns, and provides financing for the fuel and
emission allowances required for the operation of the Company's generation
facilities.
Gas Distribution, comprised of the local distribution operations of the
Company, is engaged in the purchase and sale, primarily at retail, of natural
gas. The Company's operations extend to 31 counties in South Carolina covering
approximately 21,000 square miles.
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
2000 Operations Distribution Other Eliminations Total
- -------------------------------- ------------- -------------- ----------- ---------------- ------------------
External Customer Revenue $1,344 $325 $1 $(1) $1,669
Intersegment Revenue 218 2 - (220) -
Operating Income (Loss) 430 31 - (4) 457
Interest Expense 5 n/a 4 96 105
Depreciation & Amortization 147 11 - - 158
Assets 4,655 416 - (407) 4,664
Expenditures for Assets 227 19 - 32 278
Deferred Tax Assets - n/a - - -
- -------------------------------- ------------- -------------- ----------- ---------------- ------------------
Electric Gas All Adjustments/ Consolidated
1999 Operations Distribution Other Eliminations Total
- -------------------------------- ------------ --------------- ----------- ---------------- ------------------
External Customer Revenue $1,226 $239 $2 $(2) $1,465
Intersegment Revenue 203 2 - (205) -
Operating Income (Loss) 376 22 - (5) 393
Interest Expense 5 n/a 4 93 102
Depreciation & Amortization 140 13 - - 153
Segment Assets 4,452 399 6 (453) 4,404
Expenditures for Assets 198 19 - 16 233
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 $ 2 $(2) $1,450
Intersegment Revenue 201 3 - (204) -
Operating Income (Loss) 423 29 - (4) 448
Interest Expense 4 n/a 4 86 94
Depreciation & Amortization 119 12 - - 131
Assets 4,305 381 4 (444) 4,246
Expenditures for Assets 186 19 - 48 253
Deferred Tax Assets 1 n/a - 20 21
- -------------------------------- ------------ --------------- ----------- ---------------- ------------------
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 reportable segments. Interest income is not reported by segment and is
not material.
The Consolidated Financial Statements report operating revenues which
are comprised of the reportable segments. Revenues from non-reportable segments
are included in Other Income. Therefore, the adjustments to total revenue remove
revenues from non-reportable segments. 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, unallocated assets include accumulated depreciation, offset in part by
common and non-utility plant and non-fixed assets for the segments.
Adjustments to Interest Expense and Deferred Tax Assets include
primarily the totals from the Company that are not allocated to the segments.
Interest Expense is also adjusted to eliminate inter-segment charges. Deferred
Tax Assets are also adjusted to remove the non-current portion of those assets.
14. SUBSEQUENT EVENTS
On January 24, 2001 the Company issued $150 million First Mortgage Bonds
having an annual interest rate of 6.70 percent and maturing on February 1, 2001.
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
Millions of Dollars, except per share amounts
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
First Second Third Fourth
2000 Quarter Quarter Quarter Quarter Annual
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Total operating revenues $395 $371 $448 $455 $1,669
Operating income 108(1) 96 155 98 457
Income before cumulative effect of accounting change 55 44 82 50 231
Cumulative effect of accounting change, net of taxes 22 - - - 22
Net income 77 44 82 50 253
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
First Second Third Fourth
1999 Quarter Quarter Quarter Quarter Annual
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
Total operating revenues $352 $338 $431 $344 $1,465
Operating income 99 80 148 66 393
Net income 48 37 77 27 189
- ------------------------------------------------------- ----------- ------------- ------------ ------------ ---------
(1) Excludes $30 million of income taxes formerly reported in first quarter
operating income.
PUBLIC SERVICE COMPANY
OF NORTH CAROLINA, INCORPORATED
Item 7. Management's Narrative Analysis of
Results of Operations................................. 109
Item 7A. Quantitative Disclosures About Market Risk................ 112
Item 8. Financial Statements and Supplementary Data............... 113
Public Service Company of North Carolina, Incorporated meets the conditions set
forth in General Instruction I(1)(a) and (b) of Form 10-K and therefore is
filing this form with the reduced disclosure format allowed under General
Instruction I(2).
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS.
Statements included in this narrative 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 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,
especially in PSNC's service territory, (4) the impact of competition from other
energy suppliers, (5) growth opportunities, (6) the results of financing
efforts, (7) changes in PSNC's accounting policies, (8) weather conditions,
especially in areas served by PSNC, (9) inflation, (10) changes in environmental
regulations, and (11) the other risks and uncertainties described from time to
time in PSNC's periodic reports filed with the SEC. PSNC disclaims any
obligation to update any forward-looking statements.
SCANA acquired PSNC and PSNC's fiscal year was changed from September
30 to December 31, effective in 2000. The accompanying narrative analysis is
presented in terms of a comparison of the twelve months ended December 31, 2000
and 1999. In connection with the acquisition, which was accounted for as a
purchase, the excess of the purchase price over the fair value of PSNC's assets
and liabilities was recorded as an acquisition adjustment which is being
amortized over a 35 year period.
Condensed Consolidated Income Statements
- ---------------------------------------------------- --------------------------------- ------------------ ---------------
Twelve Months Ended
December 31, %
Millions of dollars 2000* 1999 Change Change
- ---------------------------------------------------- ----------------- --------------- ------------------ ---------------
Operating Revenues $546.8 $306.7 $240.1 78.3
Cost of Gas (374.4) (141.5) (232.9) 164.6
- ---------------------------------------------------- ----------------- --------------- ------------------
Gross Margin 172.4 165.2 7.2 4.4
- ---------------------------------------------------- ----------------- --------------- ------------------
Operating Expenses:
Operation and maintenance 67.6 69.3 (1.7) (2.5)
Depreciation and amortization 41.9 26.2 15.7 59.9
Other taxes 6.4 12.9 (6.5) (50.4)
- ---------------------------------------------------- ----------------- --------------- ------------------
Total Operating Expenses 115.9 108.4 7.5 6.9
- ---------------------------------------------------- ----------------- --------------- ------------------
Operating Income 56.5 56.8 (.3) (0.5)
Other Income, net 8.2 6.6 1.6 24.2
Interest Charges 19.6 18.3 1.3 7.1
- ---------------------------------------------------- ----------------- --------------- ------------------
Income Before Income Taxes and
Cumulative Effect of Accounting Change 45.1 45.1 - -
Income Taxes 23.9 19.3 4.6 23.8
- ---------------------------------------------------- ----------------- --------------- ------------------
Income Before Cumulative Effect of
Accounting Change 21.2 25.8 (4.6) (17.8)
Cumulative Effect of Accounting
Change, net of taxes 6.6 - 6.6 -
- ---------------------------------------------------- ----------------- --------------- ------------------
Net Income $27.8 $25.8 $2.0 7.8
==================================================== ================= =============== ==================
* Effective December 31, 1999, SCANA Public Service Company, L.L.C. (formerly Sonat Public Service Company, L. L.C.)
was consolidated with PSNC.
Earnings and Dividends
Net income for the twelve months ended December 31, 2000 and 1999 was
as follows:
Millions of dollars 2000 1999
- ----------------------------------------- ------------------ -----------------
Net income derived from:
Continuing operations $21.2 $25.8
Cumulative effect of accounting
change, net of taxes 6.6 -
========================================= ================== =================
Net income $27.8 $25.8
========================================= ================== =================
Net income from continuing operations decreased approximately $4.6
million, primarily as a result of increased amortization expense arising from
the amortization of the utility plant acquisition adjustment, which was
partially offset by improved margin and a decrease in other taxes. In 2000 the
cumulative effect of an accounting change resulted from the recording of
unbilled revenues (See Note 2 of Notes to Consolidated Financial Statements).
The nature of PSNC's business is seasonal. The quarters ending June 30
and September 30 are generally PSNC's least profitable quarters due to decreased
demand for natural gas related to lower space heating requirements.
PSNC's Board of Directors authorized payment of dividends on common
stock held by SCANA as follows:
Declaration Date Dividend Amount Quarter Ended Payment Date
February 22, 2000 $6.0 million March 31, 2000 April 1, 2000
April 27, 2000 $5.0 million June 30, 2000 July 1, 2000
August 16, 2000 $4.5 million September 30, 2000 October 1, 2000
October 17, 2000 $3.5 million December 31, 2000 January 1, 2001
Gas Distribution
Gas distribution sales margins (excluding the cumulative effect of the
change in accounting and eliminating the impact of franchise taxes in 1999 as
described at Other Operating Expenses) for the twelve months ended December 31,
2000 and 1999 were as follows:
Millions of dollars 2000 1999 Change % Change
- ------------------------ ------------------------------------------------------
Gas operating revenue $405.6 $300.4 $105.2 35.0%
Less: Cost of gas (237.4) (141.4) (96.0) 67.9%
======================== =====================================
Gross margin $168.2 $159.0 $9.2 5.8%
======================== ======================================================
The increase in margin for the year ended December 31, 2000 primarily
resulted from customer growth.
Energy Marketing
Energy marketing is comprised of SCANA Public Service Company, L.L.C.,
which became a wholly owned subsidiary of PSNC effective December 31, 1999 and
participates in nonregulated activities such as natural gas brokering and supply
services. Energy marketing operating revenues and net income (including
affiliated transactions) for the year ended December 31, 2000 was as follows:
Millions of dollars
-----------------------------------------------------------------------
Operating revenues $142.9
Net income 2.0
=======================================================================
Operation and Maintenance Expenses
The $1.7 million decrease in operation and maintenance expenses from
1999 reflects a net decrease in operating costs arising from the acquisition of
PSNC by SCANA (see Note 3 of Notes to Consolidated Financial Statements). This
decrease was partially offset by the consolidation of SCANA Public Service
Company, L.L.C. in 2000.
Other Operating Expenses
Depreciation and amortization expense increased approximately $15.7
million for the year ended December 31, 2000 as compared to the same period in
1999 primarily due to the amortization of the utility plant acquisition
adjustment (see Note 3 of Notes to Consolidated Financial Statements).
Other taxes decreased for the year ended December 31, 2000 as compared
to the same period in 1999 primarily as a result of the elimination of franchise
taxes by the State of North Carolina effective August 1, 1999. The franchise tax
was replaced by an excise tax. Franchise taxes totaled $6.3 million in 1999, and
were included in PSNC's billing rates and recorded as both operating revenues
and other taxes. The new excise tax is added to customer bills based on the
volume of natural gas consumed. PSNC does not include the excise tax in either
operating revenues or other taxes , as this tax is a pass-through from the
customer to the State of North Carolina.
Other Income, net
Other income increased for the year ended December 31, 2000 as compared
to the same period in 1999 primarily due to a $1.4 million gain on the sale of
properties during the fourth quarter 2000 and an increase in income from
subsidiary operations.
Interest Expense
Interest expense increased $1.3 million over 1999 as a result of
increased borrowings and increased weighted average interest rates on short-term
debt.
Income Taxes
Income taxes increased for the year ended December 31, 2000 compared to
the corresponding period for 1999, primarily due to the non-deductibility of
amortization expense related to the acquisition adjustment.
Capital Expansion Program
PSNC's capital expansion program includes the construction of lines,
systems and facilities and the purchase of related equipment. PSNC's 2001
construction budget is approximately $58 million, compared to actual
construction expenditures for 2000 of $39.1 million. The financing of the
capital expansion program is expected to be funded through borrowings, including
advances from SCANA.
Competition
Although PSNC is the sole distributor of natural gas in its service
area, it faces competition from suppliers of alternate fuels. The primary
alternate fuels available to large commercial and industrial customers are fuel
oil and propane. The primary competition to natural gas in the residential and
smaller commercial markets is electricity.
The NCUC has approved a rate structure that allows PSNC to negotiate
reduced rates in order to match the cost of alternate fuels to large commercial
and industrial customers and recover the lost margin from other classes of
customers. PSNC anticipates that the need to negotiate reduced rates with these
customers will continue.
Electric restructuring efforts in North Carolina have been stalled by
developments in California, concerns over municipal power agencies' debt and
other factors. Legislation or regulatory action at the Federal level,
particularly as part of a larger energy policy initiative, may be considered in
2001. PSNC is not able to predict whether any restructuring legislation or
regulatory action will be enacted and, if it is, the impact it will have on PSNC
and the natural gas industry.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
All financial instruments held by PSNC described below are held for
purposes other than trading.
Interest rate risk - The table below provides information about PSNC'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, 2000 Expected Maturity Date
(Millions of dollars)
Fair
Liabilities 2001 2002 2003 2004 2005 Thereafter Total Value
-------------------------------- --------- ---------- ---------- ---------- ---------- ----------- ---------- ----------
Long-Term Debt:
Fixed Rate ($) 4.3 4.3 7.5 7.5 3.2 122.4 149.2 154.9
Average Fixed Interest Rate 10.0% 10.0% 9.47% 9.47% 8.75% 7.50% 7.87% -
December 31, 1999 Expected Maturity Date
(Millions of dollars)
Fair
Liabilities 2000 2001 2002 2003 2004 Thereafter Total Value
-------------------------------- --------- --------- --------- ---------- ----------- ----------- ----------- ----------
Long-Term Debt:
Fixed Rate ($) 6.8 5.6 4.3 7.5 7.5 125.6 157.3 156.4
Average Fixed Interest Rate 10.0% 10.0% 10.0% 9.47% 9.47% 7.53% 7.98% -
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' Reports........................................ 114
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 2000 and 1999.......... 116
Consolidated Statements of Income and Retained Earnings for the
Year Ended December 31, 2000, the Three Months Ended
December 31, 1999 and the Fiscal Years Ended
September 30, 1999 and 1998.................................... 117
Consolidated Statements of Cash Flows for the Year Ended
December 31, 2000, the Three Months Ended December 31, 1999 and
the Fiscal Years Ended September 30, 1999 and 1998.............. 118
Consolidated Statements of Capitalization as of
December 31, 2000 and 1999........................................... 119
Notes to Consolidated Financial Statements............................. 120
INDEPENDENT AUDITORS' REPORT
Public Service Company of North Carolina, Incorporated:
We have audited the accompanying Consolidated Balance Sheets and Statements of
Capitalization of Public Service Company of North Carolina, Incorporated
(Company) as of December 31, 2000 and 1999, and the related Consolidated
Statements of Income and Retained Earnings and of Cash Flows for the year ended
December 31, 2000 and for the three months 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 the financial statements and financial statement schedule based on
our audits. The consolidated financial statements of the Company for the fiscal
years ended September 30, 1999 and 1998 were audited by other auditors whose
report, dated November 4, 1999 (except with respect to matters discussed in Note
13, as to which the date is December 17, 1999), expressed an unqualified opinion
on those statements.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 2000 and 1999 consolidated financial statements present
fairly, in all material respects, the financial position of the Company at
December 31, 2000 and 1999, and the results of its operations and its cash flows
for the year ended December 31, 2000 and for the three months ended December 31,
1999 in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
As discussed in Notes 1D and 2, respectively, to the consolidated financial
statements, effective January 1, 2000, the Company changed its fiscal year end
to December 31 and its method of accounting for operating revenues associated
with its regulated utility operations.
s/DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbia, South Carolina
February 7, 2001 (February 16, 2001 as to Note 15)
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing
standards, the consolidated financial statements of Public Service Company of
North Carolina, Incorporated included in this Form 10-K, and have issued our
report thereon dated November 4, 1999 (except with respect to the matters
discussed in Note 13, as to which the date is December 17, 1999).
