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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-3382
CAROLINA POWER & LIGHT COMPANY
------------------------------
(Exact name of registrant as specified in its charter)
411 Fayetteville Street
North Carolina 56-0165465 Raleigh, North Carolina 27601
- -------------- ---------- ----------------------- -----
(State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
919-546-6111
------------
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
-----------------------------------------------------------
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
Quarterly Income Capital Securities New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
-----------------------------------------------------------
Preferred Stock (Without Par Value, Cumulative)
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting and non-voting common stock held by
non-affiliates at February 26, 1999, was $6,034,582,932.
Shares of Common Stock (Without Par Value) outstanding at February 26, 1999:
151,337,503.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
Portions of the Company's 1999 definitive proxy statement dated April 1, 1999,
are incorporated into Part III, Items 10, 11, 12 and 13 hereof.
TABLE OF CONTENTS
Page
----
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS 5
PART I
ITEM 1. BUSINESS 6
General 6
Generating Capability 7
Interconnections with Other Systems 9
Competition 10
Capital Requirements 14
Financing Requirements 14
Retail Rate Matters 16
Wholesale Rate Matters 18
Environmental Matters 18
Nuclear Matters 19
Fuel 23
NCNG Merger 25
Diversified Businesses 25
Other Matters 26
Operating Statistics 28
ITEM 2. PROPERTIES 29
ITEM 3. LEGAL PROCEEDINGS 30
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 30
EXECUTIVE OFFICERS OF THE REGISTRANT 31
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS 33
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 36
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 49
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 73
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 73
ITEM 11. EXECUTIVE COMPENSATION 73
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 73
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 73
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 73
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
Examples of forward-looking statements discussed in this Form 10-K, PART I, ITEM
1, "BUSINESS", include, but are not limited to, statements under the following
headings: 1) "General" relating to forecasted capacity margins over anticipated
system peak loads; 2) "Generating Capability" regarding the forecasted system
sales growth and planned generation additions schedule; 3) "Interconnections
with Other Systems" relating to future energy cost savings resulting from
amendments to agreements with Cogentrix and relating to estimated minimum annual
payments for long-term purchase contracts; 4) "Competition" regarding the effect
on the Company of increased competition at the wholesale level and the
likelihood of additional industry restructuring-related bills being introduced
in Congress in 1999; 5) "Capital Requirements" relating to estimated capital
requirements for 1999-2001; 6) "Financing Program" relating to expected external
funding requirements; 7) "Environmental Matters" relating to future capital
expenditures to meet nitrogen oxide emission requirements, emerging regulatory
requirements and the materiality of future costs related to environmental
matters; 8) "Nuclear Matters" relating to future capital expenditures for
modifications at the Company's nuclear units, future increase in low-level
radioactive waste disposal costs, materiality of various nuclear-related
matters; 9) "Fuel" regarding the percentages of future coal burn requirements
from intermediate and long-term agreements, effect of amendments to the Clean
Air Act on the price of low sulfur coal, sufficiency of existing uranium
contracts and regarding total decontamination and decommissioning fund fees
expected to be paid; and 10) "Diversified Businesses" relating to future
services to be provided by Interpath Communications, Inc., and Strategic
Resource Solutions Corp.'s enhanced ability to deliver energy-management
products.
In addition, examples of forward-looking statements discussed in this Form 10-K,
PART II, ITEM 7, "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS", include, but are not limited to, statements under
the following headings: 1) "Liquidity and Capital Resources" about estimated
capital requirements through the year 2001 and 2) "Other Matters" about the
effects of new environmental regulations, nuclear decommissioning costs, the
effect of electric utility industry restructuring and the outcome of the Year
2000 compliance.
Any forward-looking statement speaks only as of the date on which such statement
is made, and the Company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances after the date on
which such statement is made.
Examples of factors that should be considered with respect to any
forward-looking statements made throughout this document include, but are not
limited to, the following: Governmental policies and regulatory actions
(including those of the Federal Energy Regulatory Commission, the Environmental
Protection Agency, the Nuclear Regulatory Commission, the Department of Energy,
the North Carolina Utilities Commission and the South Carolina Public Service
Commission); general industry trends; operation of nuclear power facilities;
availability of nuclear waste storage facilities; nuclear decommissioning costs;
changes in the economy of areas served by the Company; legislative and
regulatory initiatives that impact the speed and degree of industry
restructuring; ability to obtain adequate and timely rate recovery of costs,
including potential stranded costs arising from industry restructuring;
competition from other energy suppliers; the success of the Company's
diversified businesses; ability of the Company and its suppliers and customers
to successfully address Year 2000 readiness issues; weather conditions and
catastrophic weather-related damage; market demand for energy; inflation;
capital market conditions; unanticipated changes in operating expenses and
capital expenditures; and legal and administrative proceedings. All such factors
are difficult to predict, contain uncertainties that may materially affect
actual results, and may be beyond the control of the Company. New factors emerge
from time to time and it is not possible for management to predict all of such
factors, nor can it assess the effect of each such factor on the Company.
PART I
ITEM 1. BUSINESS
GENERAL
1. COMPANY. Carolina Power & Light Company (the Company) is a public
service corporation formed under the laws of North Carolina in 1926, and
is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North and South Carolina. The Company
had approximately 7,200 employees at December 31, 1998. The principal
executive offices of the Company are located at 411 Fayetteville Street,
Raleigh, North Carolina 27601, telephone number: 919-546-6111.
2. FRANCHISES. The Company is a regulated public utility and holds
franchises to the extent necessary to operate in the municipalities and
other areas it serves.
3. SERVICE. The territory served, an area of approximately 30,000 square
miles, includes a substantial portion of the coastal plain of North
Carolina extending to the Atlantic coast between the Pamlico River and
the South Carolina border, the lower Piedmont section of North Carolina,
an area in northeastern South Carolina and an area in western North
Carolina in and around the City of Asheville. The estimated total
population of the territory served is approximately 3.9 million.
The Company provides retail electricity in over 200 communities, each
having an estimated population of 500 or more, and at wholesale to North
Carolina Eastern Municipal Power Agency (Power Agency) consisting of 32
members, 3 municipalities, French Broad Electric Membership Corporation
and North Carolina Electric Membership Corporation (NCEMC) consisting of
27 members (17 of which are served by the Company's system). At December
31, 1998, the Company was furnishing electric service to approximately
1,183,000 customers.
4. SALES. During 1998, 33% of operating revenues were derived from
residential sales, 22% from commercial sales, 23% from industrial sales,
13% from wholesale sales and 9% from other sources. Of such operating
revenues, approximately 67% were derived from North Carolina retail
customers, 13% from South Carolina retail customers, 13% from North
Carolina wholesale customers, less than 1% from South Carolina wholesale
customers and 6% from sales to other utilities and other customers.
5. PEAK DEMAND. A 60-minute system peak demand record of 10,529 megawatts
(MW) was reached on July 23, 1998. At the time of this peak demand, the
Company's capacity margin, based on installed capacity (less unavailable
capacity) and scheduled firm purchases and sales, was approximately
7.6%.
Total system peak demand decreased for 1996 by 3.4%, for 1997 increased
by 2.2%, and for 1998 increased by 5.0% as compared with the preceding
year. The Company currently projects that system peak demand will
increase at an average annual growth rate of approximately 2.8% over the
next ten years. The year-to-year change in actual peak demand is
influenced by the specific weather conditions during those years and may
not exhibit a consistent pattern. Total system load factors, expressed
as the ratio of the average load supplied to the peak load demand, were
60.8% for 1996, 60.6% for 1997, and 60.1% for 1998. The Company
forecasts capacity margins of 10.8% over anticipated system peak load
for 1999 and 11% for 2000. This forecast assumes normal weather
conditions in each year consistent with long-term experience, and is
based upon the rated Maximum Dependable Capacity of generating units in
commercial operation and scheduled firm purchases of power. See PART I,
ITEM 1, "Generating Capability" and "Interconnections With Other
Systems". However, some of the generating units included in arriving at
these capacity margins may be unavailable as a result of scheduled and
unplanned outages. See PART I, ITEM 1, "Nuclear Matters". The data
contained in this paragraph includes Power Agency's load requirements
and capability from its ownership interests in certain of the Company's
generating facilities. See PART I, ITEM 1, "Generating Capability",
paragraph 1.
GENERATING CAPABILITY
1. FACILITIES. At December 31, 1998, the Company had a total system
installed generating capability (including Power Agency's share) of
9,963 MW, with generating capacity provided primarily from the installed
generating facilities listed in the table below. The remainder of the
Company's generating capacity is composed of 53 coal, hydro and
combustion turbine units ranging in size from a 2.5 MW hydro unit to a
78 MW coal-fired unit. Pursuant to certain agreements with the Company,
Power Agency has acquired undivided ownership interests of 18.33% in
Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4 and 16.17% in
Harris Unit No. 1 and Mayo Unit No. 1. Of the total system installed
generating capability of 9,963 MW, 53% is coal, 32% is nuclear, 2% is
hydro and 13% is fired by other fuels including No. 2 oil, natural gas
and propane.
MAJOR INSTALLED GENERATING FACILITIES
AT DECEMBER 31, 1998
Year Maximum
Commercial Primary Dependable
Plant Location Unit No. Operation Fuel Capacity
-------------- -------- --------- ---- --------
Asheville 1 1964 Coal 198 MW
(Skyland, N.C.) 2 1971 Coal 194 MW
Cape Fear 5 1956 Coal 143MW
(Moncure, N.C.) 6 1958 Coal 173MW
Darlington County Plant 12 1997 Gas/Oil 120MW
(Hartsville, S.C.) 13 1997 Gas/Oil 120MW
H.F. Lee 1 1952 Coal 79MW
(Goldsboro, N.C.) 2 1951 Coal 76MW
3 1962 Coal 252MW
H.B. Robinson 1 1960 Coal 174MW
(Hartsville, S.C.) 2 1971 Nuclear 683MW
Roxboro 1 1966 Coal 385MW
(Roxboro, N.C.) 2 1968 Coal 670MW
3 1973 Coal 707MW
4 1980 Coal 700MW*
L.V. Sutton 1 1954 Coal 97MW
(Wilmington, N.C.) 2 1955 Coal 106MW
3 1972 Coal 410MW
Brunswick 1 1977 Nuclear 820MW*
(Southport, N.C.) 2 1975 Nuclear 811MW*
Mayo 1 1983 Coal 745MW*
(Roxboro, N.C.)
Harris 1 1987 Nuclear 860MW*
(New Hill, N.C.)
* Facilities are jointly owned by the Company and Power Agency, and
the capacity shown includes Power Agency's share.
2. MAINTENANCE OF PROPERTIES. The Company maintains all of its properties
in good operating condition in accordance with sound management
practices. The average life expectancy for ratemaking and accounting
purposes of the Company's generating facilities (excluding combustion
turbine units and hydro units) is approximately 40 years from the date
of commercial operation.
3. GENERATION ADDITIONS SCHEDULE. The Company's energy and load forecasts
were revised in December 1998. Over the next ten years, system internal
sales growth is forecasted to average approximately 2.8% per year and
annual growth in system internal peak demand is projected to average
approximately 2.8%. The Company's generation additions schedule provides
for the addition of approximately 2,800 MW of combustion turbine
capacity and 2,500 MW of combined cycle capacity over the period 1999 to
2008 in order to meet the needs of its growing customer base and
increase its ability to participate in the wholesale power market. The
Company may alter its long-term plans based on changes in load
forecasts, market conditions, and other factors. In addition, see Part
I, Item 1 "Interconnections with Other Systems" for discussion of the
Company's long-term purchase power contracts.
On August 18, 1998 the Company filed with the North Carolina Utility
Commission (NCUC) an Application for a Certificate of Public Convenience
and Necessity to construct an additional 177 MW of combustion turbine
capacity adjacent to the Company's Lee Steam Electric Plant in Wayne
County, North Carolina and a second 160 MW combustion turbine unit at
the Company's Asheville Steam Electric Plant in Buncombe County, North
Carolina. The Wayne County Turbine is in addition to the 500 MW of
combustion turbine capacity for which the Company received a Certificate
of Public Convenience and Necessity on March 21, 1996. These units will
primarily be used during periods of summer and winter peak demands. By
order issued December 17, 1998, the NCUC granted the Company a
Certificate to construct both units. Construction of the combustion
turbines began during the first quarter of 1999. Commercial operation is
anticipated to begin in June 2000.
On November 17, 1998, the Company made a pre-filing with the NCUC of its
plans to construct 1100 MW of combustion turbine generating capacity in
Rowan County, North Carolina. On February 17, 1999, the company filed an
amendment to its November 17, 1998 pre-filing. The amendment changed the
filing in two areas. First, the amount of new combustion turbine
generating capacity to be built was increased to 1,600 MW, and second,
the site location was changed to a new site in Rowan County and a site
in Richmond County. The Company anticipates filing the actual
Application for a Certificate of Public Convenience and Necessity with
the NCUC on or about March 19, 1999.
INTERCONNECTIONS WITH OTHER SYSTEMS
1. INTERCONNECTIONS. The Company's facilities in Asheville and vicinity are
integrated into the total system through the facilities of Duke Energy
Corporation (Duke) via interconnection agreements that permit transfer
of power to and from the Asheville area. The Company also has major
interconnections with the Tennessee Valley Authority (TVA), Appalachian
Power Company (APCO), Virginia Power, South Carolina Electric and Gas
Company (SCE&G), South Carolina Public Service Authority (SCPSA) and
Yadkin, Inc. (Yadkin).
2. INTERCHANGE AND POWER PURCHASE/SALE AGREEMENTS.
a) The Company has interchange agreements with APCO, Duke, SCE&G,
SCPSA, TVA, Virginia Power and Yadkin which provide for the purchase
and sale of power for hourly, daily, weekly, monthly or longer
periods. In addition to the interchange agreements, the Company has
executed individual purchase agreements and sales agreements with
more than 100 companies beyond the Virginia-Carolinas Subregion
described in paragraph 2.b. below. Purchases and sales under these
agreements may be made due to economic or reliability
considerations.
By letter dated May 24, 1996, the Company provided Duke with written
notice that effective June 1999, it will terminate Schedule G to the
Interchange Agreement between the Company and Duke. Schedule G
provides for the wheeling of electricity between the Company's
eastern area and its western area.
By letter dated December 30, 1996, Duke provided the Company with
written notice that effective December 31, 1999, it will terminate
the Standby Concurrent Exchange Agreement (Standby Agreement)
between the Company and Duke. The Standby Agreement provides for the
simultaneous exchange of up to 70 MW of electricity during periods
of scheduled maintenance or breakdown.
On December 31, 1996, pursuant to the Federal Energy Regulatory
Commission (FERC) Order 888, which directs that no bundled economy
energy coordination transactions occur after December 31, 1996, the
Company submitted to the FERC a compliance filing to unbundle
transmission charges from rate schedules that are applicable to the
power sales agreements between the Company and others. See PART I,
ITEM 1, "Competition", paragraph 2, for further discussion of the
FERC Order 888.
b) The Virginia-Carolinas Subregion of the Southeastern Electric
Reliability Council is principally made up of the Company, Duke,
Nantahala Power & Light Company, SCE&G, SCPSA, Virginia Power,
Southeastern Power Administration and Yadkin. Electric service
reliability is promoted by arrangements among the members of
electric reliability organizations at the subregional level.
3. LONG-TERM PURCHASE POWER CONTRACTS.
a) In March 1987, the Company entered into an agreement with Duke,
which has been accepted by the FERC, whereby Duke would provide 400
MW of firm capacity to the Company's system over the period January
1, 1992, through December 31, 1997. Pursuant to an amendment of the
contract, commencement of the purchase of power by the Company was
delayed until July 1993 and termination was extended through June
1999. The estimated minimum annual payment for power purchases under
the six-year agreement is approximately $48 million, representing
capital-related capacity costs. Purchases under this agreement,
including transmission use charges, totaled $75.5
million in 1998.
b) The Company has entered into an agreement, which has been approved
by the FERC, with APCO and Indiana Michigan Power Company (Indiana
Michigan), operating subsidiaries of American Electric Power
Company, to upgrade transmission interconnections in the Company's
western and eastern service areas and purchase 250 MW of generating
capacity from Indiana Michigan's Rockport Unit No. 2 through 2009.
Upgrades to the transmission interconnections in the Company's
western and eastern service area were completed in 1992 and 1998,
respectively. The estimated minimum annual payment for power
purchases under the agreement is approximately $31 million,
representing capital-related capacity costs. In 1998, purchases
under this agreement, including transmission use charges, totaled
$59.3 million.
c) In 1996, the Company agreed with Cogentrix of North Carolina, Inc.
and Cogentrix Eastern Carolina Corporation (collectively referred to
as Cogentrix) to amend electric power purchase agreements related to
five plants owned by Cogentrix. The amendments, which became
effective on September 26, 1996, permit the Company to dispatch the
output of the five plants. In return, the Company gave up its right
to purchase two of the five plants in 1997. As a result of the
amendments, the Company expects to realize energy cost savings
through the expiration of the agreement in 2002.
d) In December 1998, the Company entered into an agreement to purchase
all of the output of a combustion turbine project to be built,
owned, and operated by Broad River Energy, LLC, in Cherokee County,
South Carolina. The project is scheduled to be in service on or
before June 1, 2001 and is expected to have a net dependable
capacity of approximately 500 MWs. The agreement is for an initial
period of 15 years, with an option for the Company to extend the
agreement for two additional five year terms. During the term of the
agreement, the Company will have full rights to the output of the
project as well as control over the scheduling of the units.
4. POWER AGENCY. Pursuant to the terms of a 1981 Power Coordination
Agreement, as amended, between the Company and Power Agency, the Company
is obligated to purchase a percentage of Power Agency's ownership
capacity of, and energy from, the Harris Plant through 2007. A similar
buyback arrangement related to the Mayo Plant ended in 1997. The
estimated minimum annual payments for these purchases, which reflect
capital-related capacity costs, total approximately $26 million.
Purchases under the agreement with Power Agency totaled $34.4 million in
1998.
COMPETITION
1. GENERAL. In recent years, the electric utility industry has experienced
a substantial increase in competition at the wholesale level, caused by
changes in federal law and regulatory policy. Several states have also
decided to restructure aspects of retail electric service. The issue of
retail restructuring and competition is being reviewed by a number of
states and bills have been introduced in Congress that seek to introduce
such restructuring in all states.
Allowing increased competition in the generation and sale of electric
power will require resolution of many complex issues. One of the major
issues to be resolved is who will pay for stranded costs. Stranded costs
are those costs and investments made by utilities in order to meet their
statutory obligation to provide electric service, but which could not be
recovered through the market price for electricity following industry
restructuring. The amount of such stranded costs that the Company might
experience would depend on the timing of, and the extent to which,
direct competition is introduced, and the then-existing market price of
energy. If electric utilities were no longer subject to cost-based
regulation and it were not
possible to recover stranded costs, the financial position and results
of operations of the Company could be adversely affected.
2. WHOLESALE COMPETITION. Since passage of the National Energy Act of 1992
(Energy Act), competition in the wholesale electric utility industry has
significantly increased due to a greater participation by traditional
electricity suppliers, wholesale power marketers and brokers, and due to
the trading of energy futures contracts on various commodities
exchanges. This increased competition could affect the Company's load
forecasts, plans for power supply and wholesale energy sales and related
revenues. The impact could vary depending on the extent to which
additional generation is built to compete in the wholesale market, new
opportunities are created for the Company to expand its wholesale load,
or current wholesale customers elect to purchase from other suppliers
after existing contracts expire.