Our audit was made for the purpose of forming an opinion on those
statements taken as a whole. The schedules listed in the index are the
responsibility of the Registrant's management and are presented for purposes of
complying with the Securities and Exchange Commission's rules and are not part
of the basic financial statements. These schedules have been subjected to the
auditing procedures applied in the audit of the basic financial statements and,
in our opinion, fairly state in all material respects the financial data
required to be set forth therein in relation to the basic financial statements
taken as a whole.
s/Arthur Andersen LLP
Charlotte, North Carolina
November 4, 1999
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED BALANCE SHEETS
- -------------------------------------------------------------------------- ------------------------ --------------------------
Successor Predecessor
December 31, December 31,
Millions of dollars 2000 1999
- -------------------------------------------------------------------------- ------------------------ --------------------------
Assets
Gas Utility Plant (Note 1) $787 $768
Less - Accumulated depreciation 263 245
Acquisition Adjustment, net of accumulated amortization (Notes 1 & 3) 452 -
- -------------------------------------------------------------------------- ------------------------ --------------------------
Gas Utility Plant, Net 976 523
- -------------------------------------------------------------------------- ------------------------ --------------------------
Nonutility Property and Investments, net of accumulated depreciation 34 31
- -------------------------------------------------------------------------- ------------------------ --------------------------
Current Assets:
Cash and temporary investments (Note 1) 7 9
Restricted cash and temporary investments (Note 1) 5 3
Receivables (net of provisions for uncollectible accounts
of $2.4 million for 2000 and $2.7 million for 1999) 149 59
Inventories (at average cost):
Stored gas 32 29
Materials and supplies 7 7
Deferred gas costs, net (Note 2) 9 27
Other 1 1
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total Current Assets 210 135
- -------------------------------------------------------------------------- ------------------------ --------------------------
Deferred Charges and Other Assets:
Due from affiliate-pension asset (Note 6) 10 -
Other 18 9
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total Deferred Charges and Other Assets 28 9
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total $1,248 $698
========================================================================== ------------------------ ==========================
========================================================================== ------------------------ ==========================
Capitalization and Liabilities
Capitalization:
Common equity (Note 9) $712 $232
Long-term debt, net (Notes 7 & 11) 145 151
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total Capitalization 857 383
- -------------------------------------------------------------------------- ------------------------ --------------------------
Current Liabilities:
Short-term borrowings (Notes 8 & 11) 125 138
Current portion of long-term debt (Note 7) 4 7
Accounts payable 84 50
Accrued taxes 3 5
Customer prepayments and deposits 8 7
Advances from parent 44 -
Dividends declared and interest accrued 5 8
Other 6 2
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total Current Liabilities 279 217
- -------------------------------------------------------------------------- ------------------------ --------------------------
Deferred Credits and Other Liabilities:
Deferred income taxes, net (Notes 1 & 10) 82 75
Deferred investment tax credits (Notes 1 & 10) 3 3
Accrued pension cost (Note 6) - 3
Due to affiliate-postretirement benefits (Note 6) 10 -
Other 17 17
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total Deferred Credits and Other Liabilities 112 98
- -------------------------------------------------------------------------- ------------------------ --------------------------
Total $1,248 $698
========================================================================== ------------------------ ==========================
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
- ----------------------------------------------------------- --------------- -----------------------------------------------------
Successor Predecessor
- ----------------------------------------------------------- --------------- ----------------- -----------------------------------
Year Three Months
Ended Ended Fiscal Year Ended
December 31, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Operating Revenues $547 $81 $298 $330
Cost of Gas 375 41 133 174
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Gross Margin 172 40 165 156
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Operating Expenses:
Operation and maintenance 67 18 71 60
Depreciation and amortization 42 7 26 25
Other taxes 6 2 15 17
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Total Operating Expenses 115 27 112 102
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Operating Income 57 13 53 54
Other Income, net 8 1 6 5
Interest Charges 20 5 18 18
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Income Before Income Taxes and
Cumulative Effect of Accounting Change 45 9 41 41
Income Taxes 24 4 17 16
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Income Before Cumulative Effect of Accounting Change 21 5 24 25
Cumulative Effect of Accounting Change, net of taxes
(Note 2) 7 - - -
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
Net Income 28 5 24 25
Retained Earnings at Beginning of Period 73 73 70 64
Acquisition of Company (73) - - -
Common Stock Cash Dividends Declared (19) (5) (21) (19)
- ----------------------------------------------------------- --------------- ----------------- ----------------- -----------------
=========================================================== =============== ================= ================= =================
Retained Earnings at End of Period $9 $73 $73 $70
=========================================================== =============== ================= ================= =================
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
- --------------------------------------------------------- ----------------- -----------------------------------------------------
Successor Predecessor
- --------------------------------------------------------- ----------------- ------------------ ----------------------------------
Year Three Months
Ended Ended Fiscal Year Ended
December 31, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Cash Flows From Operating Activities:
Net income $28 $5 $24 $25
Adjustments to reconcile net income to net cash
provided from (used in) operating activities:
Cumulative effect of accounting change, net of
taxes (7) - - -
Depreciation and amortization 47 8 29 28
Over (under) collections, fuel adjustment
clause 9 - 5 (6)
Change in operating assets and liabilities:
(Increase) decrease in receivables, net (77) (49) (9) 11
(Increase) decrease in inventories (3) - (5) (3)
(Increase) decrease in deferred gas cost 5 (8) (5) 6
Increase (decrease) in accounts payable and
advances 78 39 5 (7)
Increase (decrease) in accrued pension cost - (1) (3) (2)
Increase (decrease) in postretirement payable 1 - - -
Increase (decrease) in deferred income
taxes, net 9 - 8 7
Other, net (14) - 1 (5)
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used In) Operating Activities 76 (6) 50 54
- --------------------------------------------------------- ----------------- ---------------- -----------------
------------------
Cash Flows From Investing Activities:
Construction expenditures (39) (12) (44) (65)
Sales of assets 5 - - -
Nonutility and other (1) (1) (5) (2)
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used For) Investing Activities (35) (13) (49) (67)
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Cash Flows From Financing Activities:
Issuance of common stock - - 6 10
Increase (decrease) in short-term borrowings, net (13) 34 34 33
Retirement of long-term debt and common stock (9) (8) (17) (10)
Cash dividends (21) (5) (20) (19)
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net Cash Provided From (Used For) Financing Activities (43) 21 3 14
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Net (Decrease) Increase in Cash and Temporary
Investments (2) 2 4 1
Cash and Temporary Investments at Beginning of Period 9 7 3 2
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
- --------------------------------------------------------- ----------------- ------------------ ---------------- -----------------
Cash and Temporary Investments at End of Period $7 $9 $7 $3
========================================================= ================= ================== ================ =================
Supplemental Cash Flow Information:
Cash paid during the period for:
Interest (net of capitalized interest of $1.0,
$0.1, $0.6 and $0.6) $21 $5 $18 $18
Income taxes 25 - 7 12
In connection with the acquisition of Public Service Company of North Carolina,
Inc. by SCANA Corporation, $21 million in common stock was cancelled. The
application of push-down accounting for the acquisition resulted in the
recording of a $466 million acquisition adjustment.
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
CONSOLIDATED STATEMENTS OF CAPITALIZATION
- -------------------------------------------------------------------------- ---------------- ----------------
Successor Predecessor
- -------------------------------------------------------------------------- ---------------- ----------------
December 31, (Millions of dollars) 2000 1999
- -------------------------------------------------------------------------- ---------------- ----------------
Common Equity:
Common stock, $1 par, 1,000 shares authorized and issued in 2000;
30,000,000 shares authorized, 20,577,967 shares issued in 1999 $- $21
Capital in excess of par value 703 138
Retained earnings 9 73
- -------------------------------------------------------------------------- ---------------- ----------------
Total Common Equity 712 232
- -------------------------------------------------------------------------- ---------------- ----------------
Long-term Debt:
Senior debentures (unsecured) -
10% due 2003 - 4
10% due 2004 17 22
8.75% due 2012 32 32
6.99% due 2026 50 50
7.45% due 2026 50 50
- -------------------------------------------------------------------------- ---------------- ----------------
149 158
Less - Current maturities (4) (7)
- -------------------------------------------------------------------------- ---------------- ----------------
Total Long-Term Debt, Net 145 151
- -------------------------------------------------------------------------- ---------------- ----------------
========================================================================== ================ ================
Total Capitalization $857 $383
========================================================================== ================ ================
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization and Principles of Consolidation
Public Service Company of North Carolina, Incorporated (PSNC), a public
utility, was organized as a North Carolina corporation in 1938. Effective
January 1, 2000 the acquisition of PSNC by SCANA Corporation (SCANA), a South
Carolina holding company, was consummated in a business combination accounted
for as a purchase. As a result, PSNC became a wholly owned subsidiary of SCANA
incorporated under the laws of South Carolina. PSNC is engaged predominantly in
the transportation, distribution and sale of natural gas to residential,
commercial and industrial customers in North Carolina.
The accompanying Consolidated Financial Statements include the accounts
of PSNC and its subsidiary companies, PSNC Production Corporation, SCANA Public
Service Company, L.L.C. (formerly Sonat Public Service Company, L.L.C.), Clean
Energy Enterprises, Inc., PSNC Blue Ridge Corporation, and PSNC Cardinal
Pipeline Company (collectively, the "Company"). The accounts of SCANA Public
Service Company, L.L.C. are included only for the period subsequent to their
acquisition (See Note 4). Investments in other affiliates in which the Company
has the ability to exercise influence over operating and financial policies are
accounted for under the equity method. Significant intercompany balances and
transactions have been eliminated in consolidation.
Affiliated Transactions
At December 31, 2000 PSNC had recorded $4.3 million in associated
company receivables and $1.7 million in associated company payables with various
SCANA subsidiaries. These amounts are included in PSNC's accounts receivable and
accounts payable, respectively.
B. Basis of Accounting
PSNC accounts for its regulated utility operations, assets and
liabilities in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) 71. This 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, PSNC has recorded, as of December 31, 2000,
approximately $21.0 million and $4.6 million of regulatory assets and
liabilities, respectively, including amounts recorded for deferred income tax
liabilities of approximately $0.4 million. The regulatory assets are recoverable
through rates. In the future, as a result of deregulation or other changes in
the regulatory environment, PSNC 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 PSNC'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 PSNC are maintained in accordance with the
Uniform System of Accounts prescribed by the National Association of Regulatory
Utility Commissioners (NARUC) and as adopted by the North Carolina Utilities
Commission (NCUC).
D. Change in Fiscal Year
PSNC changed its fiscal year end to December 31 from September 30,
effective January 1, 2000.
E. 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.
F. Allowance for Funds Used During Construction (AFC)
AFC, a noncash item, reflects the period cost of capital devoted to
plant under construction. This accounting practice results in the inclusion of,
as a component of construction cost, the cost of debt 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
calculated AFC composite rates were 6.8 percent for the year ended 2000, 6.4
percent for the three months ended December 31, 1999 and 5.5 percent and 5.9
percent for the fiscal years ended 1999 and 1998, respectively. These rates do
not exceed the maximum allowable rate as calculated under FERC Order No. 561.
G. Revenue Recognition
Revenues are recorded during the accounting period in which services
are provided to customers, and include estimated amounts for natural gas
delivered, but not yet billed. Prior to January 1, 2000 revenues related to
regulated gas services were recorded only as customers were billed. (See Note
2.)
PSNC's Rider D mechanism authorizes the recovery of all prudently
incurred gas costs from customers on a monthly basis. Any difference in amounts
paid and collected for these costs is deferred for subsequent refund to or
collection from customers. Additionally, PSNC can recover its margin losses on
negotiated gas sales to certain large commercial/industrial customers in any
manner authorized by the NCUC. At December 31, 2000 and 1999 PSNC had
undercollected from customers pursuant to Rider D approximately $9.3 million and
$16.7 million, respectively, which is in "Deferred Gas Costs, net."
PSNC'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. PSNC
establishes its commodity cost of gas for large commercial and industrial
customers on the basis of market prices for natural gas as approved by the NCUC.
H. Depreciation and Amortization
Provisions for depreciation and amortization are recorded using the
straight-line method and are based on the estimated service lives of the various
classes of property. The composite weighted average depreciation rates
approximate 4.1 percent for the year ended December 31, 2000, 4.1 percent for
the three months ended December 31, 1999 and 3.9 percent and 4.0 percent for the
fiscal years ended September 30, 1999 and 1998.
The acquisition adjustment related to the acquisition of PSNC by SCANA
is being amortized over a 35-year period using the straight-line method.
I. Income Taxes
In 2000 PSNC is included in the consolidated federal income tax return
of SCANA Corporation. Under a joint consolidated income tax allocation agreement
each subsidiary's current and deferred tax expense is computed on a stand-alone
basis. 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 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. Debt Expense
PSNC amortizes issuance costs for its debentures over the life of
the related debt. PSNC is amortizing the redemption premium and the unamortized
issuance costs on its previously refunded Series K First Mortgage Bonds over 15
years (1987-2002), in accordance with the treatment authorized by the NCUC.
K. Environmental
PSNC maintains an environmental assessment program to identify and
assess current and former operation sites that could require environmental
cleanup. As site assessments are initiated, estimates are made of the
expenditures, if any, deemed necessary to investigate and remediate 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 to regulated operations. Such amounts are deferred and amortized
with recovery provided through rates.
L. Cash and Temporary Investments
PSNC considers temporary cash investments having original maturities of
three months or less to be cash equivalents. Temporary cash investments may
include repurchase agreements, U.S. Treasury bills, federal agency securities,
certificates of deposit and high-grade commercial paper.
Since fiscal 1992, PSNC has received refunds from its pipeline
transporters for which the investment and use have been restricted by an order
of the NCUC. Pursuant to an order of the NCUC, these funds are segregated from
PSNC's general funds and will be used for expansion of PSNC's facilities into
unserved territories. These refunds, along with interest earned thereon, are
periodically transferred to the Office of the State Treasurer of North Carolina.
The balance not transferred is reported in restricted cash and temporary
investments.
At December 31, 2000 the balance in restricted cash and temporary
investments includes approximately $4.5 million in supplier refunds to be
returned to customers in the form of a bill credit during the first quarter of
2001. This refund to customers was approved by the NCUC to help defray the
unusually high cost of natural gas experienced during the most recent heating
season.
M. Recently Issued Accounting Standard and Bulletin
In June 1998 the Financial Accounting Standards Board (FASB) issued
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." In
June 2000 the FASB issued SFAS 138, which amends certain provisions of SFAS 133
to expand the normal purchase and sale exemption for supply contracts and to
redefine interest rate risk to reduce sources of ineffectiveness, among other
things. PSNC's adoption of SFAS 133, as amended, on January 1, 2001 did not have
a material impact on PSNC's results of operations, cash flows or financial
position.
In December 1999 Staff Accounting Bulletin No. 101, "Revenue Recognition
in Financial Statements" was issued by the Securities and Exchange Commission
(SEC), and provides the SEC staff's views in applying generally accepted
accounting principles to selected revenue recognition issues. PSNC's adoption of
this bulletin in the fourth quarter of 2000 had no impact on its results of
operations, cash flows or financial position.
N. Reclassifications
Certain amounts from prior periods have been reclassified to conform
with the presentation adopted for 2000.
O. 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 amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE
Effective January 1, 2000 PSNC changed its method of accounting for
operating revenues associated with its regulated utility operations from cycle
billing to full accrual. The cumulative effect of this change was approximately
$6.6 million, net of taxes. Accruing unbilled revenues more closely matches
revenues and expenses. Unbilled revenues represent the estimated amount
customers will be charged for service rendered but not yet billed as of the end
of the accounting period. At December 31, 1999 the gas costs associated with
unbilled revenues were deferred. Beginning January 1, 2000 these costs are no
longer deferred.
If this method had been applied retroactively, net income would have
been $11.0 million for the three months ended December 31, 1999, compared to
$5.1 million , as previously reported. Further, if this method had been applied
retroactively to the fiscal years ended September 30 1999 and 1998, the impact
on net income would not have been material.
3. ACQUISITION BY SCANA CORPORATION
On February 10, 2000 the acquisition of PSNC by SCANA was
consummated in a business combination accounted for as a purchase. PSNC became a
wholly owned subsidiary of SCANA effective January 1, 2000. Pursuant to the
Agreement and Plan of Merger, PSNC shareholders were paid approximately $212
million in cash and 17.4 million shares of SCANA common stock valued at
approximately $488 million.
PSNC has recorded a utility plant acquisition adjustment of
approximately $466 million, which reflects the excess of SCANA's purchase price
over the fair value of PSNC's net assets at January 1, 2000. The adjustment is
being amortized over 35 years on the straight-line basis. Common equity at
December 31, 2000 includes the effect of the acquisition adjustment.
PSNC agreed to pay approximately $5 million to ten key executives
under severance agreements related to the acquisition. Severance benefits of
approximately $2.7 million have been paid to seven key executives whose
positions were eliminated. In addition, approximately $3.1 million was paid to
former directors of PSNC in connection with deferred compensation and retirement
plans, and approximately $8.1 million was paid to participants in PSNC's
nonqualified stock option plans.
4. ACQUISITION OF SONAT PUBLIC SERVICE COMPANY
Effective December 31, 1999 PSNC Production Corporation (PSNC
Production), a wholly owned subsidiary of PSNC, purchased the remaining 50%
membership interest in Sonat Public Service Company, L.L.C. (Sonat). As a
result, Sonat became a wholly owned subsidiary of PSNC Production. PSNC
Production paid $5.3 million to acquire this interest. Sonat was subsequently
renamed SCANA Public Service Company, L.L.C. (SCANA Public Service).
5. RATE AND OTHER REGULATORY MATTERS
A. On April 6, 2000 the NCUC issued an order permanently approving
PSNC's request to establish its commodity cost of gas for large commercial and
industrial customers on the basis of market prices for natural gas. The NCUC
previously allowed PSNC use of this mechanism on a trial basis. This procedure
ensures that the amount paid by PSNC for natural gas to serve these customers
approximates the amount collected from them.
B. A state expansion fund, established by the North Carolina General
Assembly in 1991 and funded by refunds from PSNC's interstate pipeline
transporters, provides financing for expansion into areas that otherwise would
not be economically feasible to serve. On December 30, 1999 PSNC filed an
application with the NCUC to extend natural gas service to Madison, Jackson and
Swain Counties. 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. On June 29, 2000 the NCUC approved PSNC's requests for reinstatement of
its exclusive franchises for Madison, Jackson and Swain Counties and
disbursement of up to $28.4 million from PSNC's expansion fund for this project.
PSNC estimates that the cost of this project will be approximately $31.4
million.
C. On December 7, 1999 the NCUC issued an order approving the
acquisition of PSNC by SCANA. As specified in the NCUC order, PSNC reduced its
rates by approximately $1 million in August 2000, will reduce rates another $1
million in August 2001 and has agreed to a five-year moratorium on general rate
cases. General rate relief can be obtained during this period to recover costs
associated with materially adverse governmental actions and force majeure
events.