To assist in the development of wholesale competition, the Federal
Energy Regulatory commission (FERC), in 1996, issued standards for
wholesale wheeling of electric power through its rules on open access
transmission and stranded costs and on information systems and standards
of conduct (Orders 888 and 889). The rules require all transmitting
utilities to have on file an open access transmission tariff, which
contains provisions for the recovery of stranded costs and numerous
other provisions that could affect the sale of electric energy at the
wholesale level. The Company filed its open access transmission tariff
with the FERC in mid-1996. Shortly thereafter, Power Agency and other
entities filed protests challenging numerous aspects of the Company's
tariff and requesting that an evidentiary proceeding be held. The FERC
set the matter for hearing and set a discovery and procedural schedule.
In July 1997, the Company filed an offer of settlement in this matter.
The administrative law judge certified the offer to the full FERC in
September 1997. The offer is pending before the FERC. The Company cannot
predict the outcome of this matter.
In November 1997, the Company applied to the FERC for authority to sell
power at market-based rates. In January 1998, the FERC issued an order
accepting the Company's application and permitting the Company to sell
power at market-based rates. Excluding sales under specific long-term
wholesale agreements, the Company makes virtually all of its wholesale
power sales under its market-based rate tariff.
During the last week of June 1998, some wholesale power markets
experienced sharp increases in prices. That upsurge in power costs was
due, in part, to the unavailability of generating capacity and unusually
hot weather in the Midwestern portion of the country. The relatively
sudden movement in wholesale power prices disrupted certain power
transactions, including some to which the Company was a party. The
monetary damages the Company incurred as a result of those disrupted
transactions did not have a material adverse effect on the Company's
financial position and results of operations. The Company has taken
steps to mitigate those monetary damages. The Company anticipates
increased volatility in the wholesale power market during peak demand
periods; however, due to the risk management processes the Company has
in place, the Company does not expect this volatility to have a material
adverse effect on its financial position and results of operations.
3. RETAIL COMPETITION. The Energy Act prohibits the FERC from ordering
retail wheeling - transmitting power on behalf of another producer to an
individual retail customer. Several states have changed their laws and
regulations to allow full retail competition. Other states are
considering changes to allow retail competition. These changes and
proposals have taken differing forms and included disparate elements.
The Company believes changes in existing laws in both North and South
Carolina would be required to permit competition in the Company's retail
jurisdictions.
4. NORTH CAROLINA ACTIVITIES. Since 1995, the NCUC has been considering the
impact of increased competition in the electric utility industry. In May
1996, the NCUC issued an order stating that the FERC Orders 888 and 889
would provide a new focus for NCUC proceedings with respect to
competition in the electric industry. As a result, the NCUC held Docket
No. E-100, Sub 77, which concerned retail competition, in abeyance
pending further order and established a new docket (Docket No. E-100,
Sub 78)
to address the FERC Orders 888 and 889. The NCUC has received several
rounds of comments in this docket; the Company filed its most recent
comments and reply comments in November 1997 and December 1997,
respectively. By order issued June 18, 1998, the Commission held that
this docket would also be held in abeyance pending further order. The
Company cannot predict the outcome of this matter.
In April 1997, the North Carolina General Assembly (General Assembly)
approved legislation establishing a 23-member study commission to
evaluate the future of electric service in the state. During 1998, the
study commission met and held public hearings around the state. The
commission also retained consultants to conduct analyses and studies
concerning various restructuring issues, including stranded costs, state
and local tax implications and electric rate comparisons. In June 1998,
the study commission issued an interim report to the 1998 General
Assembly, summarizing the numerous fact-finding and educational
activities and analytical projects the commission had initiated or
completed. That report offered no judgments or recommendations. The
commission is scheduled to make its final report to the 1999 Session of
the General Assembly which will begin in 1999 and continue during 2000.
The Company cannot predict the outcome of this matter.
5. SOUTH CAROLINA ACTIVITIES. The South Carolina General Assembly ended its
1998 session without enacting any legislation regarding electric
restructuring. On October 29, 1998, the South Carolina Senate Judiciary
Committee appointed a 13-member task force to study the restructuring
issue and make a report to the South Carolina General Assembly during
the 1999 legislative session. The task force was subsequently expanded
to 18 members, including the Company. The General Assembly's House
Utility Subcommittee is also expected to continue pursuing the issue
during that session. The Company cannot predict the outcome of these
matters.
6. FEDERAL ACTIVITIES. At the federal level, additional bills regarding
restructuring of the electric utility industry were introduced in 1998,
but Congress adjourned in October without taking any action on the
issue. The debate regarding industry restructuring is expected to
continue in Congress in 1999. The Company cannot predict the outcome of
this matter.
7. COMPANY ACTIVITIES. The developments described above have created
changing markets for energy. As a strategy for competing in these
changing markets, the Company is becoming a total energy provider in the
region by providing a full array of energy-related services to its
current customers and expanding its market reach. As part of this
strategy, the Company plans to position itself as a supplier of natural
gas to its customers. The Company took a major step towards reaching
this goal on November 10, 1998 by entering into the Merger Agreement
with North Carolina Natural Gas Corporation (NCNG).
On March 3, 1999, the Company and Southern Natural Gas Co., a subsidiary
of Sonat Inc., announced plans to form a 50/50 joint venture to
construct, own and operate a 175 mile, 30-inch natural gas pipeline from
Aiken, South Carolina to an interconnect with the NCNG system in Robeson
County, North Carolina. The new Palmetto Interstate Pipeline will have a
capacity of 200 million to 300 million cubic feet per day and will be
expandable to accommodate future growth and demand along its route. Most
of the pipeline's capacity will be used by the Company to fuel new
electric generation it will develop in the Carolinas over the next
several years. The remaining pipeline capacity will be used to increase
the region's natural gas availability. Construction of the new pipeline
will begin after engineering, environmental preparation and federal and
state permitting are completed. The current schedule calls for
construction to begin mid-2001, with the pipeline to be operational in
April 2002. The pipeline's cost is expected to be $200 million to $250
million.
The Company currently plans to construct approximately 2300 MW of new
generating facilities by the year 2002. These facilities, including two
combustion turbine facilities outside of the Company's current service
area, will help the Company continue to meet the needs of its growing
retail customer base and increase its ability to participate in the
wholesale energy supply business.
The Company's strategy for addressing the planning uncertainty and risks
created by the changing markets for energy includes securing long-term
contracts with its wholesale customers, continuing to work to meet the
energy needs of its industrial customers, promoting economic
development, implementing new marketing strategies, improving customer
satisfaction, and increasing the focus on managing and reducing costs
and, consequently, avoiding future rate increases.
In 1996, Power Agency notified the Company that it would discontinue
certain contractual purchases of power from the Company effective
September 1, 2001; however, the Company won the right to continue
supplying this power by being selected from a number of bidders. On
September 11, 1998, the Company and Power Agency entered into a revised
agreement that extends the period during which Power Agency will
continue to purchase all of its supplemental power from the Company
through at least December 31, 2002. The new agreement also includes
options for Power Agency to purchase supplemental power from the Company
for the year 2003 and beyond. The load served by supplemental power
under that agreement will include all of Power Agency's power needs in
excess of the load served by Power Agency through its ownership interest
in generation units that it jointly owns with the Company and other
smaller resources that are currently in place. The revised agreement was
filed with, and has been accepted by, the FERC.
On October 9, 1998, the Company and its largest customer, NCEMC, entered
into an agreement under which NCEMC will purchase a total of 800 MWs of
peaking capacity and associated energy from the Company during the
period from January 1, 2001 through December 31, 2003. The agreement,
which provides NCEMC with an option to extend all or part of the
purchase through 2005, provides capacity to meet NCEMC's growing peaking
power needs. A portion of this purchase is intended to serve load
located in the Company's service area that is currently served by
purchases from the Company under a contract that will expire on December
31, 2000. During the period 2001 through 2003, this agreement also will
serve up to 450 MWs of NCEMC load that is located in the Duke Power
service area that has not previously been served by the Company. The
agreement will be filed with the FERC for approval or acceptance. The
Company cannot predict the outcome of this matter.
On October 30, 1998, the Company and NCEMC also entered into agreements
that supersede the 1993 Power Coordination Agreement between the Company
and NCEMC, as amended (the PCA). The primary effect of the new
agreements is to unbundle the generation and transmission service for
the load previously served under the PCA. To that end, the parties
executed a Network Integration Transmission Service Agreement and a
Network Operating Agreement under which NCEMC will receive transmission
services from the Company pursuant to the Company's Open Access
Transmission Tariff. The parties also entered into a new Power Supply
Agreement , which provides for the Company to sell capacity and energy
to NCEMC under terms and conditions and in amounts that are
substantially the same as those that were set forth in the PCA. The
parties agreed to a modification of the calculation of certain capacity
charges; however, the net effect of the changes is intended to be
essentially revenue neutral under expected load conditions. The Network
Integration Transmission Service Agreement, the Network Operating
Agreement and the new Power Supply Agreement were filed with FERC on
November 3, 1998 and have been accepted. The new Power Supply Agreement
has also been submitted by NCEMC to the Rural Utilities Service for
approval. The Company cannot predict the outcome of this matter.
On September 28, 1998, the Company and the South Carolina Public Service
Authority (Santee Cooper) entered into an agreement under which the
Company will provide peaking capacity and associated energy to Santee
Cooper for the period January 1, 1999 through December 31, 2003. Under
the terms of the agreement, the Company will provide 100 MW of
generation capacity in 1999, 150 MW in 2000 and 200 MW from 2001 to
2003. The agreement was filed with, and has been accepted by, the FERC.
As a regulated entity, the Company is subject to the provisions of
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation," (SFAS-71). Accordingly, the
Company records certain assets and liabilities resulting from the
effects of the ratemaking process, which would not be recorded under
generally accepted accounting principles for unregulated entities. The
Company's ability to continue to meet the criteria for application of
SFAS-71 may be affected in the future by competitive forces and
restructuring in the electric utility industry. In the event that
SFAS-71 no longer applied to a separable portion of the Company's
operations, related regulatory assets and liabilities would be
eliminated unless an appropriate regulatory recovery mechanism is
provided. Additionally, these factors could result in an impairment of
electric utility plant assets as determined pursuant to Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
CAPITAL REQUIREMENTS
CAPITAL REQUIREMENTS. During 1998 the Company expended approximately
$725 million for capital requirements. Estimated capital requirements
for 1999 through 2001 primarily reflect construction expenditures to add
generation, transmission and distribution facilities, as well as upgrade
existing facilities. Those capital requirements are reflected in the
following table (in millions):
1999 2000 2001
---- ---- ----
Construction Expenditures $649 $860 $1,104
Nuclear Fuel Expenditures 77 93 64
AFUDC (17) (29) (54)
Mandatory Retirements of Long-Term Debt 53 198 -
---- ------ ------
TOTAL $762 $1,122 $1,114
==== ====== ======
This table includes environmental expenditures relating to the Clean Air
Act of approximately $27 million, and the NOx SIP Call of approximately
$195 million. See PART I, ITEM 1, "Environmental Matters", paragraph 2,
and "Generating Capability", paragraph 3, for further discussion of the
impact of the Clean Air Act and NOx SIP Call on the Company, and planned
generation additions, respectively.
In addition, the Company has total projected cash requirements of
approximately $356 million for the years 1999 through 2001 relating to
expenditures in other areas such as affordable housing investments and
telecommunications infrastructure development. These projections are
periodically reviewed and may change significantly.
FINANCING REQUIREMENTS
1. FINANCING REQUIREMENTS. The proceeds from the issuance of commercial
paper related to the credit facilities mentioned below (see paragraph 5
below) and/or internally generated funds financed the retirement of
long-term debt totaling $205 million in 1998. External funding
requirements, which do not include early redemptions of long-term debt
or redemptions of preferred stock, are expected to approximate $375
million, $500 million and $460 million in 1999, 2000 and 2001,
respectively. These funds will be required for construction, mandatory
retirements of long-term debt and general corporate purposes. The amount
and timing of future sales of Company securities will depend upon market
conditions and the specific needs of the Company. The Company may from
time to time sell securities beyond the amount needed to meet capital
requirements in order to allow for the early redemption of long-term
debt, the redemption of preferred stock, the reduction of short-term
debt or for other general corporate purposes. See PART II, ITEM 7,
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS", for further analysis and discussion of the Company's
financing plans and capital resources and liquidity.
2. SEC FILINGS.
i) The Company has on file with the Securities and Exchange Commission
(SEC) a shelf registration statement (File No. 333-69237) under
which $1.5 billion aggregate principal amount of first mortgage
bonds, senior notes and other debt securities are available for
issuance by the Company.
ii) The Company has on file with the SEC a shelf registration statement
(File No. 33-5134) enabling the Company to issue up to $180 million
of Serial Preferred Stock.
3. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES.
External financings during 1998 and early 1999 included:
The issuance on March 5, 1999 of $400 million principal amount of Senior
Notes, 5.95% Series due March 1, 2009. The net proceeds of approximately
$390 million were used to reduce the outstanding balance of commercial
paper.
4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND DEBENTURES.
Redemptions and retirements during 1998 included:
i) The redemption on June 1, 1998, of $40 million principal amount of
First Mortgage Bonds, 6-7/8% Series due October 1, 1998.
ii) The retirement on July 1, 1998, of $100 million principal amount
of First Mortgage Bonds, 5-3/8% Series, which matured on that
date.
iii) The retirement on September 13, 1998, of $5 million principal
amount of First Mortgage Bonds, Secured Medium-Term Notes, 5.05%
Series C, which matured on that date.
iv) The retirement on September 13, 1998, of $5 million principal
amount of First Mortgage Bonds, Secured Medium-Term Notes, 5.06%
Series C, which matured on that date.
v) The retirement on September 15, 1998, of $20 million principal
amount of First Mortgage Bonds, Secured Medium-Term Notes, 5.00%
Series C, which matured on that date.
vi) The retirement on September 15, 1998, of $15 million principal
amount of First Mortgage Bonds, Secured Medium-Term Notes, 5.01%
Series C, which matured on that date.
vii) The retirement on October 19, 1998, of $20 million principal
amount of First Mortgage Bonds, Secured Medium-Term Notes, 5.00%
Series C, which matured on that date.
5. CREDIT FACILITIES. As of December 31, 1998, the Company's revolving credit
facilities totaled $750 million, all of which are long-term agreements
supporting its commercial paper borrowings. The Company is required to pay
minimal annual commitment fees to maintain its credit facilities. Consistent
with
management's intent to maintain its commercial paper on a long-term basis, and
as supported by its long- term revolving credit facilities, the Company included
in its long-term debt all commercial paper outstanding as of December 31, 1998
which amounted to $488 million. See PART II, ITEM 8, "CONSOLIDATED FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA", Note 4, for a more detailed discussion of
the Company's revolving credit facilities.
RETAIL RATE MATTERS
1. GENERAL. The Company is subject to regulation in North Carolina by the
NCUC and in South Carolina by the South Carolina Public Service
Commission (SCPSC) with respect to, among other things, rates and
service for electric energy sold at retail, retail service territory and
issuances of securities.
2. CURRENT RETAIL RATES. The rates of return granted to the Company in its
most recent general rate cases are as follows:
1988 North Carolina Utilities Commission Order
(test year ended March 31, 1987)
----------------------------------------------
Capital Weighted Weighted
Capital Structure Ratio Cost Rate Cost
----------------- ----- --------- ----
Long-Term Debt 48.57% 8.62% 4.19%
Preferred Stock 7.43 8.75 .65
Common Equity 44.00 12.75 5.61
----
Rate of Return 10.45%
=====
1988 South Carolina Public Service Commission Order
(test year ended September 30, 1987)
---------------------------------------------------
Capital Weighted Weighted
Capital Structure Ratio Cost Rate Cost
----------------- ----- --------- ----
Long-Term Debt 47.82% 8.62% 4.12%
Preferred Stock 7.46 8.75 .65
Common Equity 44.72 12.75 5.71
----
Rate of Return 10.48%
=====
3. OTHER RETAIL RATE MATTERS. A petition was filed in July 1996 by the
Carolina Industrial Group for Fair Utility Rates (CIGFUR) with the NCUC,
requesting that the NCUC conduct an investigation of the Company's base
rates or treat its petition as a complaint against the Company. The
petition alleged that the Company's return on equity (which was
authorized by the NCUC in the Company's last general rate proceeding in
1988) and earnings are too high. In December 1996, the NCUC issued an
order denying CIGFUR's petition and stating that it tentatively found no
reasonable grounds to proceed with CIGFUR's petition as a complaint.
Subsequently, CIGFUR filed a Motion for Reconsideration with the NCUC
and a Notice of Appeal with the North Carolina Court of Appeals, both of
which were denied. On December 4, 1998, a petition for Discretionary
Review filed by CIGFUR was denied by the North Carolina Supreme Court.
Pursuant to authorizations from the NCUC and the SCPSC, the Company
began to accelerate the amortization of certain regulatory assets over a
three-year period beginning January 1997. The accelerated
amortization of these regulatory assets results in additional
depreciation and amortization expenses of approximately $68 million in
each year of the three-year period.
In 1996, the NCUC also authorized the Company to defer operation and
maintenance expenses of approximately $40 million associated with
Hurricane Fran, with amortization over a 40-month period.
In late 1998 and early 1999, the Company filed, and the respective
commissions subsequently approved, proposals in the North and South
Carolina retail jurisdictions to accelerate cost recovery of its nuclear
generating assets beginning January 1, 2000 and continuing through 2004.
The accelerated cost recovery begins immediately after the 1999
expiration of the accelerated amortization of certain regulatory assets,
which began in January 1997. Pursuant to the orders, the Company's
depreciation expense for nuclear generating assets will increase by $106
million to $150 million per year. Recovering the costs of the nuclear
generating assets on an accelerated basis will better position the
Company for the uncertainties associated with potential restructuring of
the electric utility industry.
4. INTEGRATED RESOURCE PLANNING. Integrated resource planning is a process
that systematically compares all reasonably available resources, both
demand-side and supply-side, in order to develop that mix of resources
that allows a utility to meet customer demand in a cost-effective
manner, giving due regard to system reliability, safety and the
environment. In the past, utilities were required to file their
Integrated Resource Plans (IRP) with the NCUC and the SCPSC once every
three years. The Company regularly reviews its IRP in light of changing
conditions and evaluates the impact these changes have on its resource
plans, including purchases and other resource options. During 1998, the
NCUC and SCPSC substantially altered their IRP rules. Both the NCUC and
SCPSC reduced the amount of information that must be included in the
Company's IRP. The NCUC also eliminated the triennial IRP and now
requires an annual filing.
5. FUEL COST RECOVERY.
a) In the North Carolina retail jurisdiction, the NCUC establishes
base fuel costs in general rate cases and holds hearings annually
to determine whether a rider should be added to base fuel rates to
reflect increases or decreases in the cost of fuel and the fuel
cost component of purchased power as well as changes in the fuel
cost component of sales to other utilities. The NCUC considers the
changes in the Company's cost of fuel during a historic test
period ending March 31 of each year and corrects any past over- or
under-recovery. On June 4, 1998, the Company filed its 1998 fuel
cost recovery application. The NCUC issued a final order approving
the Company's proposed billing fuel factor of 1.079 cents/kWh on
September 9, 1998. This new factor became effective on September
15, 1998.
b) In the South Carolina retail jurisdiction, fuel rates are set by
the SCPSC. At the fuel hearings, any past over- or under-recovery
of fuel costs is taken into account in establishing the new rate.
On February 22, 1999, the Company filed a proposal with the SCPSC
to continue the existing fuel factor of 1.122 cents/kWh. The
Company's 1999 fuel hearing was held on March 24, 1999.