D. On February 22, 1999 the NCUC approved PSNC's application to use
expansion funds to extend natural gas service into Alexander County, and
authorized disbursements from the fund of approximately $4.3 million based upon
budgeted construction cost of approximately $6.2 million. Most of Alexander
County lies within PSNC's certificated service territory and did not previously
have natural gas service. The project was completed and customers began
receiving natural gas service in March 2000.
E. On October 30, 1998 the NCUC issued an order in PSNC's general rate
case filed in April 1998. The order, effective November 1, 1998, granted PSNC
additional revenue of $12.4 million and allowed a 9.82 percent overall rate of
return on PSNC's net utility investment. It also approved the continuation of
the Weather Normalization Adjustment (WNA) and Rider D mechanisms and full
margin transportation rates. PSNC's Rider D rate mechanism authorizes the
recovery of all prudently incurred gas costs from customers on a monthly basis.
Any difference in amounts paid and collected for these costs is deferred for
subsequent refund to or collection from customers. On February 4, 2000 in
response to an appeal by the Carolina Utility Customers Association, Inc., the
Supreme Court of North Carolina affirmed the NCUC order.
6. EMPLOYEE BENEFIT PLANS AND STOCK COMPENSATION PLANS
Employee Benefit Plans
Since July 1, 2000 PSNC has participated in SCANA's
noncontributory defined benefit pension plan,
which covers substantially all permanent employees. SCANA's pension plan
benefits for PSNC employees are calculated using a cash balance formula under
which employees earn benefits through monthly compensation and interest credits.
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.
Also, since July 1, 2000 PSNC has participated in SCANA's plan to
provide certain unfunded health care and life insurance benefits to active and
retired employees. Retirees share in a portion of their medical care cost and
are provided life insurance benefits at no charge. The cost of postretirement
benefits other than pensions are accrued during the years the employees render
the service necessary to be eligible for the applicable benefits.
Prior to July 1, 2000 PSNC and its subsidiaries sponsored a noncontributory
defined benefit pension plan covering substantially all employees. The benefits
were based on years of service and the employee's compensation during the five
consecutive years of employment that produced the highest average pay.
Contributions to the plan were determined on an annual basis, with the amount of
such contributions being within the range of the minimum required funding amount
and the maximum amount deductible for Federal income tax purposes. Prior to July
1, 2000 PSNC also provided certain health care and life insurance benefits to
its employees. Retirees were required to contribute toward the costs of their
medical care coverage. The costs of postretirement benefits other than pensions
were accrued during the years the employees rendered the service necessary to be
eligible for the applicable benefits.
During the fiscal year ended September 30, 1999, PSNC recognized
pension gains of $1.8 million and a net curtailment loss on postretirement
benefit obligations of $0.5 million directly related to severance activity under
restructuring discussed further in Note 13.
The fair value of PSNC's common stock held by its plan at June 30,
2000, December 31, 1999, and September 30, 1999 measurement dates were
approximately $0.0 million, $1.4 million and $1.3, million respectively.
As discussed above, effective July 1, 2000, PSNC's pension and
postretirement plans were merged with SCANA's plans. At the time of the plan
mergers, PSNC had recognized a prepaid pension cost of approximately $9.0
million and a postretirement welfare plan obligation of approximately $9.1
million. For the period July 1 through December 31, 2000, PSNC's net periodic
benefit income was approximately $0.6 million income for the pension plan and
PSNC's net periodic benefit cost was approximately $0.7 million cost for the
postretirement plan.
Disclosures required for these PSNC's plans under SFAS 132 "Employer's
Disclosures about Pensions and Other Postretirement Benefits" for the periods
prior to the plan mergers are set forth in the following tables:
Components of Net Periodic Benefit Cost
Retirement Benefits
Six Months Three Months
Ended Ended Year Ended Year Ended
June 30, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- ------------------------------------ -------------------- --------------------- ---------------------- -----------------------
Service cost $0.8 $0.5 $2.3 $2.1
Interest cost 1.6 0.8 3.0 3.0
Expected return on plan assets (2.2) (0.8) (3.1) (2.7)
Prior service cost amortization - 0.1 0.6 0.6
Transition amount amortization - (0.1) (0.3) (0.3)
==================================== ==================== ===================== ====================== =======================
Net periodic benefit cost $0.2 $0.5 $2.5 $2.7
==================================== ==================== ===================== ====================== =======================
Other Postretirement Benefits
Six Months Three Months
Ended Ended Year Ended Year Ended
June 30, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- ------------------------------------ -------------------- --------------------- ---------------------- -----------------------
Service cost $0.1 $0.1 $0.3 $0.3
Interest cost 0.4 0.2 0.6 0.6
Prior service cost amortization - - 0.1 -
Transition amount amortization - - 0.2 0.2
==================================== ==================== ===================== ====================== =======================
Net periodic benefit cost $0.5 $0.3 $1.2 $1.1
==================================== ==================== ===================== ====================== =======================
Weighted-Average Assumptions
Retirement Benefits
Six Months Three Months
Ended Ended Year Ended Year Ended
June 30, December 31, September 30, September 30,
2000 1999 1999 1998
- ------------------------------------ -------------------- --------------------- ---------------------- ---------------------
Discount rate 8.00% 8.00% 7.50% 6.75%
Expected return on plan assets 9.50% 9.50% 8.00% 8.00%
Rate of compensation increase Age-related Age-related Age-related Age-related
Other Postretirement Benefits
Six Months Three Months
Ended Ended Year Ended Year Ended
June 30, December 31, September 30, September 30,
2000 1999 1999 1998
- ------------------------------------ -------------------- -------------------- ----------------------- -----------------------
Discount rate 8.00% 8.00% 7.50% 6.75%
Expected return on plan assets n/a n/a n/a n/a
Rate of compensation increase Age-related Age-related Age-related Age-related
Changes in Benefit Obligations
Retirement Benefits
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
Millions of dollars 2000 1999 1999
- --------------------------------------------------- -------------------- --------------------- ------------------------
Benefit obligation, beginning of period $38.7 $44.1 $46.6
Service cost 0.8 0.5 2.3
Interest cost 1.6 0.8 3.0
Settlement payments - - (7.2)
Benefits paid (2.5) (2.2) (0.5)
Curtailment gain - - (1.2)
Actuarial (gain) loss 1.3 (4.5) 1.1
- --------------------------------------------------- -------------------- --------------------- ------------------------
Benefit obligation at end of period $39.9 $38.7 $44.1
=================================================== ==================== ===================== ========================
Other Postretirement Benefits
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
Millions of dollars 2000 1999 1999
- --------------------------------------------------- --------------------- -------------------- ------------------------
Benefit obligation, beginning of period $8.9 $9.3 $9.0
Service cost 0.1 - 0.3
Interest cost 0.4 0.2 0.6
Benefits paid (0.3) (0.1) (0.6)
Curtailment gain - - (0.3)
Actuarial (gain) loss 2.1 (0.5) 0.3
- --------------------------------------------------- --------------------- -------------------- ------------------------
Benefit obligation at end of period $11.2 $8.9 $9.3
=================================================== ===================== ==================== ========================
Change in Plan Assets
Retirement Benefits
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
Millions of dollars 2000 1999 1999
- --------------------------------------------------- --------------------- -------------------- ------------------------
Fair value of plan assets, beginning of period $47.9 $45.0 $43.7
Actual return on plan assets 0.8 3.1 5.3
Company contribution - 2.0 3.7
Benefits paid (2.5) (2.2) (7.7)
- --------------------------------------------------- -------------------- --------------------- ------------------------
Fair value of plan assets at end of period $46.2 $47.9 $45.0
=================================================== ==================== ===================== ========================
Funded Status of Plans
Retirement Benefits
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
Millions of dollars 2000 1999 1999
- --------------------------------------------------- -------------------- --------------------- ------------------------
Funded status, beginning of period $6.3 $9.2 $0.9
Unrecognized actuarial (gain) loss 2.7 (14.4) (7.6)
Unrecognized prior service cost - 2.5 2.7
Unrecognized net transition obligation - (0.8) (1.0)
- --------------------------------------------------- -------------------- --------------------- ------------------------
Net asset (liability) recognized in
Consolidated Balance Sheet $9.0 $(3.5) $(5.0)
=================================================== ==================== ===================== ========================
Other Postretirement Benefits
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
Millions of dollars 2000 1999 1999
- ------------------------------------------------- --------------------- ------------------- ---------------------------
Funded status, beginning of period $(11.2) $(8.9) $(9.3)
Unrecognized actuarial (gain) loss 2.1 (0.5) 0.3
Unrecognized prior service cost - 0.4 0.4
Unrecognized transition obligation - 2.7 2.8
- ------------------------------------------------- -------------------- --------------------- --------------------------
Net asset (liability) recognized in
Consolidated Balance Sheet $(9.1) $(6.3) $(5.8)
================================================= ==================== ===================== ==========================
Health Care Trends
The determination of net periodic other postretirement benefit cost is based on
the following assumptions:
Six Months Three Months
Ended Ended Year Ended
June 30, December 31, September 30,
2000 1999 1999
- ------------------------------------------------- --------------------- ------------------- ---------------------------
Health care cost trend rate 8.00% 8.00% 7.75%
Ultimate health care cost trend rate 5.50% 5.50% 4.25%
Year achieved 2005 2005 2008
Stock Compensation Plans
Prior to SCANA's acquisition of PSNC effective January 1, 2000,
PSNC sponsored the stock-based compensation plans described below. PSNC
applied the intrinsic value method prescribed by Accounting Principles
Board Opinion No. 25, "Accounting for Stock Issued to Employees" and
related interpretations in accounting for grants made under the plans.
Because all options granted after September 30, 1997 were granted with
exercise prices equal to the fair market value of the Company's stock
on the respective grant dates, no compensation expense was recognized
in connection with such grants. If PSNC had determined compensation
expense for the issuance of options based on the fair value method
described in SFAS 123, "Accounting for Stock-Based Compensation," net
income would have been reduced to the pro forma amounts shown below:
Year Ended September 30,
Millions of dollars 1999 1998
--------------------- --------------------------------------------
Net income As reported $24.5 $24.8
Pro forma $23.7 $23.6
Nonqualified Stock Option Plans
PSNC sponsored a 1992 Nonqualified Stock Option Plan (1992 Plan)
and a 1997 Nonqualified Stock Option Plan (1997 Plan). In accordance
with the 1992 Plan, options to purchase PSNC common stock could have
been granted to officers and key employees of PSNC at 90 percent of the
fair market value of the stock determined on the date of the grant.
Under the 1997 Plan, options to purchase PSNC's common stock could have
been granted to officers and key employees of PSNC at the fair market
value of the stock determined on the date of the grant. Options from
the 1992 Plan and the 1997 Plan were exercisable beginning two years
from the date of the grant and expired five years from the date of the
grant.
In addition, upon a change in control event, which occurred with
shareholder approval of PSNC's acquisition by SCANA, all outstanding
options became exercisable on July 1, 1999.
Options granted, exercised and canceled under both plans for the
periods indicated were as follows:
Options Weighted-Average
Outstanding Exercise Price
--------------------------------------------------- --------------------------
September 30, 1997 463,938 $14.54
Granted 624,000 $20.64
Exercised (111,375) $14.60
Canceled (20,879) $16.88
--------------------------------------------------- --------------------------
September 30, 1998 955,684 $18.46
Granted - -
Exercised (149,212) $14.66
Canceled (101,680) $20.54
--------------------------------------------------- --------------------------
September 30, 1999 704,792 $18.97
Granted - -
Exercised (60,647) $12.86
Canceled - -
--------------------------------------------------- --------------------------
--------------------------------------------------- --------------------------
December 31,1999 644,145 $19.08
Granted - -
Exercised (644,145) $19.08
Canceled - -
--------------------------------------------------- --------------------------
=================================================== ==========================
December 31, 2000 - -
=================================================== ==========================
For purposes of pro forma disclosure, the weighted average fair
value at grant date (the value at grant date of the right to purchase
stock at a fixed price for an extended time period) for options granted
in 1998 was estimated using the Black-Scholes options pricing model
with the following weighted average assumptions:
Risk free interest rates(s) 5.5% and 5.8%
Volatility factor 15.30%
Dividend yield 4.53%
Expected life 4.5 years
The weighted average fair value of nonqualified stock options
granted during fiscal 1998 was $2.54. At September 30, 1998, 231,403
options were exercisable at a weighted average price of $13.49. At
September 30 and December 31, 1999, all outstanding options were
exercisable at the weighted average prices indicated above. As of
December 31, 1999, the 644,145 outstanding options had a weighted
average remaining contractual life of 2.6 years and exercise prices
ranging from $12.86 to $21.25.
Employee Stock Purchase Plan
Under the 1992 Employee Stock Purchase Plan, as amended, PSNC
was authorized to issue common stock to its full-time employees, nearly
all of whom were eligible to participate, at a purchase price equal to
90 percent of such common stock's fair value. This plan was terminated
effective June 30, 1999. In fiscal 1999 and 1998, PSNC issued to
employees 62,355 and 82,203 shares, respectively.
For purposes of pro forma disclosure, the weighted average fair
value at grant date for employee stock options granted was estimated
using the Black-Scholes option pricing model with the following
weighted average assumptions:
1999 1998
------------------------------------------- ---------------------
Risk free interest rate 4.58% 5.43%
Volatility factor 14.96% 15.30%
Dividend yield 3.85% 4.53%
Expected life 1 year 1 year
The weighted average fair value of each employee stock purchase
plan grant during fiscal 1999 and 1998 was $6.52 and $6.10,
respectively.
7. LONG-TERM DEBT
The annual amounts of long-term debt maturities for the years
2001 through 2005 are summarized as follows:
----------------- ----------------- ------------------ -----------------
Year Amount Year Amount
----------------- ----------------- ------------------ -----------------
(Millions of Dollars)
2001 $4.3 2004 $7.5
2002 4.3 2005 3.2
2003 7.5
----------------- ----------------- ------------------ -----------------
Under the terms of the debt agreements, there are various
provisions relating to the maintenance of certain financial ratios and
conditions, the most significant of which could restrict payment of
dividends. At December 31, 2000, PSNC is in compliance in all material
respects with the requirements of its debt agreements.
8. SHORT-TERM BORROWINGS
PSNC pays fees to banks as compensation for its committed lines of
credit. Commercial paper borrowings are for 270 days or less. At December 31,
2000 committed lines of credit under revolving credit agreements which expire
July 27, 2001 were $125 million. Unused lines of credit were $125 million.
Short-term borrowings through commercial paper at December 31, 2000 were $125
million at a weighted average interest rate of 6.69 percent.
At December 31, 1999 PSNC had committed lines of credit with five
commercial banks and a five-year revolving line of credit with one bank. PSNC
also had uncommitted annual lines of credit. PSNC paid fees to banks as
compensation for its committed lines of credit. At December 31, 1999 PSNC had
authorized lines of credit (committed and uncommitted) of $195 million, which
included unused lines of credit of $57.5 million and short-term borrowings of
$137.5 million at a weighted average interest rate of 5.74 percent.