6. AVOIDED COST PROCEEDINGS. In 1998, the NCUC opened Docket No. E-100, Sub
81 for its biennial proceeding to establish the avoided cost rates for
all electric utilities in North Carolina. Avoided cost rates are
intended to reflect the costs that utilities are able to "avoid" by
purchasing power from qualifying facilities. The Company's initial
filing in this docket was made on November 6, 1998. Intervenor comments
on the utilities' filings were filed January 15, 1999, and a hearing for
non-expert public
witnesses was held on February 2, 1999. The Company cannot predict the
outcome of this matter.
WHOLESALE RATE MATTERS.
The Company is subject to regulation by the FERC with respect to rates for
transmission and sale of electric energy at wholesale, the interconnection of
facilities in interstate commerce (other than interconnections for use in the
event of certain emergency situations), the licensing and operation of
hydroelectric projects and, to the extent the FERC determines, accounting
policies and practices. The Company and its wholesale customers last agreed to a
general increase in wholesale rates in 1988; however, wholesale rates have been
adjusted since that time through contractual negotiations.
ENVIRONMENTAL MATTERS
1. GENERAL. In the areas of air quality, water quality, control of toxic
substances and hazardous and solid wastes and other environmental
matters, the Company is subject to regulation by various federal, state
and local authorities. The Company considers itself to be in substantial
compliance with those environmental regulations currently applicable to
its business and operations and believes it has all necessary permits to
conduct such operations. Environmental laws and regulations constantly
evolve and the ultimate costs of compliance cannot always be accurately
estimated. The costs associated with compliance with pollution control
laws and regulations at the Company's existing facilities that the
Company expects to incur from 1999 through 2001 are included in the
estimates of capital requirements under PART I, ITEM 1, "Capital
Requirements".
2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act (Act)
require substantial reductions in sulfur dioxide and nitrogen oxides
emissions from fossil-fueled electric generating plants. The Act will
require the Company to meet more stringent provisions effective January
1, 2000. The Company plans to meet the sulfur dioxide emissions
requirements by utilizing the most economical combination of
fuel-switching and sulfur dioxide emission allowances. Installation of
additional equipment will be necessary to reduce nitrogen oxide
emissions. The Company estimates that future capital expenditures
necessary to meet the nitrogen oxide emission requirements will
approximate $27 million. Increased operation and maintenance costs,
including emission allowance expenses and increased fuel costs are not
expected to be material to the Company's results of operations.
On October 27, 1998, the Environmental Protection Agency (EPA) published
a final rule addressing the issue of regional transport of ozone. This
rule is commonly known as the NOx SIP call. The EPA's rule requires 22
states, including North and South Carolina, to further reduce nitrogen
oxide emission in order to attain a pre-set state NOx emission level by
May 2003. The EPA's rule also suggests to the states that these
additional nitrogen oxide emission reductions be obtained from the
utility sector. The Company is evaluating necessary measures to comply
with the rule and estimates its related capital expenditures through
2003 could be approximately $327 million. Increased operation and
maintenance costs relating to the NOx SIP call are not expected to be
material to the Company's results of operations. The Company and the
states of North and South Carolina are participating in litigation
challenging the NOx SIP call. The Company cannot predict the outcome of
this matter.
With regard to revisions to existing air quality standards, in July 1997
the EPA issued final regulations establishing a new fine-particulate
standard. These regulations may require the installation of additional
control equipment at some of the Company's fossil-fueled electric
generating plants. The Company is evaluating the effects of these and
other similar regulations and cannot determine the estimated costs that
may be required for compliance. The Company cannot predict the outcome
of this matter.
3. SUPERFUND. The provisions of the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (CERCLA), authorize
the EPA to require clean up of hazardous waste sites. This statute
imposes retroactive joint and several liability. Some states, including
North and South Carolina, have similar types of legislation. There are
presently several sites with respect to which the Company has been
notified by the EPA or the State of North Carolina of its potential
liability, as described below in greater detail.
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under various
federal and state laws. There are several manufactured gas plant (MGP)
sites to which the Company and certain entities that were later merged
into the Company had some connection. In this regard, the Company, along
with others, is participating in a cooperative effort with the North
Carolina Department of Environment and Natural Resources, Division of
Waste Management (DWM), which has established a uniform framework to
address MGP sites. The investigation and remediation of specific MGP
sites will be addressed pursuant to one or more Administrative Orders on
Consent (AOC) between the DWM and the potentially responsible party or
parties. The Company has signed AOCs to investigate certain sites. The
Company continues to investigate the identities of parties connected to
individual MGP sites, the relative relationships of the Company and
other parties to those sites and the degree to which the Company will
undertake efforts with others at individual sites. The Company does not
expect the costs associated with these sites to be material to the
financial position and results of operations of the Company.
The Company has been notified by regulators of its involvement or
potential involvement in several sites, other than MGP sites, that may
require investigation and/or remediation. Although the Company may incur
costs at these sites, the investigation and/or remediation of the sites
has not advanced to a stage where reasonable cost estimates can be made.
The Company cannot predict the outcome of these matters.
4. OTHER ENVIRONMENTAL MATTERS. The Company has filed claims with its
general liability insurance carriers to recover costs arising out of
actual or potential environmental liabilities. Some claims have been
settled, and others are still being pursued. The Company cannot predict
the outcome of these matters.
5. ENVIRONMENTAL ACCRUAL. The Company carries a liability for the estimated
costs associated with certain remedial activities. This liability is not
material to the financial position of the Company.
NUCLEAR MATTERS
1. GENERAL. Under the Atomic Energy Act of 1954 and the Energy
Reorganization Act of 1974, as amended, operation of nuclear plants is
intensively regulated by the Nuclear Regulatory Commission (NRC), which
has broad power to impose nuclear safety and security requirements. In
the event of noncompliance, the NRC has the authority to impose fines,
set license conditions, or shut down a nuclear unit, or some combination
of these, depending upon its assessment of the severity of the
situation, until compliance is achieved. The electric utility industry
in general has experienced challenges in a number of areas relating to
the operation of nuclear plants, including: substantially increased
capital outlays for modifications; the effects of inflation upon the
cost of operations; increased costs related to compliance with changing
regulatory requirements; renewed emphasis on achieving excellence in all
phases of operations; unscheduled outages; outage durations; and
uncertainties regarding disposal facilities for low-level radioactive
waste and storage facilities for spent nuclear fuel. See paragraphs 2
and 3 below. The Company experiences these challenges to varying
degrees. Capital expenditures for modifications
at the Company's nuclear units, excluding Power Agency's ownership
interests, during 1999, 2000 and 2001 are expected to total
approximately $54 million, $35 million, and $73 million, respectively
(including AFUDC).
2. SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE. The Nuclear Waste
Policy Act of 1982 (Nuclear Waste Act) provides the framework for
development by the federal government of interim storage and permanent
disposal facilities for high-level radioactive waste materials. The
Nuclear Waste Act promotes increased usage of interim storage of spent
nuclear fuel at existing nuclear plants. The Company will continue to
maximize the use of spent fuel storage capability within its own
facilities for as long as feasible. As of December 31, 1998, sufficient
on-site spent nuclear fuel storage capability is available for the
full-core discharge of Brunswick Unit No. 1 through 1999, Brunswick Unit
No. 2 through 2000, Robinson Unit No. 2 through 2000 and Harris through
2002 assuming normal operating and refueling schedules. The spent fuel
storage facilities at the Brunswick and Robinson Units along with the
Harris Plant spent fuel storage facilities are sufficient to provide
storage space for spent fuel generated by all of the Company's nuclear
generating units through the expiration of their current operating
licenses, provided that currently idle storage space at the Harris Plant
can be activated. On December 23, 1998, the Company submitted a license
amendment application to the NRC requesting approval to activate and
begin using the additional spent fuel storage at the Harris Plant. The
Company is maintaining full-core discharge capability for the Brunswick
Units and Robinson Unit No. 2 by transferring spent nuclear fuel by rail
to the Harris Plant. As a contingency to the shipment by rail of spent
nuclear fuel, during April 1989, the Company filed an application with
the NRC for the issuance of a license to construct and operate an
independent spent fuel storage facility for the dry storage of spent
nuclear fuel at the Brunswick Plant. At the Company's request, the NRC
suspended review of the Company's license application based on the
success of the Company's shipping efforts. The NRC will resume review of
the license upon notification by the Company of its desire to continue
the application process. Subsequent to the expiration of the licenses,
dry storage may be necessary in conjunction with the decommissioning of
the units. Pursuant to the Nuclear Waste Act, the Company, through a
joint agreement with the U. S. Department of Energy (DOE) and the
Electric Power Research Institute, has built a demonstration facility at
the Robinson Plant that allows for the dry storage of 56 spent nuclear
fuel assemblies. The Company cannot predict the outcome of these
matters.
As required under the Nuclear Waste Policy Act of 1982, the Company
entered into a contract with the DOE under which the DOE agreed to begin
taking spent nuclear fuel by January 31, 1998. The DOE defaulted on its
January 31, 1998 obligation to begin taking spent nuclear fuel, and a
group of utilities, including the Company, has undertaken measures to
force the DOE to take spent nuclear fuel. To date, the courts have
rejected these attempts. In addition, several utilities have filed
actions for damages in the United States Court of Claims, and in some of
those cases the Court has agreed that the DOE has breached its contract
for disposal of spent nuclear fuel. The Company is in the process of
evaluating whether it should file a similar action for damages. The
Company will also monitor legislation that has been introduced in
Congress that would provide for interim storage of spent nuclear fuel at
a storage facility operated by the DOE. The Company cannot predict the
outcome of this matter.
3. LOW-LEVEL RADIOACTIVE WASTE. Disposal costs for low-level radioactive
waste that result from normal operation of nuclear units have increased
significantly in recent years and are expected to continue to rise.
Pursuant to the Low-Level Radioactive Waste Policy Act of 1980, as
amended in 1985, each state is responsible for disposal of low-level
waste generated in that state. States that do not have existing sites
may join in regional compacts. The States of North and South Carolina
were participants in the Southeast Regional Compact and disposed of
waste at a disposal site in South Carolina along with other members of
the compact. Effective July 1, 1995, South Carolina withdrew from the
Southeast regional compact and
excluded North Carolina waste generators from the existing disposal site
in South Carolina. As a result, the State of North Carolina does not
have access to a low-level radioactive waste disposal facility. The
North Carolina Low-Level Radioactive Waste Management Authority, which
is responsible for siting and operating a new low-level radioactive
waste disposal facility for the Southeast regional compact, has
submitted a license application for the site it selected in Wake County,
North Carolina to the North Carolina Division of Radiation Protection.
In December 1997, the Southeast Regional Compact Commission suspended
funding for the proposed low-level radioactive waste facility in Wake
County. The future funding for this project remains uncertain. Although
the Company does not control the future availability of low-level waste
disposal facilities, the cost of waste disposal or the development
process, it supports the development of new facilities and is committed
to a timely and cost-effective solution to low-level waste disposal. The
Company's nuclear plants in North Carolina are currently storing
low-level waste on site and are developing additional storage capacity
to accommodate future needs. The Company's nuclear plant in South
Carolina has access to the existing disposal site in South Carolina.
Although the Company cannot predict the outcome of this matter, it does
not expect the cost of providing additional on-site storage capacity for
low-level radioactive waste to be material to the results of operations
or financial position of the Company.
4. DECOMMISSIONING.
a) Pursuant to an NRC rule, licensees of nuclear facilities are
required to submit decommissioning funding plans to the NRC for
approval to provide reasonable assurance that the licensee will
have the financial ability to implement its decommissioning plan
for each facility. The rule requires licensees to do one of the
following: prepay at least an NRC-prescribed minimum amount
immediately; set up an external sinking fund for accumulation of
at least that minimum amount over the operating life of the
facility; or provide a surety to guarantee financial performance
in the event of the licensee's financial inability to perform
actual decommissioning. On July 26, 1990, the Company submitted
its decommissioning funding plans to the NRC. In this regard, the
Company entered into a Master Decommissioning Trust Agreement
dated July 19, 1990 (Trust), with Wachovia Bank of North Carolina,
N.A., as Trustee, as a vehicle to achieve such decommissioning
funding. In June 1991, the Company began depositing funds into the
Trust.
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC and the SCPSC and
are based on site-specific estimates that included the costs for
removal of all radioactive and other structures at the site. In
the wholesale jurisdiction, the provisions for nuclear
decommissioning costs are based on amounts agreed upon in
applicable rate agreements. Decommissioning cost provisions, which
are included in depreciation and amortization expense, were $33.3
million, $33.2 million and $33.1 million in 1998, 1997 and 1996,
respectively. Accumulated decommissioning costs, which are
included in accumulated depreciation, were $496.3 million and
$428.7 million at December 31, 1998 and 1997, respectively. These
costs include amounts retained internally and amounts funded in an
external decommissioning trust. The balance of the nuclear
decommissioning trust was $310.7 million and $245.5 million at
December 31, 1998 and 1997, respectively. Trust earnings increase
the trust balance with a corresponding increase in the accumulated
decommissioning balance. These balances are adjusted for net
unrealized gains and losses related to changes in the fair value
of trust assets. Based on the site-specific estimates discussed
below, and using an assumed after-tax earnings rate of 7.75% and
an assumed cost escalation rate of 4%, current levels of rate
recovery for nuclear decommissioning costs are adequate to provide
for decommissioning of the Company's nuclear facilities.
b) The Company's most recent site-specific estimates of decommissioning
costs were developed in 1998, using 1998 cost factors, and are based on
prompt dismantlement decommissioning, which reflects the cost of removal
of all radioactive and other structures currently at the site, with such
removal occurring shortly after operating license expiration. See
paragraph 5 below for expiration dates of operating licenses. These
estimates, in 1998 dollars, are $279.8 million for Robinson Unit No. 2,
$299.3 million for Brunswick Unit No. 1, $298.5 million for Brunswick
Unit No. 2, and $328.1 million for the Harris Plant. The estimates are
subject to change based on a variety of factors including, but not
limited to, cost escalation, changes in technology applicable to nuclear
decommissioning and changes in federal, state or local regulations. The
cost estimates exclude the portion attributable to Power Agency, which
holds an undivided ownership interest in the Brunswick and Harris
nuclear generating facilities. To the extent of its ownership interests,
Power Agency is responsible for satisfying the NRC's financial assurance
requirements for decommissioning costs. See PART I, ITEM 1, "Generating
Capabilities", paragraph 1.
c) The Financial Accounting Standards Board is proceeding with its project
regarding accounting practices related to obligations associated with
the retirement of long-lived assets, and an exposure draft of a proposed
accounting standard is expected to be issued during the first half of
1999. It is uncertain when a final statement will be issued and what
effects it may ultimately have on the Company's accounting for nuclear
decommissioning and other retirement costs.
5. OPERATING LICENSES. Facility Operating Licenses, issued by the NRC, for
the Company's nuclear units allow for a full 40 years of operation.
Expiration dates for these licenses are set forth in the following
table.
Facility Operating License
Facility Expiration Date
-------- ---------------
Robinson Unit No. 2 July 31, 2010
Brunswick Unit No. 1 September 8, 2016
Brunswick Unit No. 2 December 27, 2014
Harris Plant October 24, 2026
6. OTHER NUCLEAR MATTERS
a) In 1991, the NRC issued a final rule on nuclear plant maintenance
that became effective on July 10, 1996. In general terms, the new
maintenance rule prescribes the establishment of performance
criteria for each safety system based on the significance of that
system. The rule also requires monitoring of safety system
performance against the established acceptance criteria, and
provides that remedial action be taken when performance falls
below the established criteria. In March 1998, the Company's
Maintenance Rule Program was found acceptable by the NRC during
baseline inspections.
b) On November 23, 1988, the NRC requested in Generic Letter 88-20
that utilities perform Individual Plant Examinations (IPEs) to
determine potential vulnerabilities to severe accidents beyond the
design basis accidents for which the plants are designed. These
are considered to be very low probability events. The Company
submitted the results of the first phase (for internally initiated
events) in August 1992 for the Brunswick and Robinson Plants.
Based on those results, potential enhancements for the Robinson
Plant were evaluated and several enhancements were
made to the Robinson Plant. These changes had insignificant
financial and operational impacts. For the Brunswick Plant, no
modifications were required to meet the guidelines of the IPE. On
August 20, 1993, the Company submitted the results of the Harris
Plant IPE. While some Harris Plant procedural changes were made
due to the IPE results, the IPE did not result in any significant
financial or operational impacts or identify any need for plant
modifications. In June 1995, the Company completed and submitted
the results of the second phase of the IPEs (for externally
initiated events) for the Company's three nuclear plants. The
results of the IPEs indicated some potential procedural changes
for the Harris and Brunswick Plants. Those results also indicated
that both minor procedural changes and minor plant modifications
would be required for the Robinson Plant. All IPE items and
findings had been addressed and implemented by the end of 1998.
c) Degradation of tubing internal to steam generators in pressurized
water reactor power plants due to intergranular stress corrosion
cracking has been an on-going industry phenomenon. The Company has
determined that the steam generators at the Harris Plant are
subject to degradation and plans to replace the steam generators
in 2001. The steam generators at the Robinson plant were replaced
in 1984 and are expected to perform until the plant's operating
license expires. The Company does not expect the costs associated
with replacing the steam generators at the Harris Plant to be
material to the financial position of the Company.
d) The Company is insured against public liability for a nuclear
incident up to $9.8 billion per occurrence, which is the maximum
limit on public liability claims pursuant to the Price-Anderson
Act. In the event that public liability claims from an insured
nuclear incident exceed $200 million, the Company would be subject
to a pro rata assessment of up to $83.9 million, plus a 5%
surcharge, for each reactor owned for each incident. Payment of
such assessment would be made over time as necessary to limit the
payment in any one year to no more than $10 million per reactor
owned. Power Agency would be responsible for its ownership share
of the assessment on jointly owned nuclear units. For a more
detailed discussion of nuclear liability insurance, see PART II,
ITEM 8, "CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA", Note 12 b.
FUEL
1. SOURCES OF GENERATION. Total system generation (including Power Agency's
share) by primary energy source, along with purchased power, for the
years 1995 through 1999 is set forth below:
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
(estimated)
Fossil 44% 45% 46% 47% 49%
Nuclear 42 41 43 42 41
Purchased Power 13 12 10 9 9
Hydro 1 2 1 1 1
Combustion Turbine - - - 1 -
2. COAL. The Company has intermediate and long-term agreements from which
it expects to receive approximately 90% of its coal burn requirements in
1999. These agreements have expiration dates ranging from 1999 to 2006.
All of the coal that the Company is currently purchasing under
intermediate and long-term agreements is considered to be low sulfur
coal by industry standards. Recent amendments to the Clean Air Act may
result in increases in the price of low sulfur coal. See PART I, ITEM 1,
"Environmental Matters", paragraph 2. The average cost (including
transportation costs) to the Company of coal delivered for 1998 was
$41.10 per ton.
3. OIL. The Company uses No. 2 oil primarily for its combustion turbine
units, which are used for emergency backup and peaking purposes, and for
boiler start-up and flame stabilization. The Company has a No. 2 oil
supply contract for its normal requirements. In the event base-load
capacity is unavailable during periods of high demand, the Company may
increase the use of its combustion turbine units, thereby increasing No.
2 oil consumption. The Company intends to meet any additional
requirements for No. 2 oil through additional contract purchases or
purchases in the spot market. There can be no assurance that adequate
supplies of No. 2 oil will be available to meet the Company's
requirements. To reduce the Company's vulnerability to the lack of No. 2
oil availability, fourteen combustion turbine units with a total
generating capacity of 665 MW can also burn natural gas. Over the last
five years, No. 2 oil, natural gas and propane accounted for 2.40% of
the Company's total burned fuel cost. In 1998, No. 2 oil, natural gas
and propane accounted for 4.03% of the Company's total burned fuel cost.