9. COMMON EQUITY
The changes in "Common Equity" during the year ended December 31, 2000,
the three months ended December 31, 1999 and fiscal years ended September 30,
1999 and 1998 are summarized as follows:
Common Shares Millions of Dollars
- --------------------------------------------------------------------------------
Balance at September 30, 1997 19,770,843 $207.4
Changes in Retained Earnings:
Net income 24.8
Cash Dividends Declared (19.2)
Issuance of Stock 503,489 9.8
- --------------------------------------------------------------------------------
Balance at September 30, 1998 20,274,332 222.8
Changes in Retained Earnings
Net Income 24.5
Cash Dividends Declared (20.8)
Issuance of Stock 303,635 6.7
- --------------------------------------------------------------------------------
Balance at September 30, 1999 20,577,967 233.2
Changes in Retained Earnings:
Net Income 5.1
Cash Dividends Declared (6.0)
- ----------------------------------------------- --------------
Balance at December 31, 1999 20,577,967 232.3
Cancellation of Shares Due
to Acquisition (20,576,967) 470.9
Other Changes in Retained Earnings:
Net Income 27.8
Cash Dividends Declared (19.0)
- -------------------------------------------------------------------------------
Balance at December 31, 2000 1,000 $712.0
============================================================== ======= =========
10. INCOME TAXES
Total income tax expense attributable to income before cumulative effect
of accounting change for the periods indicated is as follows:
Successor Predecessor
- --------------------------------------------------- ---------------- ---------------------------------------------------
Year Three Months
Ended Ended Fiscal Year Ended
December 31, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Current taxes:
Federal $18.6 $2.9 $9.0 $7.9
State 3.9 0.6 2.1 1.8
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Total current taxes 22.5 3.5 11.1 9.7
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Deferred taxes, net:
Federal 1.5 0.6 5.4 5.6
State 0.3 0.1 1.2 1.3
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Total deferred taxes 1.8 0.7 6.6 6.9
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Investment tax credits:
Amortization of amounts deferred - Federal (0.4) - (0.4) (0.4)
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Total investment tax credits (0.4) - (0.4) (0.4)
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Total income tax expense $23.9 $4.2 $17.3 $16.2
=================================================== ================ ================= ================= ===============
The difference between actual income tax expense and the amount
calculated from the application of the statutory Federal income tax rate (35%
for 2000, 1999 and 1998) to pre-tax income before cumulative effect of
accounting change is reconciled as follows:
Successor Predecessor
- --------------------------------------------------- ---------------- ---------------------------------------------------
Year Three Months
Ended Ended Fiscal Year Ended
December 31, December 31, September 30, September 30,
Millions of dollars 2000 1999 1999 1998
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
Income before cumulative effect
of accounting change $21.2 $5.1 $24.1 $24.8
Total income tax expense:
Charged to operating expense 20.6 3.8 15.3 15.1
Charged to other income 3.3 0.4 2.0 1.1
=================================================== ================ ================= ================= ===============
Total pre-tax income 45.1 9.3 41.4 41.0
=================================================== ================ ================= ================= ===============
=================================================== ================ ----------------- ================= ===============
Income taxes on above at statutory
Federal income tax rate 15.8 3.3 14.5 14.4
Increases (decreases) attributed to:
State income taxes (less Federal income tax
effect) 2.8 0.5 2.1 2.0
Non-deductible book amortization
of acquisition adjustments 4.7 - - -
Amortization of Federal investment tax credits (0.4) - (0.4) (0.4)
Other differences, net 1.0 0.4 1.1 0.2
- --------------------------------------------------- ---------------- ----------------- ----------------- ---------------
=================================================== ================ ================= ================= ===============
Total income tax expense $23.9 $4.2 $17.3 $16.2
=================================================== ================ ================= ================= ===============
The tax effects of significant temporary differences comprising PSNC's net
deferred tax liability of $80.7 million at December 31, 2000 and $73.8 million
at December 31, 1999 (see Note 1I), are as follows:
Successor Predecessor
- --------------------------------------------------------------------------
Millions of dollars 2000 1999
- --------------------------------------------------------------------------
Deferred tax assets:
Unamortized investment tax credits $1.0 $1.1
Other postretirement benefits - 2.1
Pension costs - 2.0
Deferred compensation - 1.0
Other 2.9 4.2
- ---------------------------------------------------------------- ---------
Total deferred tax assets 3.9 10.4
- ---------------------------------------------------------------- ---------
Deferred tax liabilities:
Property, plant and equipment 82.2 80.6
Other 2.4 3.6
- ---------------------------------------------------------------- ---------
Total deferred tax liabilities 84.6 84.2
- ---------------------------------------------------------------- --------
Net deferred tax liability $80.7 $73.8
================================================================ =========
11. FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of PSNC's financial
instruments at December 31, 2000 and 1999 are as follows:
Millions of dollars 2000 1999
------------------------------------------- ----------------------------- ------------------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
------------------------------------------- -------------- -------------- --------------- --------------
Assets:
Cash and temporary cash investments $7 $7 $9 $9
Liabilities:
Short-term borrowings 125 125 138 138
Long-term debt 149 154 157 156
The information presented herein is based on pertinent information
available as of December 31, 2000 and 1999. Although PSNC 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,
2000, and the current estimated fair value may differ significantly from the
estimated fair value 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 are valued at their carrying amounts.
o Fair values of long-term debt are based on quoted market prices of the
instruments. Settlement of long-term debt may not be possible or may not
be considered prudent.
o Short-term borrowings are valued at their carrying amounts.
12. COMMITMENTS AND CONTINGENCIES
PSNC owns, or has owned, all or portions of seven sites in North Carolina
on which manufactured gas plants (MGP) 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. An environmental due diligence
review of PSNC conducted in February 1999 estimated that the cost to remediate
the remaining sites would range between $11.3 million and $21.9 million. During
the second quarter of 2000, the review was finalized and the estimated liability
was recorded. 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. 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 potentially responsible parties (PRP). 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 December 31, 2000,
PSNC has recorded a liability and associated regulatory asset of $10.2 million,
which reflects the minimum amount of the range, net of shared cost recovery from
other PRPs. Amounts incurred to date are not material. Management intends to
request recovery in future rate case filings of MGP cleanup costs incurred and
not recovered from other PRPs and believes that all costs incurred will be
recoverable in gas rates.
13. RESTRUCTURING
During fiscal 1999, PSNC recorded net restructuring charges of $4.3
million. These charges consisted of severance benefits of $3.7 million, a
one-time payment to 152 employees of $1 million in connection with an automobile
fleet restructuring, a net curtailment loss from these matters can currently be
determined.
51
11.on postretirement benefit
obligations of $.5 million offset by pension gains of $1.8 million and $.8
million of other restructuring charges.
14. SEGMENT OF BUSINESS INFORMATION:
Segment information atINFORMATION
PSNC's reportable segments are listed in the following table. Gas
Distribution uses operating income to measure profitability, while Energy
Marketing, which is comprised solely of SCANA Public Service (formerly Sonat),
uses net income to measure profitability. Affiliate revenue is derived from
transactions between reportable segments. Prior to December 31, 1995, 19941999 Sonat was
an equity investment and 1993not a segment of business (see Note 4). PSNC did not
have deferred tax assets for any period reported. For 2000, adjustments to net
income and income tax expense include the cumulative effect of the accounting
change described in Note 2.
Disclosure of Reportable Segments
Millions of dollars
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
Year Ended Gas Energy All Adjustments/ Consolidated
December 31, 2000 Distribution Marketing Other Eliminations Total
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
External Revenue $432 $141 $ - $(26) $547
Intersegment Revenue - 1 30 (31) -
Deprec. & Amort. 42 - - - 42
Operating Income 54 n/a n/a 3 57
Interest Expense 20 - - - 20
Net Income n/a 2 5 21 28
Segment Assets 1,231 35 72 (90) 1,248
Expenditures for
Assets 39 - 1 - 40
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
Three months Ended Gas Energy All Adjustments/ Consolidated
December 31, 1999 Distribution Marketing Other Eliminations Total
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
External Revenue $81 n/a - - $81
Intersegment Revenue - n/a $27 $(27) -
Deprec. & Amort. 7 n/a - - 7
Operating Income 13 n/a n/a - 13
Interest Expense 5 n/a - - 5
Net Income n/a n/a - 5 5
Segment Assets 678 20 58 (58) 698
Expenditures for
Assets 12 n/a 1 - 13
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
Fiscal Year Ended Gas Energy All Adjustments/ Consolidated
September 31, 1999 Distribution Marketing Other Eliminations Total
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
External Revenue $298 n/a $6 $(6) $298
Intersegment Revenue - n/a 39 (39) -
Deprec. & Amort. 26 n/a 1 (1) 26
Operating Income 53 n/a n/a - 53
Interest Expense 18 n/a - - 18
Net Income n/a n/a 2 22 24
Segment Assets 637 n/a 46 (34) 649
Expenditures for
Assets 44 n/a 5 - 49
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
Fiscal Year Ended Gas Energy All Adjustments/ Consolidated
September 31, 1998 Distribution Marketing Other Eliminations Total
- ------------------------------ ------------------- ---------------- -------------- ------------------- --------------------
External Revenue $330 n/a - - $330
Intersegment Revenue - n/a $87 $(87) -
Deprec. & Amort. 25 n/a 1 (1) 25
Operating Income 54 n/a n/a - 54
Interest Expense 18 n/a - - 18
Net Income n/a n/a 1 24 25
Segment Assets 606 n/a 34 (21) 619
Expenditures for
Assets 65 n/a 2 - 67
15. SUBSEQUENT EVENTS
PSNC Production Corporation and SCANA Public Service Company LLC were
sold to SCANA Energy Marketing, Inc., a subsidiary of SCANA Corporation for $4.4
million, which approximates net book value, effective January 1, 2001.
On February 16, 2001 PSNC issued $150 million of medium-term notes
having an annual interest rate of 6.625 percent and maturing on February 15,
2011. The proceeds from these borrowings were used to reduce short-term debt and
for the years then ended is as follows:
1995
Electric Gas Transit Total
(Thousandsgeneral corporate purposes.
16. QUARTERLY FINANCIAL DATA (UNAUDITED)
(Millions of Dollars)
Operating revenues $1,006,566 $ 200,632 $ 3,889 $1,211,087
Operating expenses,
excluding depreciation
and amortization 657,452 169,768 10,429 837,649
Depreciation and
amortization 103,961 12,616 1,007 117,584dollars, except per share amounts)
- -------------------------------------------------------- ------------------------------------------------------------
Year Ended December 31, 2000 First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------------- ----------- ------------ ----------- ----------- -----------
Total operating revenues $171 $80 $76 $220 $547
Operating income (loss) 37(1) (2) (7) 29 57
Cumulative effect of accounting change, net of taxes 7 - - - 7
Net income (loss) 26 (5) (8) 15 28
Three Months Ended December 31, 1999
- -------------------------------------------------------- -----------
Total operating expenses 761,413 182,384 11,436 955,233revenues $81
Operating income (loss) $ 245,153 $ 18,248 $ (7,547) 255,854
Add - Other income, net 9,553
Less - Interest charges 96,22213
Net income $ 169,185
Capital expenditures:
Identifiable $ 245,016 $ 19,670 $ 265 $ 264,951
Utilized for overall Company operations 27,816
Total $ 292,767
Identifiable assets at
December 31, 1995:
Utility plant, net $2,850,647 $ 209,847 $ 1,878 $3,062,372
Inventories 76,697 2,155 561 79,413
Total $2,927,344 $ 212,002 $ 2,439 3,141,785
Other assets 660,648
Total assets $3,802,433
1994
Electric Gas Transit Total
(Thousands(loss) 5
- ---------------------------------------------------------------------------------------------------
First Second Third Fourth
Fiscal Year Ended September 30, 1999 Quarter Quarter Quarter Quarter Annual
- -------------------------------------------------- ------------ ----------- ----------- -----------
Total operating revenues $73 $135 $54 $37 $299
Operating income (loss) 10 40 7 (3) 54
Net income (loss) 4 22 2 (3) 25
(1)Excludes $14 million of Dollars)
Operating revenues $975,526 $201,746 $ 4,002 $1,181,274
Operating expenses,
excluding depreciation
and amortization 659,610 173,717 10,577 843,904
Depreciation and
amortization 95,666 11,060 226 106,952
Totalincome taxes formerly reported in first quarter
operating expenses 755,276 184,777 10,803 950,856
Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418
Add - Other income, net 7,271
Less - Interest charges 85,646
Net income $ 152,043
Capital expenditures:
Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780
Utilized for overall Company operations 20,167
Total $ 420,947
Identifiable assets at
December 31, 1994:
Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956
Inventories 85,113 2,605 495 88,213
Total $2,802,260 $203,623 $ 2,286 3,008,169
Other assets 578,922
Total assets $3,587,091
52income.
1993
Electric Gas Transit Total
(Thousands of Dollars)
Operating revenues $ 940,547 $174,035 $ 3,851 $1,118,433
Operating expenses,
excluding depreciation
and amortization 639,808 148,349 9,737 797,894
Depreciation and
amortization 91,142 9,903 175 101,220
Total operating expenses 730,950 158,252 9,912 899,114
Operating income (loss) $ 209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585
Less - Interest charges 79,936
Net income $ 145,968
Capital expenditures:
Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934
Total $ 300,620
Identifiable assets at
December 31, 1993:
Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603
Inventories 66,181 2,526 463 69,170
Total $2,511,647 $180,990 $2,136 2,694,773
Other assets 495,166
Total assets $3,189,939
53
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
1995
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $308,759 $275,139 $339,937 $287,252 $1,211,087
Operating income 67,189 53,153 87,023 48,489 255,854
Net Income 45,249 30,870 65,040 28,026 169,185
1994
(Thousands of Dollars)
First Second Third Fourth
Quarter Quarter Quarter Quarter Annual
Total operating
revenues $313,321 $263,033 $327,066 $277,854 $1,181,274
Operating income 63,520 43,316 79,133 44,449 230,418
Net Income 45,340 24,348 57,619 24,736 152,043
54PART II, ITEM 9 AND PART III
SCANA CORPORATION
SOUTH CAROLINA ELECTRIC & GAS COMPANY
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONEDISCLOSURE:
SCANA: None
SCE&G: None
PSNC filed on April 3, 2000 a Current Report on Form 8-K dated March 27,
2000 changing its certifying accountants.
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 23 herein. The other
information required by Item 10 is incorporated herein by reference, to the
captions "Proposal 1 - Nominees For Class II Directors", "Continuing Directors",
and "Other Information - Section 16(a) Beneficial Ownership Reporting
Compliance" in SCANA's definitive proxy statement for the 2001 annual meeting of
shareholders which was 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 27, 19952000 (except as
otherwise indicated) to hold office until the next annual meeting of the Company'sSCE&G's
stockholders on April 25, 1996.May 3, 2001.
Name and Year First
Became Director Age Principal Occupation; Directorships
Bill L. Amick 5257 For more than five years, Chairman of the Board
(1990) Board and Chief Executive Officer of Amick Farms,
Inc., Amick Processing, Inc. and Amick Broilers,
Inc., Batesburg, SC (vertically integrated
broiler operation).
For more than five years, Chairman and Chief
Executive Officer of Amick Processing, Inc.
and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.;
Public Service Company of North Carolina, Inc.,
(PSNC), Gastonia, NC; Blue Cross and Blue Shield
of South Carolina, Columbia, SC.
James A. Bennett Since May 2000, President and Chief Executive
(1997) 40 Officer of South Carolina Community Bank,
Columbia, SC.
From February 10, 2000 to May 2000, Economic
Development 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, Columbia, SC; PSNC,
Gastonia, NC.
William B. Bookhart,
Jr. 54(1979) 59 For more than five years, a partner in
(1979) Bookhart
Farms, Elloree, SC (general farming).
Director, SCANA Corporation, Columbia, SC.SC; PSNC,
Gastonia, NC.
Name and Year First
Became Director Age Principal Occupation; Directorships
William T. Cassels, Jr. 66 For more than five years, ChairmanC. Burkhardt 63 Since May 2000, retired President and Chief ,
(2000) Executive Officer of the
(1990) Board, Southeastern Freight Lines,Austin Quality Foods, Inc.,
Columbia, SC (trucking business).
Cary, NC (production and distribution of baked
snacks)
Director, SCANA Corporation, Columbia, SC;
South Carolina National Corporation,
Columbia, SC; WachoviaPSNC, Gastonia, NC; Capital Bank, of South
Carolina, N.A., Columbia, SC.Raleigh, NC.
Hugh M. Chapman 6368 Since January 1, 1992, Chairman ofJune 30, 1997, retired from NationsBank
(1988) NationsBank South, Atlanta, GA (a division of NationsBank
Corporation, bank holding company).
From September 1, 1990For more than five years prior to December 31, 1991,
ViceJune 30, 1997
Chairman andof NationsBank South.
Director, C&S/SovranSCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; West Point-Stevens, West
Point, GA; PrintPack, Inc., Atlanta, GA.
PriorGA; The
Williams Companies, Inc., Tulsa, OK.
Elaine T. Freeman 65 For more than five years, Executive Director of (1992)
ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg, SC
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; National Bank of South
Carolina (a member bank of Synovus Financial
Corporation), Columbia, SC.
Lawrence M. Gressette,Jr. 69 Since February 28, 1997, Chairman Emeritus of
(1987) SCANA Corporation, Columbia, SC.
For more than five years prior to September 1, 1990, President and
Director, Citizens & Southern
Corporation, Atlanta, GA andFebruary 28,
1997, Chairman of the Board Citizens & Southern
South Carolina Corporation, Columbia,
SC.and Chief
Executive Officer of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC.
55SC;
PSNC, Gastonia, NC.
D. Maybank Hagood 39 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 61 For more than five years, Chairman, President
(1983) and Chief Executive Officer, The Liberty .
Corporation, Greenville, SC (broadcasting
holding company)
Director, SCANA Corporation, Columbia, SC;
PSNC, Gastonia, NC; The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC.
Lynne M. Miller 49 Since February 1998, Chief Executive Officer of
(1997) Environmental Strategies Corporation, Reston,
VA (environmental consulting and engineering
firm).
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, (a
Subsidiary of Abigail Adams National Bancorp,
Inc.), Washington, DC.
Name and Year First
Became Director Age Principal Occupation; Directorships
James B. Edwards, D.M.D. 68 For more than five years, President and
(1986) Professor of Maxillofacial Surgery,
Medical University of South Carolina,
Charleston, SC.
U.S. Secretary of Energy from January
1981 to November 1982.
Governor of South Carolina, 1975-1979.
Director, Phillips Petroleum Co.,
Bartlesville, OK; WMX Technologies, Inc.,
Oak Brook, IL; General Engineering
Laboratories, Inc., Charleston SC;
GS Industries, Inc., Charlotte, NC; IMO
Industries, Inc., Lawrenceville, NJ;
National Data Corporation, Atlanta, GA;
SCANA Corporation, Columbia, SC.
Elaine T. Freeman 60 For more than five years, Executive Director
(1992) of ETV Endowment of South Carolina, Inc.
(non-profit organization), Spartanburg,
SC.
Director National Bank of South Carolina,
Columbia, SC; SCANA Corporation,
Columbia, SC.
Lawrence M. Gressette, Jr. 64Maceo K. Sloan 51 For more than five years, Chairman, of the
(1987) BoardPresident
(1997) and Chief Executive Officer of SCANA CorporationSloan Financial
Group, Inc. (holding company) and Chairman
of the Board and
Chief Executive Officer of allNCM Capital
Management Group, Inc. (investment company),
Durham, NC.
Director, SCANA subsidiaries,
including the Company.