The availability and cost of fuel oil could be adversely affected by
energy legislation enacted by Congress, disruption of oil or gas
supplies, labor unrest and the production, pricing and embargo policies
of foreign countries.
4. NUCLEAR. The nuclear fuel cycle requires the mining and milling of
uranium ore to provide uranium oxide concentrate (U3O8), the conversion
of U3O8 to uranium hexafluoride (UF6), the enrichment of the UF6 and the
fabrication of the enriched uranium into fuel assemblies. Existing
uranium contracts are expected to supply the necessary nuclear fuel to
operate all of the Company's nuclear generating facilities through 2001.
The Company expects to meet its future U3O8 requirements from inventory
on hand and amounts received under contract. Although the Company cannot
predict the future availability of uranium and nuclear fuel services,
the Company does not currently expect to have difficulty obtaining U3O8
and the services necessary for its conversion, enrichment and
fabrication into nuclear fuel. For a discussion of the Company's plans
with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear
Matters", paragraph 2.
5. DOE ENRICHMENT FACILITIES DECONTAMINATION AND DECOMMISSIONING (D&D)
FUND. Under Title XI of the Energy Policy Act of 1992, Public Law
102-486, Congress established a decontamination and decommissioning
(D&D) fund for the DOE's gaseous diffusion enrichment plants.
Contributions to this fund are being made by U.S. domestic utilities
which have purchased enrichment services from DOE since it began sales
to non-Department of Defense customers. Each utility's share of the
contributions is based on that utility's past purchases of services as a
percentage of all purchases of services by U.S. utilities. Total annual
contributions are capped at $150 million per year with an overall cap of
$2.25 billion over 15 years both indexed to inflation. The Company has
paid approximately $34 million in D&D fees through 1998, and expects to
pay a cumulative total of approximately $83 million over the 15 year
period ending September 30, 2007 (excluding Power Agency's ownership
share). The Company is recovering these costs as a component of fuel
cost.
During March 1997, the Company, along with other entities, filed an
administrative claim with the DOE, and a Complaint against the DOE in
the United States Court of Federal Claims, seeking a refund of part of
the price paid by the Company for enrichment services purchased from the
DOE. It is the Company's position that the contract price it paid to the
DOE for uranium purchases included the cost of D&D, and that the DOE's
collection of additional D&D fees pursuant to the Energy Act resulted in
an overpayment of fees by the Company. In addition, the claim requested
the elimination of future D&D fund assessments. It was the Company's
position that the D&D assessments constitute a breach of contract, a
taking of vested contract rights, a violation of property rights,
illegal exaction and a violation of the Fifth Amendment of
the United States Constitution. The Company's action was stayed pending
the outcome of a similar case, Yankee Atomic Electric Company (Yankee
Atomic) v, United States (33 Fed.Cl. 580 (Cl.Ct. 1995)), in which the
United States Court of Claims found that a portion of the D&D
assessments made against Yankee Atomic were unlawful. The government
appealed that case to the District of Columbia Circuit Court of Appeals,
which subsequently overturned the favorable Court of Claims decision.
After the Circuit Court of Appeals refused to rehear the matter, Yankee
Atomic filed a petition for a certiorari to seek a review by the United
States Supreme Court, which was denied. During February 1999, the
Company amended its complaint for various reasons, and the government
subsequently filed a motion to dismiss. The total refund demanded in the
Company's amended complaint through the date of the complaint filing
(including Power Agency's ownership share) is approximately $39 million.
The Company cannot predict the outcome of this matter.
6. PURCHASED POWER. The Company purchased 5,336,867 MWh in 1998, 5,886,722
MWh in 1997 and 6,792,340 MWh in 1996 or approximately 9%, 10% and 12%,
respectively, of its system energy requirements (including Power Agency)
and had available 1,438 MW in 1998, 1,839 MW in 1997 and 1,536 MW in
1996 of firm purchased capacity under contract at the time of peak load.
The Company may acquire purchased power capacity in the future to
accommodate a portion of its system load needs.
NCNG MERGER
On November 10, 1998, the Company and North Carolina Natural Gas
Corporation entered into an Agreement and Plan of Merger (Merger
Agreement) providing for the strategic business combination of the
Company and NCNG. Pursuant to the Merger Agreement, NCNG will become a
wholly owned subsidiary of the Company. The Merger is intended to
constitute a tax-free reorganization for federal income tax purposes and
to be accounted for as a pooling-of-interests. The Company will issue
approximately $354 million in stock to NCNG shareholders to complete the
merger.
The Merger Agreement has been approved by the Boards of Directors of the
Company and NCNG. Consummation of the Merger is subject to certain
closing conditions, including approval by the shareholders of NCNG and
certain regulatory approvals or filings. Applications for regulatory
approval were filed with the NCUC on January 11, 1999, and with the
SCPSC on February 9, 1999. NCNG presently intends that the shareholders
meeting to consider such approval will be held as early as practicable.
The requisite notifications were filed with the Federal Trade Commission
and the Department of Justice under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976, as amended, during March 1999.
Further details concerning the proposed transaction are provided in the
Company's Form 10-Q for the quarter ended September 30, 1998, which was
filed with the SEC on November 13, 1998.
DIVERSIFIED BUSINESSES
1. STRATEGIC RESOURCE SOLUTIONS CORP. Strategic Resource Solutions Corp.
(SRS), a wholly owned subsidiary, specializes in facilities and energy
management software, systems and services for educational, commercial,
industrial and governmental markets nationwide. During 1998, SRS
acquired the following companies: Parke Industries Inc., a lighting
retrofit company located in California; Intelligent Solutions Inc., a
Nevada company that designs and manufactures advanced cogeneration
energy systems for highly efficient on-location power generation; and
two North Carolina companies, Jack Walters Inc. and Jack Walters
Services, Inc. (collectively JWI). JWI designs, engineers, installs and
maintains building automation systems that control heating, ventilation,
air conditioning and lighting.
2. INTERPATH COMMUNICATIONS, INC. Interpath Communications, Inc.
(Interpath), a majority-owned subsidiary, is a telecommunications
company primarily engaged in providing Internet-based services.
Interpath's services include consulting, design, implementation and
support related to Internet access, Intranet development, electronic
commerce, hosting and videoconferencing. During 1998, Interpath merged
with TriNet Services, a leader in Internet professional services. The
merger of the two companies has facilitated Interpath's ability to
expand its market share of Internet services by combining Interpath's
high-speed fiber optic network and support services with TriNet's
Internet consulting and development capabilities.
Interpath also owns a 10% limited partnership interest in BellSouth
Carolinas PCS, L.P. BellSouth Personal Communications, Inc. manages the
partnership as the general partner. PCS is a wireless communications
technology that provides high-quality mobile communications. The
partnership serves PCS subscribers in North and South Carolina, and a
small portion of Georgia, pursuant to a license issued by the Federal
Communications Commission.
OTHER MATTERS
1. SAFETY INSPECTION REPORTS. In April 1990, the FERC sent a letter to the
Company providing comments on its review of the Company's Fifth (1987)
Independent Consultant's Safety Inspection Report, which is required
every five years under the FERC Regulation 18 CFR Part 12, for the
Walters Hydroelectric Project and requested the Company to undertake
certain supplemental analyses and investigations regarding the stability
of the dam under extreme and improbable loading conditions. In November
1994, the Company submitted the independent consultant's report to the
FERC regarding the stability of the dam at the Walters Project. The
independent consultant concluded that the Walters dam has adequate
structural stability and reserve capacity to resist both usual and
unusual loading conditions without failure and that structural
remediation is neither warranted nor recommended. In February 1997, the
Company received a letter from the FERC pertaining to the Company's
inspection report filed in November 1994. The FERC submitted comments on
the inspection report and requested that further analysis be conducted.
The Company filed a response in April 1997. In its response, the Company
agreed with some of the FERC's comments and took exception to others. In
November 1998, the Company received a letter from the FERC pertaining to
the Company's April 1997 letter. The Company filed a response in
December 1998, which provided information on a plan to further
investigate the dam abutments and which addresses FERC's revised dynamic
evaluation criteria. Depending on the outcome of these matters, the
Company could be required to undertake efforts to enhance the stability
of the dams. The cost and need for such efforts have not been
determined. The Company cannot predict the outcome of this matter.
Similar letters were sent by the FERC during May 1990 with respect to
the Company's Blewett and Tillery Hydroelectric Plants. The matters
raised in the May 1990 letters from the FERC are still under
investigation. Depending on the outcome of these matters, the Company
could be required to undertake efforts to enhance the stability of the
dams. The cost and need for such efforts have not been determined. The
Company filed the Seventh (1998) Part 12 Report for the Tillery
Hydroelectric Plant in November 1998 in accordance with a request from
the FERC. The Tillery report does not indicate any deficiencies that
would endanger the integrity of the dam. The consultant's Seventh Part
12 Report regarding the Blewett Hydroelectric Plant has been developed
but, as requested by the FERC, has not been filed. The FERC is
developing comments on earlier filings from the Company and has
indicated that additional investigations and analyses may be required.
The Company has agreed to await the comments from the FERC and
incorporate the consultant's responses into the Seventh Part 12 Report.
A review of the draft of the Seventh Part 12 Report for Blewett reveals
that the consultant did not identify any critical dam safety
deficiencies. The Company cannot predict the outcome of this matter.