For more than five years priorCorporation, Columbia, SC;
PSNC, Gastonia, NC; M&F Bankcorp, Inc., and
Its subsidiary, Mechanics and Farmers Bank,
Durham, NC; NetDirect, Minneapolis, MN., and
Trustee of Teachers Insurance Annuity
Association - College Retirement Equity
Fund (TIAA- CREF).
Harold C. Stowe 54 Since March 1997, President and Chief
(1999) Executive Officer of Canal Industries, Inc.,
Conway, SC (forest products industry).
From 1996 to December 13, 1995,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.
William B. Timmerman 54 Since March 1, 1997, Chairman and Chief
(1991) Executive Officer of SCANA Corporation,
Columbia, SC.
From at least March 1, 1996, President of
SCANA Corporation.
Director, Wachovia Corporation, Winston-
Salem, NC; InterCel, Inc., West Point, GA;
The Liberty Corporation, Greenville, SC;
SCANA Corporation, Columbia, SC.
Benjamin A. Hagood 68 Since JanuaryFrom August 21, 1996 to March 1, 1993, Chairman of the
(1974) Board William M. Bird and Company, Inc.,
Inc., Charleston, SC (wholesale
distributor of floor covering material).
For more than two years prior to January 1,
1993, President and Director, William M.
Bird and Company, Inc., Charleston, SC.
Director, SCANA Corporation, Columbia, SC.
56
Name and Year First
Became Director Age Principal Occupation; Directorships
W. Hayne Hipp 56 For more than five years, President and
(1983) Chief Executive Officer, The Liberty
Corporation, Greenville, SC (insurance
and broadcasting holding company).
Director, The Liberty Corporation,
Greenville, SC; Wachovia Corporation,
Winston-Salem, NC; SCANA Corporation,
Columbia, SC.
Bruce D. Kenyon 53 For more than five years, President and
(1991)1997, Chief
Operating Officer of the Company.
Director, SCANA Corporation, Columbia, SC.
F. Creighton McMaster 66 For more than five years, President and
(1974) Manager, Winnsboro Petroleum Company,
Winnsboro, SC (wholesale distributor
of petroleum products).
Director, First Union National Bank of
South Carolina, Greenville, SC; SCANA
Corporation, Columbia, SC.
Henry Ponder, Ph.D. 67 For more than five years, President, Fisk
(1983) University, Nashville, TN.
Director, Suntrust Banks, Inc., Nashville,
TN; SCANA Corporation, Columbia, SC.
John B. Rhodes 65 For more than five years, Chairman and
(1967) Chief Executive Officer, Rhodes Oil
Company, Inc., Walterboro, SC
(distributor of petroleum products).
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 49 Since December 13, 1995, President of SCANA
(1991) Corporation.
From May 1, 1994 to December 13, 1995,
Executive Vice President of SCANA
Corporation.
Since August 25, 1993, Assistant Secretary
of SCANA Corporation and all of its
subsidiaries, including the Company.
From August 28, 1991 to February 20, 1996,
Chief Financial Officer of the Company.
For more than five years prior to May 1,
1994, Senior Vice President of SCANA
SCANA Corporation.
For more than five years prior to February
20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC;
InterCel,PSNC, Gastonia, NC; Powertel, Inc., West
Point, GA.
57
Name and Year First
Became Director Age Principal Occupation; Directorships
E. Craig Wall, Jr. 58GA; ITC^DeltaCom, Inc. West Point, GA;
The Liberty Corporation, Greenville, SC.
G. Smedes York 60 For more than five years, President and (1982) Director, Canal Industries, Conway, SC
(forest products industry)(2000) Raleigh,
NC.Treasurer of York Properties, Inc.
(full-service commercial and residential real
estate company).
Director, Sonoco Products Company,
Hartsville, SC; Ruddick Corporation,
Charlotte, NC; Nationsbank Corp.,
Charlotte, NC; Blue Cross/Blue Shield of
South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC.
58
EXECUTIVE OFFICERS OF THE COMPANY
The Company's officers are elected at the annual organizational meetingSC;
PSNC, Gastonia, NC.
Charles E. Zeigler, Jr. 54 Since February 2000, President and Chief
(2000) Operating Officer of the Board of Directors and hold office until the next such organizational
meeting, unless the Board of Directors shall otherwise determine, or unless
a resignation is submitted.
Positions Held During
Name Age Past Five Years Dates
L.M. Gressette, Jr. (1) 64PSNC, Gastonia, NC.
From February 1993 to February 2000, Chairman,
of the BoardPresident and Chief Executive Officer *-present
President -of
PSNC.
Director, SCANA *-1995
B.D. Kenyon (1) 53 President and Chief
Operating Officer 1990-present
W.B. Timmerman (1) 49 President - SCANA 1995-present
President of MPX, an
affiliate 1996-present
Executive Vice President, 1994-1995
SCANA
Assistant Secretary 1993-1996
Chief Financial Officer *-1996
Controller, SCANA *-1996
Senior Vice President, *-1994
SCANA
G.J. Bullwinkel, Jr. 47 Senior Vice President-
Retail Electric 1995-present
Senior Vice President-
Fossil & Hydro Production 1993-1994
Senior Vice President-
Production 1991-1992
W.A. Darby 50 Senior Vice President -
Gas, SCANA Gas Group 1996-present
Vice President-Gas Operations *-present
President and Treasurer of
ServiceCare 1996-present
General Manager of ServiceCare,
Inc., an affiliate 1994-present
J. L. Skolds 45 Senior Vice President - 1994-present
Generation
Vice President - Nuclear
Operations 1990-1994
K. B. Marsh (1) 40 Vice President - Finance,
Chief Financial Officer
and Controller - SCANA 1996-present
Vice President - Finance,
Treasurer and Secretary 1992-1996
Vice President - Finance
and Treasurer 1991-1992
Vice President - Corporate
Planning 1991
Vice President and
Controller *-1991
B.T. Zeigler (1) 40 Vice President - SCANA 1996-present
General Counsel of SCE&G 1995-present
Associate General Counsel -
SCE&G Legal Department 1992-1995
Partner - Lewis, Babcock &
Hawkins Law Firm *-1992
*Indicates position held at least since March 1, 1991
(1) Also an executive officer of SCANA
59Corporation, Columbia, SC;
PSNC, Gastonia, NC.
COMPLIANCE WITH
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 54 Chairman of the Board and Chief Executive Officer 1997-present
President, SCANA *-present
Chief Operating Officer, SCANA 1996-1997
President, SCI, an affiliate 1996-1997
Chief Financial Officer and Controller, SCANA *-1996
H. T. Arthur 55 Senior Vice President and General Counsel 1998-present
Vice President and General Counsel 1996-1998
N. O. Lorick 50 President and Chief Operating Officer 2000-present
Vice President of Fossil and Hydro Operations *-2000
K. B. Marsh 45 Senior Vice President - Finance and Chief Financial
Officer 2000-present
Senior Vice President - Finance, Chief Financial Officer
and Controller, SCANA 1998-2000
Vice President - Finance, Chief Financial Officer and
Controller, SCANA 1996-1998
Vice President - Finance, Treasurer and Secretary, SCE&G *-1996
S. A. Byrne 40 Vice President Nuclear Operations 2000-present
General Manager Nuclear Plant Operations *-2000
M. R. Cannon 50 Controller, SCANA & All Subsidiaries (excluding SEMI) 2000-present
Treasurer, SCANA & SCE&G *-2000
*Indicates position held at least since March 1, 1996
SECTION 16(a) OF THE EXCHANGE ACTBENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of the Company'sSCE&G's common stock is held by its parent, SCANA Corporation, and none of the directors and executive officers of the
Company own any of the other classes of equity securities of the
Company.Corporation. The
required forms indicate that no equity securities of the
CompanySCE&G are owned by theits
directors and executive officers. Based solely on a review of the copies of such
forms and amendments furnished to the CompanySCE&G and written representations from the
executive officers and directors, the CompanySCE&G believes that during 19952000 all Section
16(a) filing requirements applicable to its executive officers, directors and
greater than 10%10 percent beneficial owners were complied with except that one report covering initial ownership of the
Company's preferred stock was filed late by Kevin B. Marsh and Belton
T. Zeigler.with.
ITEM 11. EXECUTIVE COMPENSATION
SCANA: The following table contains information with respect to
compensation paid or accrued during the years 1995, 1994 and 1993called for by Item 11, Executive Compensation, is
incorporated herein by reference to the Chief Executive Officercaptions "Director Compensation,"
"Compensation Committee Interlocks and Insider Participation," and "Executive
Compensation" in SCANA's definitive proxy statement for the 2001 annual meeting
of the Company and to each of the other
four most highly compensated executive officers of the Company during
1995 who were serving as executive officers of the Company at the end
of 1995.shareholders.
SUMMARY COMPENSATION TABLE
SCE&G: The information called for by Item 11, Executive Compensation, is as
follows:
Summary Compensation Table
Annual Compensation Long-Term Compensation Awards
Securities
Underlying
Option LTIP
Salary Bonus(1) Compensation(2) SARS Payouts(3) Compensation(4)
Name and Principal Position Year ($) ($) ($) (#) ($) ($)
----
Name and Principal Year Annual Compensation Long-Term
Position Compensation
(1) (2)
Salary Bonus Other Payouts
($) ($) Annual
Compen-
sation
($) (3) (4)
LTIP All Other
Payouts Compensa-
($) tion ($)
L. M. Gressette, Jr. 1995 449,246(5) 197,500 65,779 390,156 26,955W. B. Timmerman 2000 524,261(5) 354,486 17,888 35,620 - 50,230
Chairman, of the 1994 416,609 0 2,255 173,375 24,996
Board and Chief 1993 383,557 186,615 61,699 266,007 23,013
Executive Officer
B. D. Kenyon 1995 318,542 104,353 7,107 172,240 19,113 President and
Chief 1994 313,581 96,768 2,649 81,619 18,8151999 490,313 312,900 17,212 - 298,813 29,419
Executive Officer - SCANA 1998 455,909 303,780 17,514 - - 27,138
J. L. Skolds 2000 244,086 - 12,878 - - 24,743
Former President and Chief 1999 330,665 168,288 16,232 - 150,618 19,840
Operating Officer 1993 297,760 99,090 4,201 125,792 17,866
W.- SCE&G 1998 305,123 163,399 14,099 - - 18,201
N. O. Lorick 2000 167,778 124,921 7,313 2,332 - 12,728
President and Chief
Operating 1999 157,417 44,356 7,313 - 38,754 9,445
Officer - SCE&G 1998 143,492 46,719 4,813 - - 8,613
K. B. Timmerman 1995 254,214 101,588 987 150,353 15,127
Chief Financial 1994 235,099 19,725 1,323 70,751 14,106
Officer and 1993 220,752 95,738 2,828 109,768 13,245
Assistant Secretary
G. J. Bullwinkel 1995 189,097 70,904 487 90,402 11,346Marsh 2000 276,172 150,720 10,613 11,627 - 24,254
Senior Vice President 1994 170,828 42,573 762 38,249 9,826-
Finance 1999 241,354 128,058 10,337 - 81,555 14,481
and Chief Financial
Officer - 1998 219,860 99,372 8,654 - - Retail Electric 1993 148,705 51,975 1,477 58,489 0
J. L. Skolds 1995 176,156 74,151 54 76,128 10,56913,122
SCANA
H. T. Arthur 2000 234,812 120,480 16,119 8,796 - 19,718
Senior Vice President 1994 156,731 42,573 2,146 38,249 9,404and 1999 219,806 93,825 15,939 - 65,843 13,188
General Counsel 1998 203,162 99,372 9,534 - - Generation 1993 146,438 43,605 4,065 58,489 0
______________12,190
S. A. Byrne 2000 183,555 123,492 8,310 8,796 - 12,962
Vice President Nuclear 1999 137,321 32,483 3,600 - - 8,239
Operations 1998 125,458 38,682 2,100 - - 7,528
(1) Payments under the annual PerformanceAnnual Incentive Plan described hereafter.Plan.
(2) OtherFor 2000, other annual compensation consists of (i) for Mr. Gressette, perquisites
including compensation related to wholeautomobile allowance, life
insurance premiums for 1995
in the amount of $54,642, (ii) for Mr. Kenyon, a lump sum payment in lieu
of a base salary increase in 1995on policies owned by named executive officers and (iii) for all named officers,
payments to cover taxes on benefits.benefits of $9,000, $7,435 and $1,453 for Mr.
Timmerman; $6,000, $6,878 and $0 for Mr. Skolds; $6,000, $1,313 and $0 for
Mr. Lorick; $9,000, $1,183 and $430 for Mr. Marsh; $9,000, $6,830, and $289
for Mr. Arthur and $8,100, $0 and $210 for Mr. Byrne.
(3) Payments under the long-term Performance Share Plan described hereafter.Long-term Equity Compensation Plan. (4) All other
compensation for all named executive officers consists solely of Company
contributions to defined contribution plans based on the funding formula applicable to all
employees of the Company.plans. (5) Reflects actual salary paid
in 1995.2000. Base salary of $460,000,$537,100, became effective on May 1, 2000.
(6) Mr. Skolds resigned from SCE&G on August 18, 2000.
Options Grants and Related Information
Options/SAR Grants in MayLast Fiscal Year
Potential
Realizable Value at
Assumed Annual
Rates of 1995.Stock Price
Appreciation
Individual Grants for Option Term
- ----------------------------------------------------------------------------------------- ---------------------------
(a) (b) (c) (d) (e) (f) (g)
Number of % of Total
Securities Options/
Underlying SARs
Options/ Granted to Exercise or
SARs Employees in Base Price Expiration
Name Granted Fiscal Year ($/Sh) Date 5% ($) 10%($)
- ----------------------- --------------- ---------------- ---------------- --------------- --------------- -----------
W. B. Timmerman 35,620 22.20 25.50 04/27/10 571,345 1,447,597
N. O. Lorick 2,332 1.45 25.50 04/27/10 37,405 94,772
K. B. Marsh 11,627 7.25 25.50 04/27/10 186,497 472,521
H. T. Arthur 8,796 5.48 25.50 04/27/10 141,088 357,469
S. A. Byrne 8,796 5.48 25.50 04/27/10 141,088 357,469
All the above options vest 33 1/3 percent on each of the first, second and third
anniversaries of the date of the grant, April 27, 2000.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
(a) (d) (e)
Number of
Securities
Underlying Value of Unexercised
Unexercised In-the-Money Options/
Option/SARs SARs at
At FY-End (#) FY-End ($) (1)
Exercisable/ Exercisable/
Name Unexercisable Unexercisable
- --------------------------------------- -------------------------------------- --------------------------------------
W. B. Timmerman 0/35,620 0/144,724
N. O. Lorick 0/2,332 0/9,475
K. B. Marsh 0/11,627 0/47,240
H. T. Arthur 0/8,796 0/35,738
S. A. Byrne 0/8,796 0/35,738
(1)Based on the closing price of $29.5625 per share on December 29, 2000, the
last trading date of the fiscal year.
60
The following table lists the performance share awards made in 2000 (for
potential payment in 2003) under the Long-Term Performance ShareEquity Compensation Plan The long-term Performance Share Planand
estimated future payouts under that plan at threshold, target and maximum levels
for officers of SCANA and
its subsidiaries measures SCANA's Total Shareholder Return ("TSR")
relative to a group of peer companies over a three-year period. The
"PSP Peer Group" includes 94 electric and gas utilities, none of which
have annual revenues of less than $100 million.
TSR is stock price increase over the three-year period, plus cash
dividends paid during the period, divided by stock price aseach of the beginning of the period. Comparing SCANA's TSR to the TSR of a large
group of other utilities reflects SCANA's recognition that investors
could have invested their funds in other utility companies and
measures how well SCANA did when compared to others operating in
similar interest, tax, economic and regulatory environments.
Executives eligible to participateexecutive officers included in the Performance Share Plan
are assigned target award opportunities annually based primarily on
their salary level. In determining award sizes, levels of
responsibilities and competitive practices also are considered.
Awards under this plan represent a significant portion of executives
"at-risk" compensation. To provide additional incentive for
executives, and to ensure that executives are only rewarded when
shareholders gain, actual payouts may exceed the median of the market
when performance is above the 50th percentile of the peer group. For
lesser performance, awards will be at or below the market median.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 12,510 2000-2002 5,004 12,510 18,765
N. O. Lorick 3,390 2000-2002 1,356 3,390 5,085
K. B. Marsh 4,880 2000-2002 1,952 4,880 7,320
H. T. Arthur 3,410 2000-2002 1,364 3,410 5,115
S. A. Byrne 3,410 2000-2002 1,364 3,410 5,115
Payouts occur when SCANA's TSRTotal Shareholder Return is in the top
two-thirds of the PSP Peer Group,Long-Term Equity Compensation Plan peer group, and will vary
based on SCANA's ranking against the peer group. Executives earn threshold
payouts of 0.4 times target at the 33rd percentile of three-year performance. Target payouts will be
made at the 50th percentile of three-year performance. Maximum payouts will be
made at 1.5 times target when SCANA's TSRperformance 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 inat
less than the bottom one-third of the peer group.33rd percentile. Awards are denominated indesignated as target shares of SCANA
Common Stock and may be paid in either stock or a combination of stock and cash.
For the three-year period from 1993 through 1995, SCANA's TSR was
at the 98th percentile of the PSP Peer Group. This resulted in
payouts in February 1996 at 150% of target shares awarded paid in a
combination of stock and cash.
The following table shows the target awards made in 1995 for
potential payment in 1998 under the long-term Performance Share Plan,
and estimated future payouts under that plan at threshold, target and
maximum levels for the named executive officers. Mr. Gressette's
award for the 1995-1997 performance period is prorated to reflect his
retirement in February 1997.
LONG-TERM INCENTIVE PLANS - AWARDS
IN LAST FISCAL YEAR
TARGET AWARDS FOR 1995 TO BE PAID IN 1998
Number of Performance Estimated Future Payouts Under
Shares, or Other Non-Stock Price-Based Plans
Units or Period Until
Other Maturation
Name Rights (#) or Payout
Threshold Target Maximum
($ or #) ($ or #) ($ or #)
L. M. Gressette, Jr. 6,023 1995-1997 2,409 6,023 9,035
B. D. Kenyon 3,700 1995-1997 1,480 3,700 5,550
W. B. Timmerman 3,220 1995-1997 1,288 3,220 4,830
G. J. Bullwinkel 1,940 1995-1997 776 1,940 2,910
J. L. Skolds 1,940 1995-1997 776 1,940 2,910
61
DEFINED BENEFIT PLANS
Effective January 1, 2000, the SCANA Corporation Retirement Plan, a tax
qualified defined benefit plan, was amended to provide a mandatory cash balance
benefit formula (the "Cash Balance Formula") for employees hired on or after
that date. Effective July 1, 2000, SCANA employees hired prior to January 1,
2000, were given the choice of remaining under the Retirement Plan's final
average pay benefit formula or switching to a cash balance benefit option.
The Cash Balance Formula benefit is expressed in the form of a
hypothetical account balance. Participants electing to participate under the
cash balance option had an opening account balance established for them. The
opening account balance equals the present value of the participant's June 30,
2000 accrued benefit under the final average pay formula. Participants who had
20 years of vesting service or who had 10 years of vesting service and whose age
plus service equaled at least 60 were given transition credits. For these
participants the beginning account balance was determined so that projected
benefits under the cash balance option approximated projected benefits under the
final average pay formula at the earliest date at which unreduced benefits are
payable under the plan.
Account balances are increased monthly by interest and compensation
credits. The interest rate used for accumulating account balances changes
annually and is equal to the rate for 30-year Treasuries for December of the
previous calendar year. Compensation credits equal 5 percent of compensation
under the Social Security Wage Base and 10 percent of compensation in excess of
the Social Security Wage Base.
In addition to the qualifiedits Retirement Plan for all employees, the CompanySCANA has
Supplemental Executive Retirement Plans ("SERP"SERPs") for certain eligible
employees, including officers.certain officers of its subsidiaries. A SERP is an unfunded
plan whichthat provides for benefit payments in addition to thosebenefits payable under
athe qualified retirement plan. It maintains uniform application
ofRetirement Plan so as to make up for benefits lost in the
Retirement Plan benefit formula and would provide, among other
benefits, paymentbecause of Retirement Plan formula pension benefits, if any,
which exceed those payable under the Internal Revenue Code ("IRC")
maximum benefit limitations.
The following table illustrates the estimated maximum annual
benefits payable upon retirement at normal retirement date under the
Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years
Average Pay 15 20 25 30 35
$150,000 42,311 56,415 70,519 84,623 87,476
200,000 57,311 76,415 95,519 114,623 118,726
250,000 72,311 96,415 120,519 144,623 149,976
300,000 87,311 116,415 145,519 174,623 181,226
350,000 102,311 136,415 170,519 204,623 212,476
400,000 117,311 156,415 195,519 234,623 243,726
450,000 132,311 176,415 220,519 264,623 274,976
500,000 147,311 196,415 245,519 294,623 306,226
550,000 162,311 216,415 270,519 324,623 337,476
600,000 177,311 236,415 295,519 354,623 368,726
The compensation shown in the column labeled "Salary" of the
Summary Compensation Table for the individuals named therein is
covered by the Retirement Plan and/or a SERP. As of December 31,
1995, Messrs. Gressette, Kenyon, Timmerman, Bullwinkel and Skolds had
credited service under the Retirement Plan (or its equivalent under
the SERP) of 33, 22, 17, 25 and 10 years, respectively. Benefits are
computed based on a straight-life annuity with an unreduced 60%
surviving spouse benefit. The amounts in this table assume
continuation of the primary Social Security benefits in effect at
January 1, 1996 and are not subject to any deduction for Social
Security or other offset amounts.
The Company also has a Key Employee Retention Program (the "Key
Employee Retention Program") covering officers and certain other
executive employees that provides supplemental retirement and/or death
benefits for participants. Under the program, each participant may
elect to receive either a monthly retirement benefit for 180 months
upon retirement at or after age 65 equal to 25% of the average monthly
salary of the participant over his final 36 months of employment prior
to age 65, or an optional death benefit payable to a participant's
designated beneficiary monthly for 180 months, in an amount equal to
35% of the average monthly salary of the participant over his final 36
months of employment prior to age 65. In the event of the
participant's death prior to age 65, the Company will pay to the
participant's designated beneficiary for 180 months, a monthly benefit
equal to 50% of such participant's base monthly salary in effect at
death.
All of the executive officers named in the Summary Compensation Table above are
participating inunder the program. Estimatedcash balance benefit option of the plan. The estimated
annual retirement benefits payable as life annuities at age 65 under the plans,
based on projected eligible compensation (assuming increases of 4%4 percent per year), to
the five executive officers named in the Summary Compensation Table are as follows:
Mr. Gressette - $113,790; Mr. Kenyon - $122,658; Mr. Timmerman - $129,942;$410,496; Mr. BullwinkelLorick - $90,887;$224,448; Mr. Marsh - $ 278,220; Mr.
Arthur - $122,424 and Mr. SkoldsByrne - $93,234.
62
TERMINATION, SEVERANCE AND CHANGE OF CONTROL ARRANGEMENTS
The Company$158,258.
SCANA has a Key Executive Severance BenefitEmployee Retention Plan (the
"Severance Plan"("KERP") intendedcovering officers and
certain other executive employees of SCE&G that provide supplemental retirement
or death benefits for participants. These employees also participate in SCANA's
Retirement Plan.
Participants who elected to assureremain in the objective judgmentfinal average pay plan
continue to participate in the KERP under the provisions in effect on June 30,
2000. Each participant who elected to convert to the cash balance plan became
entitled on July 1, 2000 to a KERP cash balance benefit. The amount of the
benefit was determined by discounting to June 30, 2000 the amount of the
participant's projected retirement benefit under the prior plan, assuming the
participant retired upon attaining the earlier of (i) age 65 or (ii) 35 years of
service (unreduced retirement age), adjusted to reflect actual years of service
through June 30, 2000.
Each participant's account balance will increase in each subsequent
year until unreduced retirement age by (i) interest at the rate for 30-year
Treasuries and (ii) an accrual reflecting one additional year of service. If a
participant continues to retainwork beyond his unreduced retirement age, his KERP
account will only grow with interest.
In the loyaltiesevent of key executives when the Company is faced with
a potential change in control or a change in control by providing a
continuationparticipant's death prior to such retirement, SCANA
will pay to the participant's designated beneficiary, the participant's KERP
account balance at the time of salary and benefits afterdeath. In the event a participant's employment is
terminated by the Company during a potential change in control,
after a change in control without just cause, disability,prior to retirement,
or death or by the participant for good reason after a change in
control. All ofwill be paid his KERP account
balance.
The estimated annual retirement benefits payable at age 65 under the
KERP to the executive officers named in the Summary Compensation Table, except Mr. Gressette have been designated as
participantswho
participate in the KERP, based on projected eligible compensation (assuming
increases of 4 percent per year) are: Mr. Timmerman - $ 186,357; Mr. Marsh -
$146,464; Mr. Arthur - $80,086; Mr. Lorick - $84,677 and Mr. Byrne - $120,183.
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).
(1) SCANA Corporation Supplementary Voluntary Deferral Plan (2) SCANA
Corporation Key Employee Retention Plan (3) SCANA Corporation
Supplemental Executive Retirement Plan (4) SCANA Corporation Long-term
Equity Compensation Plan (5) SCANA Corporation Annual Incentive Plan
(6) SCANA Corporation Key Executive Severance Plan.
WhenBenefits Plan
(7) SCANA Corporation Supplementary Key Executive Severance Benefits Plan
The trusts and the plans provide flexibility to SCANA in responding to
a potential changePotential Change in control occurs,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 participantChange 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 obli-
gatedoperative as a "single
trigger" plan, meaning that upon the occurrence of a "hostile" Change in
Control, benefits provided under Plans (1) through (5) 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 remain withits occurrence is viewed as being "friendly."
In this circumstance, the CompanyKey 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 (5) 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 six months unless his employment"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 terminated for disability or normal retirement or until a change in
control occurs. Upon a change in control resulting in an officer's
termination,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 provides for guaranteed severance
paymentswould include the following:
o An amount equal to three times the sum of: (1) the officer's annual compensationbase
salary in effect as of the officer
plus payments under certainChange in Control and (2) the larger of (i)
the officer's target award in effect as of the Company'sChange in Control under
the Annual Incentive Plan or (ii) the officer's average of actual annual
incentive and retirement
plans. The officer also would receive an additionalbonuses received during the prior three years under the Annual
Incentive Plan.
o An amount (a "gross-
up" payment) for any IRC Section 4999 excess tax or any such other
similar tax applicableequal to the severance payments. In addition,projected cost for 36
months after termination,coverage for three full years
following the Change in Control as though the officer would receivehad continued to
be a SCANA employee with respect to medical coverage, for
medical benefitslong-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 previouslyas the
officer enjoyed as of the date of the Change in Control.
o A benefit distribution under group plans or individual policy
contracts or otherwisethe 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 equal to
the lump sum amount calculated as determinedof the day of the Change in Control
under the KERP cash balance formula.
o A benefit distribution under the Supplemental Executive Retirement Plan
("SERP") equal to the amount of the SERP cash balance account as of the
date of the Change in Control, increased by an amount equal to
additional compensation and interest credits, assuming the executive had
completed three additional years of service with compensation at the
participant's rate of compensation then in effect, and assuming interest
credits for three additional years at the applicable rate of interest,
which benefit would then be reduced by the Executive Committeeamount of the Boardparticipant's
cash balance account accrued under the Retirement Plan as of Directors. Such benefits however would be reduced to the extent thatdate
the participant receives similar benefits during the
period from another employer.
In addition to the Severance Plan,Change in the event of a merger,
consolidation or acquisition in which SCANA is not the surviving
corporation, target awardsControl.
o A benefit distribution under the Performance Share Plan willequal to 100
percent of the targeted awards for all performance periods not completed
as of the date of the Change in Control.
o A benefit distribution under the Long-Term Equity Compensation Plan
equal to 100 percent of the targeted performance share awards for all
performance periods not completed as of the date of the Change in
Control.
o Under the Long-Term Equity Compensation Plan, all nonqualified stock
options awarded shall become immediately payable based on SCANA's shareholder return
performanceexercisable and remain
exercisable throughout their term.
o A benefit distribution under the Annual Incentive Plan equal to 100
percent of the target award in effect as of the date of the Change in
Control.
Benefits under the Supplementary Key Employee Severance Benefits Plan
would be the same except that the benefits under the Supplementary Voluntary
Deferral Plan would be increased by implied interest from the date of the Change
in Control until the end of the most recently completed calendar year
for each performance period as tomonth preceding the month in which the grant of target shares has
occurred at least six months previously.benefit
is distributed.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1995, no2000, decisions on various elements of executive compensation
were made by the Management Development and Corporate Performance Committee and
the Long-Term Equity Compensation Plan Committee. No officer, employee or former
officer of the
CompanySCANA or any of its affiliatessubsidiaries served as a member of the Long-Term
CompensationManagement
Development and Corporate Performance Committee or the PerformanceLong-Term Equity
Compensation Plan Committee except Mr. GressetteTimmerman, who served as an ex-officio,
non-voting member of the Management Development and Corporate Performance
Committee.
The names of the persons who serve on the Management Development and
Corporate Performance Committee and the Long-Term Equity Compensation Plan
Committee can be found at Item 12, Security Ownership of Certain Beneficial
Owners and Management. Although Mr. Timmerman served as a member of the
Performance Committee.
Although Mr. Gressette was an ex-officio, nonvoting member of theManagement Development and Corporate Performance Committee, during 1995, he did not
participate in any of its deliberationsdecisions concerning executive officer compensation.
Since January 1, 1995, the Company hasDuring 2000, SCANA and its subsidiaries engaged in a business
transactionstransaction with entitiesan entity with which Mr. Chapman (Chairman of both
the Performance Committee and the Long-Term Compensation Committee)
and Mr. McMasterAmick (a member of the Long-Term CompensationManagement
Development and Corporate Performance Committee) are executive officers.is related. Mr. ChapmanAmick is
ChairmanPresident and a 20 percent owner of NationsBank South,Team Amick Motorsports LLC, a division of
NationsBank Corporation. Since January 1, 1995,business that
owns and operates a NASCAR sanctioned racing car. This car participates in the
Company has
engaged in various transactions in which affiliates of NationsBank
Corporation acted as lender or provider of lines of credit or credit
support to the CompanyBusch Grand National Racing Series. During 2000, SCANA and its affiliates. The amountsubsidiaries paid
during
1995 by the CompanyTeam Amick Motorsports, LLC a total of $254,085, for a sponsorship and car
appearances pursuant to which SCANA received promotional considerations
associated with NASCAR racing. SCANA and its affiliatessubsidiaries do not plan to
NationsBank Corporation
affiliates on account of such transactions was $3,339,270. It is
anticipated that transactions suchcontinue as described above will continuea sponsor with Team Amick Motorsports, LLC in the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum
Company. Purchases from Winnsboro Petroleum Company totaling $71,413
for fuel oil and gasoline were made during 1995 by the Company and its
affiliates. It is anticipated that such purchases will continue in
the future.
During 1995, there existed one executive officer-director
interlock where an executive officer2001.
Directors Compensation
Board Fees
Officers of SCANA Corporation servedwho are also directors do not receive additional
compensation for their service as a
directordirectors. Since July 1, 2000, compensation
for non-employee directors of another company that hadSCANA has included the following:
o an executive officer serving on
oneannual retainer of $30,000 (60 percent of the annual retainer fee is paid
in shares of SCANA Board of Directors' committees which deals with
compensation matters. Mr. Gressette, Chairman of the Board and Chief
Executive Officer of the Company, served as a director of The Liberty
Corporation and Mr. Hipp, President and Chief Executive Officer of The
Liberty Corporation, served as a member of the Company's Long-Term
Compensation Committee.
63
Compensation of Directors
Fees. During 1995, directors who were not employees of the
Company were paid $16,000 annually for services rendered, plus $1,800Common Stock);
o $3,500 for each Boardboard meeting attended and $850attended;
o $3,000 for attendance at a committee meeting which is not held on the samea day asother than a
regular meeting of the Board. The feeBoard;
o $250 for participation in a telephone conference meeting; o $2,000 for
attendance at a telephone conference meeting is
$200. The feean all-day conference; and o reimbursement for attendance at a conference is $850. In addition,expenses incurred
in connection with all of the above.
Director Compensation and Deferral Plans
During 2000, non-employee directors are paid, ascould participate in SCANA's
Voluntary Deferral Plan. This plan permitted non-employee directors to defer
receipt of all or part of their compensation, travel, lodgingfees (except the portion paid in shares of SCANA
Common Stock) and incidental expenses relatedreceive, upon ceasing to attendance at meetings and conferences.
Directors who are employees ofserve as a director, the Company or its affiliates receive
no compensation for serving as directors or attending meetings.
Deferral Plan. SCANA has a plan pursuant to which directors may
defer all or a portion of their fees for services rendered and meeting
attendance. Interest is earned onamount that
would have resulted from investing the deferred amounts at a rate set
byin an interest bearing
savings account.
During calendar year 2000, Mr. Bennett deferred compensation under the
Performance Committee. During 1995Voluntary Deferral Plan and currently, the rate is
set at the announced prime rate of Wachovia Bank of South Carolina.
Mr. Cassels and Mr. Rhodes were the only directors participatinghis account was credited with interest in the amount
of $2,669 for that year.
Effective January 1, 2001, non-employee director compensation deferrals
are governed by a new plan, the SCANA Corporation Director Compensation and
Deferral Plan. Amounts deferred by directors in previous years under the SCANA
Voluntary Deferral Plan continue to be governed by that plan.
Under the new plan, a director may elect to defer (i) 100 percent of
all compensation amounts , or (ii) the 60 percent of the annual retainer fee
required to be paid in SCANA Common Stock, in a hypothetical investment in SCANA
Common Stock, with distribution from the plan to be ultimately payable in actual
shares of SCANA Common Stock. A director also may elect to defer the 40 percent
of the annual retainer fee not required to be paid in shares of SCANA Common
Stock and up to 100 percent of meeting attendance and conference fees with
distribution from the plan to be ultimately payable in either SCANA Common Stock
or cash. Amounts payable in SCANA Common Stock accrue earnings during 1995.the
deferral period at SCANA's dividend rate, which amount may be elected to be paid
in cash when accrued or retained to invest in hypothetical shares of SCANA
Common Stock. Amounts payable in cash accrue interest earnings until paid.