2. MARSHALL HYDROELECTRIC PROJECT. In November 1991, the FERC notified the
Company that the 5 MW Marshall Hydroelectric Project is no longer exempt
from 18 CFR Part 12, Subpart C and D, dam safety
regulations and that the plant's regulatory jurisdiction was being
transferred from the NCUC to the FERC. This change resulted from updated
dambreak flood studies which identified the potential impact on new
downstream development, thus indicating the need to reclassify the
project from a low hazard to a high hazard classification. In accordance
with the change in regulatory jurisdiction, the Company developed an
emergency action plan which meets the FERC guidelines and engaged its
independent consultant to perform a safety inspection. In April 1992 the
inspection report was submitted to the FERC for approval. In March 1995
the Company received comments on the inspection report from the FERC. As
a result of these comments, and a meeting with the FERC officials, the
Company was requested to perform further analyses and submit its
findings to the FERC. The Company subsequently submitted the first phase
of the requested analyses to the FERC in September 1995. Depending on
the outcome of the FERC's review, the Company could be required to
undertake efforts to enhance the stability of the Marshall dam and/or
powerhouse. The cost and need for such efforts have not been determined.
The Company cannot predict the outcome of this matter.
3. TAX REFUND DISPUTE. In April 1994, the Company filed a Complaint against
the U.S. Government in the United States District Court for the Eastern
District of North Carolina in Raleigh, North Carolina (Civil Action No.
5:94-CV-313-BR3) seeking a refund of approximately $188 million
representing tax and interest related to depreciation deductions the
Internal Revenue Service (IRS) previously disallowed for the years 1986
and 1987 on the Company's Harris Plant. The Company maintains that under
applicable laws and regulations the Harris Plant was ready and available
for operation in 1986. The IRS has previously denied some of the
depreciation deductions on the Company's tax returns for the years in
question on the ground that in its view the plant was not placed in
service until 1987. During December 1995, the jury returned a verdict in
favor of the U.S. Government. The Company has filed an appeal of the
jury's verdict. The Company cannot predict the outcome of this matter.
4. YEAR 2000. See Part II, Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" for discussion of the
Company's Year 2000 readiness issues.
OPERATING STATISTICS
Years Ended December 31
1998 1997 1996 1995 1994
---------- --------- --------- --------- ---------
Energy supply (millions of kWh)
Generated - coal 27,576 25,545 24,859 23,517 21,001
nuclear 22,014 21,690 20,284 19,949 18,511
hydro 790 799 882 824 884
combustion turbines 386 189 68 56 67
Purchased 5,675 6,318 7,292 7,433 7,039
---------- --------- --------- --------- ---------
Total energy supply (Company share) 56,441 54,541 53,385 51,779 47,502
Power Agency share (a) 4,349 4,101 3,616 3,828 3,236
---------- --------- --------- --------- ---------
Total system energy supply 60,790 58,642 57,001 55,607 50,738
========== ========= ========= ========= =========
Average fuel cost (per million BTU)
Fossil $ 1.71 $ 1.75 $ 1.75 $ 1.83 $ 1.78
Nuclear fuel $ 0.46 $ 0.46 $ 0.45 $ 0.46 $ 0.47
All fuels $ 1.14 $ 1.14 $ 1.14 $ 1.17 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 13,117 12,488 12,611 12,074 11,147
Commercial 10,664 10,010 9,615 9,276 8,690
Industrial 14,911 15,073 14,456 14,312 14,030
Other Retail 1,357 1,294 1,263 1,288 1,263
Wholesale 14,427 13,900 13,383 12,940 10,442
---------- --------- --------- --------- ---------
Total energy sales 54,476 52,765 51,328 49,890 45,572
Company uses and losses 1,964 1,776 2,057 1,889 1,930
---------- --------- --------- --------- ---------
Total energy requirements 56,440 54,541 53,385 51,779 47,502
========== ========= ========= ========= =========
Customers billed
Residential 996,398 972,385 945,703 920,495 894,616
Commercial 178,588 172,821 167,151 159,064 155,349
Industrial 5,056 5,072 5,066 4,863 4,845
Government and municipal 2,757 2,785 2,774 2,328 2,302
Resale 35 43 27 17 12
---------- --------- --------- --------- ---------
Total customers billed 1,182,834 1,153,106 1,120,721 1,086,767 1,057,124
========== ========= ========= ========= ==========
Operating revenues (in thousands)
Retail $ 2,532,234 $ 2,450,509 $ 2,417,011 $ 2,399,354 $2,331,538
Wholesale 539,984 518,438 523,988 560,676 500,559
Miscellaneous revenue 57,827 55,142 54,716 46,523 44,492
---------- --------- --------- --------- ---------
Total operating revenues $ 3,130,045 $ 3,024,089 $ 2,995,715 $ 3,006,553 $2,876,589
========== ========= ========= ========= =========
Peak demand of firm load (thousands of kW)
System 10,529 10,030 9,812 10,156 10,144
Company 9,875 9,344 9,264 9,500 9,642
Total capability at year-end (thousands of kW) (a)
Fossil plants 6,571 6,571 6,331 6,331 6,331
Nuclear plants 3,174 3,064 3,064 3,064 3,064
Hydro plants 218 218 218 218 218
Purchased 1,538 1,588 1,603 1,592 1,596
---------- --------- --------- --------- ---------
Total system capability 11,501 11,441 11,216 11,205 11,209
Less Power Agency-owned portion (b) 593 690 686 682 654
---------- --------- --------- --------- ---------
Total Company capability 10,908 10,751 10,530 10,523 10,555
========== ========= ========= ========= =========
(a) Represents maximum dependable capacity of installed generating units plus
other resources, including firm purchases. For 1998, total system capability
during the summer was higher by 200 MW for term purchase contracts in place
at time of summer peak.
(b) Net of the Company's purchases from Power Agency.
ITEM 2. PROPERTIES
In addition to the major generating facilities listed in PART I, ITEM 1,
"Generating Capability", the Company also operates the following plants:
Plant Location
----- --------
1. Walters North Carolina
2. Marshall North Carolina
3. Tillery North Carolina
4. Blewett North Carolina
5. Weatherspoon North Carolina
6. Morehead North Carolina
The Company's sixteen power plants represent a flexible mix of fossil, nuclear
and hydroelectric resources, with a total generating capacity (including Power
Agency's share) of 9,963 MW. The Company's strategic geographic location
facilitates purchases and sales of power with many other electric utilities,
allowing the Company to serve its customers more economically and reliably.
Major industries in the Company's service area include textiles, chemicals,
metals, paper, food, rubber and plastics, wood products, and electronic
machinery and equipment.
At December 31, 1998, the Company had 5,628 pole miles of transmission lines
including 292 miles of 500 kV lines and 2,848 miles of 230 kV lines, and
distribution lines of approximately 44,033 pole miles of overhead lines and
approximately 12,759 miles of underground lines. Distribution and transmission
substations in service had a transformer capacity of approximately 34,545 kVA in
2,035 transformers. Distribution line transformers numbered 420,633 with an
aggregate 17,788,000 kVA capacity.
Power Agency has acquired undivided ownership interests of 18.33% in Brunswick
Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4 and 16.17% in Harris Unit No. 1
and Mayo Unit No. 1. Otherwise, the Company has good and marketable title to its
principal plants and important units, subject to the lien of its Mortgage and
Deed of Trust, with minor exceptions, restrictions, and reservations in
conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. The Company also owns certain
easements over private property on which transmission and distribution lines are
located.
The Company believes that its generating facilities are suitable, adequate,
well-maintained and in good operating condition.
Plant Accounts (including nuclear fuel) - During the period January 1, 1994
through December 31, 1998, there were $2,207,444,392 additions to the Company's
utility plant accounts, $717,984,814 retirements and $(33,837,610) transfers and
adjustments resulting in net additions of $1,455,621,968. These net additions
represent an increase of approximately 15.24%.
ITEM 3 LEGAL PROCEEDINGS
Legal and regulatory proceedings are included in the discussion of the Company's
business in PART I, ITEM 1 and incorporated by reference herein.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders in the fourth quarter of
1998.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age Recent Business Experience
William Cavanaugh III 60 PRESIDENT AND CHIEF EXECUTIVE OFFICER,
October 1996 to present; President and Chief
Operating Officer, September 1992 to October
1996. Before joining the Company, Mr.
Cavanaugh held various senior management and
executive positions during a 23-year career
with Entergy Corporation, an electric utility
holding company with operations in Arkansas,
Louisiana and Mississippi. Member of the
Board of Directors of the Company since 1993.
Glenn E. Harder 48 EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL
OFFICER, Financial Services, August 1995 to
present; Senior Vice President, Group
Executive - Financial Services, October 1994
to August 1995. Before joining the Company,
Mr. Harder held various senior management and
executive positions with Entergy Corporation,
an electric utility holding company with
operations in Arkansas, Louisiana and
Mississippi, and related entities.
William S. Orser 54 EXECUTIVE VICE PRESIDENT, Energy Supply, June
1998 to present; Executive Vice President and
Chief Nuclear Officer, December 1996 to June
1998; Executive Vice President - Nuclear
Generation, April 1993 to December 1996.
Prior to April 1993, Mr. Orser held various
senior management and executive positions
with Detroit Edison Company, and positions
with Portland General Electric Company,
Southern California Edison, and the U. S.
Navy.
Tom D. Kilgore 51 SENIOR VICE PRESIDENT, Power Operations,
August 1998 to present; President and Chief
Executive Officer, Oglethorpe Power
Corporation, Georgia Transmission Corporation
and Georgia Operations Corporation, July 1991
to August 1998. These three companies provide
power generation, transmission and system
operations services, respectively, to 39 of
Georgia's 42 customer-owned Electric
Membership Corporations. From 1984 to July
1991, Mr. Kilgore held numerous management
positions at Oglethorpe.
C.S. Hinnant 54 SENIOR VICE PRESIDENT AND CHIEF NUCLEAR
OFFICER, Nuclear Generation, June 1998 to
present; Vice President, Brunswick Nuclear
Plant, April 1997 to May 1998; Vice Present ,
Robinson Nuclear Plant, March 1994 to March
1997.
Fred N. Day, IV 55 SENIOR VICE PRESIDENT, Energy Delivery, July
1997 to present; Vice President, Western