For calendar year 2001, Messrs. Amick, Bennett, Burkhardt, Hipp, Sloan,
Stowe and York and Ms. Miller have elected to defer 100 percent of their
compensation under the Director Compensation and Deferral Plan so as to acquire
hypothetical shares of SCANA Common Stock. In addition, Mr. Cassels became a participant in January
1994 and Mr. Rhodes in July 1987, and interest creditedHagood has elected
to their
deferral accounts during 1995 was $3,591.94 and $19,557.86,
respectively.defer 60 percent of his annual retainer to acquire hypothetical shares of
SCANA Common Stock.
Endowment Plan.
EachUpon election to a second term, a director participatesbecomes eligible to
participate in the Directors'SCANA Director Endowment Plan, which provides thatfor SCANA to
make a tax deductible, charitable contribution totaling $500,000 to institutions
of higher education nominateddesignated by the director. The plan is intended to
reinforce SCANA's commitment to quality 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-
stateSCANA. 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.
The plan is intended to reinforce SCANA's commitment to quality higher
education and is intended to enhance SCANA's ability to attract and
retain qualified board members.Other
As a Company retiree, Mr. Gressette receives monthly retirement benefits of
$39,571.
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 2001 annual meeting of shareholders.
SCE&G: All of the outstanding voting securities of SCE&G are owned by SCANA. The
following table lists shares of the Company's Common Stock are held, beneficially
and of record, by SCANA Corporation.
The table set forth below indicates the shares of SCANA's Common
Stockcommon stock beneficially owned as ofon March
8, 19969, 2001 by each director, each nominee and nominee, each of the executive officersofficer named in the
Summary Compensation Tabletable on page 59, and the directors and executive
officers of the Company as a group.
SECURITY OWNERSHIP OF MANAGEMENT
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature
Owner of Ownership 1 Owner of Ownership 1
B. L. Amick 2,486 W. Hayne Hipp 2,800
W. B. Bookhart, Jr. 15,761 B. D. Kenyon 18,883
G. J. Bullwinkel 17,255 F. C. McMaster 5,630
W. T. Cassels, Jr. 2,000 Henry Ponder 12,381
H. M. Chapman 6,000 J. B. Rhodes 7,780
J. B. Edwards 4,665 J. L. Skolds 6,414
E. T. Freeman 4,220 W. B. Timmerman 36,459
L. M. Gressette, Jr. 47,493 E. C. Wall, Jr. 14,000
B. A. Hagood 2,370141.
SECURITY OWNERSHIP OF MANAGEMENT
Amount and Nature Amount and Nature
of Beneficial Ownership of of Beneficial Ownership of
SCANA Common Stock *(1)(2)(3)(4) SCANA Common Stock *(1)(2)(3)(4)
Name Name
- ----- ------------------------------ ----
B. L. Amick(5) 11,821 W. H. Hipp 4,896
H. T. Arthur 16,211 K. B. Marsh 18,826
J. A. Bennett(6) 2,210 L. M. Miller(6) 3,356
W. B. Bookhart, Jr.(5)(6) 21,811 N. O. Lorick 15,977
W. C. Burkhardt(5)(6) 11,130 M. K. Sloan(5)(6) 3,955
S. A. Byrne 7,467 H. C. Stowe(5)(6) 3,941
H. M. Chapman(5)(6) 7,994 W. B. Timmerman(5) 65,191
E. T. Freeman 6,435 G. S. York(6) 10,744
L. M. Gressette, Jr. 63,640 C. E. Zeigler, Jr. 32,133
D. M. Hagood(6) 820
*Each of the directors, nominees and named executive officers owns less than 1
percent of the shares outstanding.
All directors and executive officers as a group (21( persons) TOTAL 247,243
TOTAL.TOTAL PERCENT
OF CLASS, 0.2%
The information set forth above asoutstanding and entitled to vote at the security ownership has
been furnished to the Company by such persons.
_____________________
1Annual Meeting of Shareholders
percent.----------
(1) Includes shares owned by close relatives, the beneficial ownership of which
is disclaimed by the director, nominee or nominee,named executive officers, as
follows: Mr. Amick - 480;Amick-480; Mr. Bookhart - 4,498;Bookhart-5,804; Mr. Gressette - 1,060;
Mr. Hagood - 334; Mr. McMaster - 2,000.Gressette-1,060; and by all
directors, nominees and executive officers 7,344 in total.
(2) Includes shares purchased through December 31, 1995, but not
thereafter,February 28, 2001, by the Trustee under
theSCANA's Stock Purchase Savings Plan. 64
(3) Hypothetical shares acquired under
the SCANA Director Compensation and Deferral Plan are not included in the
above table. As of March 9, 2001, each of Messrs. Amick, Bennett, Burkhardt,
Hipp, Sloan, Stowe and York and Ms. Miller had acquired 674 hypothetical
shares under the plan and Mr. Hagood had acquired 404.
(4) Includes shares subject to options exercisable within 60 days.
(5) Serves on The Management Development and Corporate Performance Committee
(Mr. Timmerman serves as an ex-officio, non-voting member).
(6) Serves on the Long-Term Equity Compensation Plan Committee.
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 "Related Transactions" in
SCANA's definitive proxy statement for the 2001 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", the "Performance Graph" and the "Audit
Committee Report" included in SCANA's definitive proxy statement for the 2001
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, "CompensationExecutive Compensation under the heading Compensation Committee
Interlocks and Insider Participation."Participation and the following:
During 2000, SCANA paid $239,242 (including the value of non-utility in
kind services provided by SCANA) to subsidiaries of Liberty Corporation for
advertising expenses. Mr. Hipp is the Chairman, President and Chief Executive
Officer and a director of Liberty Corporation. It is anticipated that similar
transactions will occur in the future.
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:
The Independent Auditor's Reports on the financial
statements for SCANA, SCE&G and PSNC are listed under Item 8
herein.
The financial statements and supplementary financial data
filed as part of this report for SCANA, SCE&G and PSNC are
listed under Item 8 herein.
The Financial Statement Schedules See Index to Consolidated Financial Statementsfiled as part of this
report for SCANA, SCE&G and Supplementary DataPSNC are listed beginning on
page 30.150.
(2) Exhibits Filed
Exhibits required to be filed with this Annual Report on
Form 10-K are listed in the Exhibit Index following the
signature page. Certain of such exhibits which have
heretofore been filed with the Securities and Exchange
Commission and which are designated by reference to their
exhibit number in prior filings are hereby incorporated herein by
reference and made a part hereof.
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 the CompanySCANA, for
itself and its subsidiaries, of SCE&G, for itself and its
subsidiaries, and of PSNC, for itself and its subsidiaries,
have been omitted and the Company agreesSCANA, SCE&G and PSNC agree to furnish
a copy of such instruments to the Commission upon request.
(b) Reports on Form 8-K during the fourth quarter of 2000 for SCANA, SCE&G and
PSNC:
None
65
SCANA:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2000, 1999 and 1998.
For December 31, 2000 Additions
Charged to
Beginning Charged to Other Deductions Ending
Description Balance Income Accounts from Reserves Balance
- -------------------------------------- ---------------- ---------------- --------------- ---------------- ----------------
Reserves deducted from related assets on the balance sheet:
Uncollectible accounts
2000 7,302,273 23,308,561 - 77,133 30,533,701
1999 1,965,732 5,636,123 - 299,582 7,302,273
1998 1,807,047 184,257 - 25,572 1,965,732
Reserve for investment impairment
2000 4,133,768 1,000,000 - 205,000 4,928,768
1999 10,292,611 - - 6,158,843 4,133,768
1998 11,150,060 - - 857,449 10,292,611
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2000 5,221,544 2,461,339 - 333,544 7,349,339
1999 4,287,986 1,352,448 - 418,890 5,221,544
1998 4,187,594 461,462 - 361,070 4,287,986
Provision for pension and benefit
Staff Reduction Plan
2000 6,487,365 - - 131,570 6,355,795
1999 6,256,249 231,116 - - 6,487,365
1998 4,486,895 6,256,249 - 4,486,895 6,256,249
Provision for environmental
remediation and settlement
2000 3,223,821 - - 409,252 2,814,569
1999 3,619,572 - - 395,751 3,223,821
1998 4,006,562 - - 386,990 3,619,572
SCE&G:
Schedule II - Valuation and Qualifying Accounts for the years ended December 31,
2000, 1999 and 1998.
For December 31, 2000 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
2000 537,000 116,000 - 76,000 577,000
1999 611,001 80,000 154,001 537,000
1998 611,001 - - - 611,001
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and damages
2000 3,972,816 819,431 - 217,055 4,575,192
1999 4,176,794 104,000 - 307,978 3,972,816
1998 4,039,148 460,462 - 322,816 4,176,794
Provision for pension and benefit
Staff Reduction Plan
2000 - - - - -
1999 - - - - -
1998 4,486,895 - - 4,486,895 -
Provision for environmental
remediation and settlement
2000 3,223,821 - - 409,252 2,814,569
1999 3,619,572 - - 395,751 3,223,821
1998 4,006,562 - - 386,990 3,619,572
PSNC:
Schedule II - Valuation and Qualifying Accounts for the Year Ended December 31,
2000, Three Months Ended December 31, 1999 and Fiscal Years Ended September 30,
1999 and 1998.
For December 31, 2000 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
2000 2,702,014 2,417,566 - 2,716,884 2,402,696
Three Months 1999 1,737,815 470,895 - (199,069) 2,702,014*
Fiscal Year 1999 2,086,128 725,094 - 1,073,407 1,737,815
Fiscal Year 1998 2,521,983 866,786 - 1,302,641 2,086,128
Reserves other than those deducted from assets on the balance sheet:
Reserve for injuries and
damages
2000 2,197,615 494,629 - 1,065,986 1,626,258
Three Months 1999 1,930,377 442,000 - 174,762 2,197,615
Fiscal Year 1999 1,207,278 1,802,544 - 1,079,445 1,930,377
Fiscal Year 1998 1,131,780 1,422,271 - 1,346,773 1,207,278
Provision for post-retirement &
post-employment
2000 6,658,753 1,227,823 - 7,488,576 398,000
Three Months 1999 6,466,563 298,857 - 106,667 6,658,753
Fiscal Year 1999 5,165,324 1,676,767 - 375,528 6,466,563
Fiscal Year 1998 4,436,674 1,052,990 - 324,340 5,165,324
*Ending balance for December 31, 1999 includes $294,235 uncollectible reserve
balance for SCANA Public Service Company, L.L.C. (formerly Sonat Public Service)
purchased December 31, 1999.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized. (REGISTRANT) SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY (SIGNATURE)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
s/Bruce D. Kenyon
(NAME AND TITLE) Bruce D. Kenyon,W. B. Timmerman
By: W. B. Timmerman, Chairman of the Board,
President, Chief Executive Officer and Chief
Operating Officer
DATE February 20, 1996Director
DATE: March 27, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
(i) Principal executive officer:
BY (SIGNATURE) s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)
s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance,
Chief Financial Officer
(Principal Financial Officer)
s/ M. R. Cannon
M. R. Cannon,
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr. L. M. Miller
W. C. Burkhardt M. K. Sloan
H. M. Chapman H. C. Stowe
E. T. Freeman G. S. York
L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette,C. E. Zeigler, Jr.
*Signed on behalf of each of these persons by , Attorney-in-Fact
DATE: March 27, 2001
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/N. O. Lorick
N. O. Lorick, President and Chief
Operating Officer
Date: March 27, 2001
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.
s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
Chief Executive Officer and Director
DATE February 20, 1996
(ii) Principal financial officer:
BY (SIGNATURE)(Principal Executive Officer)
s/K. B. Marsh
(NAME AND TITLE) K. B. Marsh, Senior Vice President - Finance and
Chief Financial Officer
DATE February 20, 1996
(iii) Principal accounting officer:
BY (SIGNATURE)(Principal Financial Officer)
s/J. E. Addison
(NAME AND TITLE) J. E. Addison, Vice President and M. R. Cannon
M. R. Cannon,
Controller
DATE February 20, 1996
BY (SIGNATURE) s/(Principal Accounting Officer)
Other Directors*:
B. L. Amick (NAME AND TITLE) B. L. Amick, Director
DATE February 20, 1996
BY (SIGNATURE) s/D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr. (NAME AND TITLE)L. M. Miller
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.
*Signed on behalf of each of these persons by , Attorney-in-Fact
Date: March 27, 2001
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.
PUBLIC SERVICE COMPANY OF NORTH CAROLINA, INCORPORATED
By: s/C. E. Zeigler, Jr.
C. E. Zeigler, Jr., President and Chief
Operating Officer
Date: March 27, 2001
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.
s/W. B. Timmerman
W. B. Timmerman, Chairman of the Board,
Chief Executive Officer and Director
(Principal Executive Officer)
s/K. B. Marsh
K. B. Marsh, Senior Vice President - Finance and
Chief Financial Officer
(Principal Financial Officer)
s/ M. R. Cannon
M. R. Cannon,
Controller
(Principal Accounting Officer)
Other Directors*:
B. L. Amick D. M. Hagood
J. A. Bennett W. H. Hipp
W. B. Bookhart, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/ L. M. Miller
W. T. Cassels, Jr.
(NAME AND TITLE) W. T. Cassels, Jr., Director
DATE February 20, 1996
BY (SIGNATURE) s/C. Burkhardt M. K. Sloan
H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Edwards
(NAME AND TITLE) J. B. Edwards, Director
DATE February 20, 1996
66
BY (SIGNATURE) s/C. Stowe
E. T. Freeman (NAME AND TITLE)G. S. York
L. M. Gressette, Jr. C. E. T. Freeman, Director
DATE February 20, 1996
BY (SIGNATURE) s/B. A. Hagood
(NAME AND TITLE) B. A. Hagood, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. Hayne Hipp
(NAME AND TITLE) W. Hayne Hipp, Director
DATE February 20, 1996
BY (SIGNATURE) s/F. C. McMaster
(NAME AND TITLE) F. C. McMaster, Director
DATE February 20, 1996
BY (SIGNATURE) s/Henry Ponder
(NAME AND TITLE) Henry Ponder, Director
DATE February 20, 1996
BY (SIGNATURE) s/W. B. Timmerman
(NAME AND TITLE) W. B. Timmerman, Director
DATE February 20, 1996
BY (SIGNATURE) s/J. B. Rhodes
(NAME AND TITLE) J. B. Rhodes, Director
DATE February 20, 1996
BY (SIGNATURE) s/E. C. Wall,Zeigler, Jr.
(NAME AND TITLE) E. C. Wall, Jr.*Signed on behalf of each of these persons by , Director
DATE February 20, 1996
67Attorney-in-Fact
Date: March 27, 2001
SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially
EXHIBIT INDEX
Numbered
Number Pages
2.Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
Agreement and Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Succession
Not Applicable
3. ArticlesMerger, dated as of IncorporationFebruary 16,
1999 as amended and By-Laws
A.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 Registration Statement No.
333-78227 on Form S-4 and
2.01 X X incorporated by reference herein)
Restated Articles of Incorporation
of the
CompanySCANA as adopted on April 26,
1989 (Filed as Exhibit 3-A to
Registration Statement No. 33-49145
and incorporated by reference
3.01 X herein)
Restated Articles of Incorporation
of SCE&G, as adopted on December
15, 1993 (Exhibit 3-A(Filed as Exhibit 3.01 to
Form 10-Q for the quarter
ended June 30, 1994, File No. 1-3375).................... #
B.Registration Statement No.333-8638
and incorporated by reference
3.02 X herein)
Articles of Amendment of SCANA,
dated April 27, 1995 (Filed as
Exhibit 4-B to Registration
3.03 X Statement No. 33-62421 and
incorporated by reference herein)
Articles of Amendment of SCE&G, dated June 7, 1994 and
filed June 9, 1994 (Exhibit 3-B(Filed as Exhibit 3.02 to
Form 10-Q
for the quarter ended June 30, 1994, FileRegistration Statement No.
1-3375).... #
C.333-86387 and incorporated
3.04 X by reference herein)
Articles of Amendment of SCE&G,
dated November 9, 1994 (Exhibit 3-C(Filed as
3.05 X Exhibit 3.03 to Form 10-K for the year ended
December 31, 1994, FileRegistration
Statement No. 1-3375)...................... #
D.333-86387 and
incorporated by reference herein)
Articles of Amendment of SCE&G,
3.06 X dated December 9, 1994 (Exhibit 3-D to Form 10-K for the year ended
December 31, 1994, File(Filed as
Exhibit 3.04 toRegistration
Statement No. 1-3375)...................... #
E.333-86387 and
incorporated by reference herein)
Articles of Correction of SCE&G,
3.07 X dated January 17, 1995 (Exhibit 3-E(Filed as
Exhibit 3.05 to Form 10-K for the year ended
December 31, 1994, FileRegistration
Statement No. 1-3375)...................... #
F.333-86387 and
incorporated by reference herein)
Articles of Amendment of SCE&G,
3.08 X dated January 13, 1995 (Filed as
Exhibit 3.06 to Registration
Statement No. 333-86387 and
filed January 17, 1995 (Exhibit 3-F to
Form 10-K for the year ended December 31, 1994,
File No. 1-3375)......................................... #
G.incorporated by reference herein)
Articles of Amendment of SCE&G,
3.09 X dated March 31,30, 1995 (Exhibit 3-G(Filed as
Exhibit 3.07 to Form 10-Q for the quarter
ended March 31, 1995, FileRegistration
Statement No. 1-3375)................... #
H.333-86387 and
incorporated by reference herein)
Articles of Correction -of SCE&G
Amendment to Statement filed March
31,30, 1995, dated December 13, 1995
(Filed herewith)......................................... 71
I.as Exhibit 3.08 to
Registration Statement No.
3.10 X 333-86387 and incorporated by
reference herein)
Articles of Amendment of SCE&G,
3.11 X dated December 13, 1995 (Filed herewith)......................................... 72
J. Copyas
Exhibit 3.09 to Registration
Statement No. 333-86387 and
incorporated by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
Articles of Amendment of SCE&G, dated
3.12 X February 18, 1997 (Filed as Exhibit 3-L
to Registration Statement No. 333-24919
and incorporated by reference herein)
Articles of Amendment of SCE&G, dated
3.13 X February 21, 1997 (Filed as Exhibit 3.1
to Registration Statement No. 333-86387
and incorporated by reference herein)
Articles of Amendment of SCE&G, dated
April 22, 1997 (Filed as Exhibit 3.12 to
3.14 X Registration Statement No. 333-86387 and
incorporated by reference herein)
Articles of Amendment of SCE&G, dated
April 9, 1998 (Filed as Exhibit 3.13 to
3.15 X Registration Statement No. 333-86387 and
incorporated by reference herein)
Articles of Amendment of SCE&G, dated
May 19, 1999 (Filed as Exhibit 3.01 to
3.16 X Registration Statement No. 333-49960 and
incorporated by reference herein)
Articles of Amendment of SCE&G, dated
August 13, 1999 (Filed as Exhibit 3.02
3.17 X to Registration Statement No. 333-49960
and incorporated by reference herein)
Articles of Amendment of SCE&G, dated
March 1, 2000 (Filed as Exhibit 3.03 to
3.18 X Registration Statement No. 333-49960 and
incorporated by reference herein)
Articles of Incorporation of PSNC
(formerly New Sub II, Inc.) dated
February 12, 1999 (Filed as Exhibit
3.01 to Registration Statement No.
333-45206 and incorporated by
3.19 X reference herein)
Articles of Amendment of PSNC (formerly
New Sub II, Inc.) as adopted on February
10, 2000 (Filed as Exhibit 3.02 to
Registration Statement No. 333-45206 and
3.20 X incorporatedby reference herein)
Articles of Correction of PSNC dated
February 11, 2000 (Filed as Exhibit 3.03
3.21 X to Registration Statement No. 333-45206
and incorporated by reference herein)
3.22 X By-Laws of the CompanySCANA as revised and amended
thruon December 15, 1993 (Exhibit 3-AZ13, 2000 (Filed herewith)
3.23 X By-Laws of SCE&G as amended and adopted
on February 22, 2001 (Filed herewith)
3.24 X By-Laws of PSNC as revised and amended
on February 22, 2001 (Filed herewith)
Articles of Exchange of South Carolina
Electric & Gas Company and SCANA
Corporation (Filed as Exhibit 4-A to
4.01 X X Post-Effective Amendment No. 1 to
Registration Statement No.2-90438
and incorporated by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-K for the year ended December 31, 1993,
Fileof
No. 1-3375)......................................... #
4. Instruments Defining the RightsSCANA SCE&G PSNC Description
Indenture dated as of Security
Holders, Including Indentures
A.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
4.02 X by reference herein)
Indenture dated as of January 1, 1945,
frombetween the South Carolina Power
Company (the "Power Company")
toand Central Hanover Bank and
Trust Company, as Trustee, as
supplemented by three Supplemental
Indentures dated respectively as of May
1, 1946, May 1, 1947 and July 1, 1949
(Exhibit(Filed as Exhibit 2-B to Registration
Statement No. 2-26459)................................ #
B.2-26459 and incorporated
4.03 X X by reference herein)
Fourth Supplemental Indenture dated as
of April 1, 1950, to Indenture referred
to in Exhibit 4A,4.03, pursuant to which
the CompanySCE&G assumed said Indenture (Exhibit
2-C to Registration Statement No.
2-26459)...... #
C. Fifth through Fifty-second Supplemental Indentures
to Indenture referred to in Exhibit 4A dated as
of the dates indicated below4.04 X X 2-26459 and filed as
exhibits to the Registration Statements and
1934 Act reports whose file numbers are set
forth below.............................................. #
December 1, 1950 Exhibit 2-D to Registration No. 2-26459
July 1, 1951 Exhibit 2-E to Registration No. 2-26459
June 1, 1953 Exhibit 2-F to Registration No. 2-26459
June 1, 1955 Exhibit 2-G to Registration No. 2-26459
November 1, 1957 Exhibit 2-H to Registration No. 2-26459
September 1, 1958 Exhibit 2-I to Registration No. 2-26459
September 1, 1960 Exhibit 2-J to Registration No. 2-26459
# Incorporated hereinincorporated by reference
as indicated.
68herein)
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
4. (continued)
June 1, 1961 Exhibit 2-K to Registration No. 2-26459
December 1, 1965 Exhibit 2-L to Registration No. 2-26459
June 1, 1966 Exhibit 2-M to Registration No. 2-26459
June 1, 1967 Exhibit 2-N to Registration No. 2-29693
September 1, 1968 Exhibit 4-O to Registration No. 2-31569
June 1, 1969 Exhibit 4-C to Registration No. 33-38580
December 1, 1969 Exhibit 4-Q to Registration No. 2-35388
June 1, 1970 Exhibit 4-R to Registration No. 2-37363
March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324
January 1, 1972 Exhibit 4-C to Registration No. 33-38580
July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291
May 1, 1975 Exhibit 4-C to Registration No. 33-38580
July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908
February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304
December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936
March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662
May 1, 1977 Exhibit 4-C to Registration No. 33-38580
February 1, 1978 Exhibit 4-C to Registration No. 33-38580
June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653
April 1, 1979 Exhibit 4-C to Registration No. 33-38580
June 1, 1979 Exhibit 4-C to Registration No. 33-38580
April 1, 1980 Exhibit 4-C to Registration No. 33-38580
June 1, 1980 Exhibit 4-C to Registration No. 33-38580
December 1, 1980 Exhibit 4-C to Registration No. 33-38580
April 1, 1981 Exhibit 4-D to Registration No. 33-49421
June 1, 1981 Exhibit 4-D to Registration No. 2-73321
March 1, 1982 Exhibit 4-D to Registration No. 33-49421
April 15, 1982 Exhibit 4-D to Registration No. 33-49421
May 1, 1982 Exhibit 4-D to Registration No. 33-49421
December 1, 1984 Exhibit 4-D to Registration No. 33-49421
December 1, 1985 Exhibit 4-D to Registration No. 33-49421
June 1, 1986 Exhibit 4-D to Registration No. 33-49421
February 1, 1987 Exhibit 4-D to Registration No. 33-49421
September 1, 1987 Exhibit 4-D to Registration No. 33-49421
January 1, 1989 Exhibit 4-D to Registration No. 33-49421
January 1, 1991 Exhibit 4-D to Registration No. 33-49421
February 1, 1991 Exhibit 4-D to Registration No. 33-49421
July 15, 1991 Exhibit 4-D to Registration No. 33-49421
August 15, 1991 Exhibit 4-D to Registration No. 33-49421
April 1, 1993 Exhibit 4-E to Registration No. 33-49421
July 1, 1993 Exhibit 4-D to Registration No. 33-57955
D.
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
4.05 X X 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
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
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
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
4.06 X X Statement No. 33-49421)......................................... #
E.33-49421 and
incorporated by reference herein)
First Supplemental Indenture to
Indenture referred to in 4-DExhibit 4.06
dated as of June 1, 1993 (Filed as
Exhibit 4-G to Registration Statement
No. 33-49421)......................... #
F.33-49421 and
4.07 X X incorporated by reference herein)
Second Supplemental Indenture to
Indenture referred to in 4-DExhibit 4.06
dated as of June 15, 1993 (Filed as
Exhibit 4-G to Registration Statement
No. 33-57955)......................... #
9. Voting33-57955 and
4.08 X X incorporated by reference herein)
Trust Agreement Notfor SCE&G Trust I
(Filed as Exhibit 4.03 to Registration
4.09 X X Statement No. 333-49960 and
incorporated by reference herein)
Certificate of Trust of SCE&G Trust I
(Filed as Exhibit 4.04 to Registration
4.10 X X Statement No. 333-49960 and
incorporated by reference herein)
Junior Subordinated Indenture for
SCE&G Trust I (Filed as Exhibit 4.05
4.11 X X to Registration Statement No.333-49960
and incorporated by reference herein)
Guarantee Agreement for SCE&G Trust I
(Filed as Exhibit 4.06 to Registration
4.12 X X Statement No. 333-49960 and
incorporated by reference herein)
Amended and Restated Trust Agreement
for SCE&G Trust I (Filed as Exhibit
4.13 X X 4.07 to Registration Statement No.
333-49960 and incorporated by
reference herein)
EXHIBIT INDEX
Exhibit Applicable 10. Material Contracts
A. Copyto Form 10-K of
No. SCANA SCE&G PSNC Description
Debenture Purchase Agreement, dated as of
September 15, 1988, with respect to $25
million of 10% Senior Debentures due
October 1, 2003 (Filed as Exhibit 4.01 to
4.14 X X Registration Statement No. 333-45206 and
incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of September 15, 1988, between
PSNC and Southland Life Insurance Company
(Filed as Exhibit 4.02 to Registration
Statement No. 333-45206 and
4.15 X X incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of September 15, 1988, between
PSNC and Jefferson-Pilot Life Insurance
Company (Filed as Exhibit 4.03 to
Registration Statement No. 333-45206
4.16 X X and incorporated by reference herein)
Amendment to Debenture Purchase Agreemen
dated as of September 15, 1988, between
PSNC and The Franklin Life Insurance
Company (Filed as Exhibit 4.04 to
Registration Statement No. 333-45206
4.17 X X and incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of September 15, 1988, between
PSNC and Columbus Life Insurance Company
(Filed as Exhibit 4.05 to Form 10-Q for
the quarter ended September 30, 2000
4.18 X X and incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of September 15, 1988, between
PSNC and Salkeld & Company (Filed as
Exhibit 4.06 to Form 10-Q for the quarter
ended September 30, 2000 and
4.19 X X incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of September 15, 1988, between
PSNC and UMB Bank (Filed as Exhibit 4.07
to Form 10-Q for the quarter ended
September 30, 2000 and incorporated
4.20 X X by reference herein)
Debenture Purchase Agreement, dated as of
December 5, 1989, as amended, with
respect to $43 million of 10% Senior
Debentures due December 1, 2004 (Filed as
Exhibit 4.05 to
4.21 X X Registration Statement No. 333-45206 and
incorporated by reference herein)
Amendment to Debenture Purchase Agreement
dated as of December 5, 1989, between
PSNC and The Prudential Life Insurance
Company of America (Filed as Exhibit 4.06
to
4.22 X X Registration Statement No. 333-45206 and
incorporated by reference herein)
Debenture Purchase Agreement, dated as of
June 25, 1992, with respect to $32
million of 8.75% Senior Debentures due
June 30, 2012 (Filed as Exhibit 4.07 to
Registration Statement No. 333-45206
4.23 X X and incorporated by reference herein)
Indenture dated as of January 1, 1996
between PSNC and First Union National
4.24 X X (Filed as Exhibit 4.08 to Registration
Statement No.333-45206 and incorporated
by reference herein)
First Supplemental Indenture dated as of
4.25 X X January 1, 1996, between PSNC and Bank of
North Carolina, as Trustee (Filed
as Exhibit 4.08 to Registration Statement
(Filed as Exhibit 4.09 to Registration
Statement No. 333-45206 and incorporated
by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
Second Supplemental Indenture dated as
of December 15, 1996 between PSNC and
First Union National Bank of North
Carolina, as Trustee (Filed as Exhibit
4.10 to Registration Statement No.
4.26 X X 333-45206 and incorporated by reference
herein)
Third Supplemental Indenture dated as
of February 10, 2000 between PSNC and
First Union National Bank of North
Carolina, as Trustee (Filed as Exhibit
4.11 to
4.27 X X Registration Statement No. 333-45206
and incorporated by reference herein)
Fourth Supplemental Indenture dated as
of February 12, 2001 between PSNC and
First Union National Bank of North
4.28 X X Carolina, as Trustee (Filed herewith)
4.29 X PSNC $150 million medium-term note
issued February 16, 2001 (Filed
herewith)
SCANA Voluntary Deferral Plan as
amended through October 21, 1997 (File
as Exhibit 10.01 to Registration
10.01 X Statement No. 333-49960 and
incorporated by reference herein)
SCANA Supplementary Executive
Retirement Plan (Exhibit 10-Aas amended and restated
effective as of October 21, 1997 (Filed
as Exhibit 10.01(b) to Registration
Statement No.333-86803 and incorporated
10.02 X by reference herein)
SCANA Supplementary Voluntary Deferral
Plan as amended and restated through
October 21, 1997 (Filed as Exhibit
10.02 to Registration Statement No.
333-49960 and
10.03 X incorporated by reference herein)
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
10.04 X and incorporated by reference herein)
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
10.05 X reference herein)
SCANA Performance Share Plan as amended
and restated effective January 1, 1998
(Filed as Exhibit 10 (e) to
Registration Statement No. 333-86803
and incorporated by
10.06 X reference herein)
SCANA Long-Term Equity Compensation
Plan dated January 2000 filed as
Exhibit 4.04 to Registration Statement
10.07 X No. 333-37398 and incorporated by
reference herein)
SCANA Key Employee Retention Plan as
amended and restated effective as of
October 21, 1997 (Filed as Exhibit
10.02 to Registration Statement No.
333-49960 and
10.08 X incorporated by reference herein)
Description of SCANA Whole Life Option
(Filed as Exhibit 10-F to Form 10-K for
the year ended December 31, 1980)............................................ #
11.1991, under
cover of Form SE, File No. 1-8809 and
10.09 X incorporated by reference herein)
EXHIBIT INDEX
Exhibit Applicable to Form 10-K of
No. SCANA SCE&G PSNC Description
10.10 X Description of SCANA Corporation
Annual Incentive Plan (Filed as
Exhibit 10-G to Form 10-K for the
year ended December 31, 1991, under
cover of Form SE, File No.1-8809
and incorporated by reference herein)
SCANA Corporation Director Compensation
and Deferral Plan effective January 1,
2001(Filed as Exhibit 10.05 to Registra
tion Statement No. 333-49960 and
incorporated by
10.11 X reference herein)
Operating Agreement of Pine Needle LNG
Company, LLC dated August 8, 1995 (Filed
as Exhibit 10.01 to Registration
Statement No. 333-45206 and incorporate
10.12 X by reference herein)
Amendment to Operating Agreement of Pin
Needle LNG Company, LLC dated October 1,
1995 (Filed as Exhibit 10.02 to
Registration Statement No. 333-45206 and
10.13 X incorporated by reference herein)
Amended Operating Agreement of Cardinal
Extension Company, LLC dated December
19, 1996 (Filed as Exhibit 10.03 to
Registration Statement No. 333-45206 and
10.14 X incorporated by reference herein)
Amended Construction, Operation and
Maintenance Agreement by and between
Cardinal Operating Company and Cardinal
Extension Company, LLC dated December
19, 1996 (Filed as Exhibit 10.04 to
Registration Statement No. 333-45206 and
incorporated by
10.15 X reference herein)
Form of Severance Agreement between PSNC
and its Executive Officers (Filed as
Exhibit 10.05 to Registration Statement
No.333-45206 and incorporated by
reference
10.16 X herein)
Service Agreement between PSNC and
SCANA Services, Inc., effective
April 1, 2000 (Filed as Exhibit
10.06 to Registration Statement No.
333-45206 and incorporated by
10.17 X reference herein)
12.01 X X X Statement Re Computation of Per Share Earnings
Not Applicable
# Incorporated herein by reference as indicated.
69
SOUTH CAROLINA ELECTRIC & GAS COMPANY
Exhibit Index (Continued)
Sequentially
Numbered
Number Pages
12. Statement re Computation of Ratios
(Filed herewith)........ 74
13. Annual Report to Security Holders, Form 10-Q or
Quarterly Report to Security Holders
Not Applicable
16. Letter Re Change in Certifying Accountant
Not Applicable
18. Letter Re Change in Accounting Principles
Not Applicable
21. Subsidiaries of the Registrant
Not Applicable
22. Published Report Regarding Matters Submitted to
Vote of Security Holders
Not Applicable
23.23.01 X Consents of Experts and Counsel
Consent of Deloitte & Touche LLP.......................... 78
24.(Independent Auditors' Consent)
24.01 X X X Power of Attorney Not Applicable
27. Financial Data Schedule
Filed herewith
28. Information from Reports furnished to State
Insurance Regulatory Authorities
Not Applicable
99. Additional Exhibits
Not Applicable
# Incorporated herein by reference as indicated.
70(Filed herewith)