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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from________ to_________
Commission file number 1-3382
CAROLINA POWER & LIGHT COMPANY
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(Exact name of registrant as specified in its charter)
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411 Fayetteville Street
North Carolina 56-0165465 Raleigh, North Carolina 27601
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(State or other jurisdiction of (I.R.S. Employer (Address of principal executive offices) (Zip Code)
incorporation or organization) Identification No.)
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919-546-6111
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(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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Title of each class Name of each exchange on which registered
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Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
Quarterly Income Capital Securities New York Stock Exchange
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SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
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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 .
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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 29, 2000 was $4,748,799,423.
Shares of Common Stock (Without Par Value) outstanding at February 29, 2000:
159,623,510.
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
Portions of the Company's 2000 definitive proxy statement dated March 31, 2000
are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof.
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TABLE OF CONTENTS
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Page
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SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS 3
PART I
ITEM 1. BUSINESS 4
General 4
Company 4
Significant Transactions 4
Financial Information 5
Business Activities 5
Generating Capability 5
Interconnections with Other Systems 8
Competition 9
Capital Requirements 13
Financing Requirements 13
Retail Rate Matters 15
Wholesale Rate Matters 18
Environmental Matters 18
Nuclear Matters 20
Fuel 24
Natural Gas Supply 26
Diversified Businesses 27
Other Matters 27
Employees 29
Operating Statistics - Electric 30
Operating Statistics - Natural Gas 31
ITEM 2. PROPERTIES 32
ITEM 3. LEGAL PROCEEDINGS 34
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 34
EXECUTIVE OFFICERS OF THE REGISTRANT 35
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS 37
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA 38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 51
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 52
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 81
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 81
ITEM 11. EXECUTIVE COMPENSATION 81
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 81
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 81
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 81
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SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
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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 the Amended and Restated Agreement and Plan
of Exchange with Florida Progress Corporation; 2) "Business Activities"
regarding changes at the Company; 3) "Generating Capability" regarding the
forecasted system sales growth, planned generation additions schedule, and
forecasted capacity margins over anticipated system peak loads; 4)
"Interconnections with Other Systems" relating to future energy cost savings
resulting from amendments to agreements with Cogentrix, future purchases from
the Broad River Energy project and relating to estimated minimum annual payments
for long-term purchase contracts; 5) "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
2000; 6) "Capital Requirements" relating to estimated capital requirements for
2000-2002; 7) "Financing Requirements" relating to expected external funding
requirements; 8) "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; 9)
"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; and 10) "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.
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 2002 and 2) "Other Matters" about the effects of
new environmental regulations, nuclear decommissioning costs, and the effect of
electric utility industry restructuring.
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 Public Service Commission of
South Carolina); 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
subsidiaries; weather conditions and catastrophic weather-related damage; market
demand for energy; inflation; capital market conditions; the proposed share
exchange with Florida Progress Corporation; failure of the potential benefits of
the Company's conversion to a holding company structure to materialize,
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.
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PART I
ITEM 1. BUSINESS
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GENERAL
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COMPANY
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Carolina Power & Light Company (the Company), whose principal executive offices
are located at 411 Fayetteville Street, Raleigh, North Carolina is a full
service energy provider formed under the laws of North Carolina in 1926 and is
an exempt holding company as defined by the Public Utility Holding Company Act
of 1935. The Company is primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North and South Carolina,
and the transmission, distribution and sale of natural gas in portions of North
Carolina. The Company provides these and other services through its business
segments: electric, natural gas and other.
The electric segment generates, transmits, distributes and sells electricity to
56 of the 100 counties in North Carolina, and 14 counties in northeastern South
Carolina. The territory served is an area of 33,667 square miles, including 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 an around the city of Asheville. The
estimated total population of the territory served is approximately 4.2 million.
At December 31, 1999, the electric segment was providing electric services,
retail and wholesale, to 1.2 million customers. The electric segment is subject
to the rules and regulations of the Federal Energy Regulatory Commission (FERC),
the North Carolina Utilities Commission (NCUC) and the Public Service Commission
of South Carolina (SCPSC).
The natural gas segment transmits, distributes and sells gas to approximately
167,000 thousand customers in 110 towns and cities and four municipal gas
distribution systems. The area served includes substantial portions of
south-central and eastern North Carolina. The natural gas segment also purchases
and transports natural gas under long-term contracts with Transcontinental Gas
Pipe Line Corporation (Transco), Columbia Gas Transmission Corporation
(Columbia) and several major oil and gas producers. Natural gas operations are
subject to the rules and regulations of the NCUC.
The other segment primarily includes telecommunication services, energy
management services, propane and miscellaneous non-regulated activities. These
services are primarily provided through two of the Company's subsidiaries,
Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc.
(Interpath). SRS specializes in facilities and energy management software,
systems and services for educational, commercial, industrial and governmental
markets nationwide. Interpath is a telecommunications company primarily engaged
in providing comprehensive network services.
The Company holds franchises to the extent necessary to operate its regulated
electric and natural gas operations in the municipalities and other areas it
serves.
SIGNIFICANT TRANSACTIONS
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On July 15, 1999, the Company completed the acquisition of North Carolina
Natural Gas Corporation (NCNG), now operating as a wholly owned subsidiary. Each
outstanding share of NCNG common stock was converted into the right to receive
0.8054 shares of Company common stock, resulting in the issuance of
approximately 8.3 million shares. The acquisition was accounted for as a
purchase and, accordingly, the operating results of NCNG have been included in
the Company's consolidated financial statements since the date of acquisition.
See PART II, ITEM 7, "Other Matters."
The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L
Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned
subsidiary of the Company formerly known as CP&L Holdings, Inc.
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entered into an Amended and Restated Agreement and Plan of Share Exchange dated
as of August 22, 1999, amended and restated as of March 3, 2000 (the "Amended
Agreement"). The transaction is expected to be completed in the fall of 2000.
See PART II, ITEM 7, "Other Matters."
The Company is in the process of converting to a holding company structure, in
which the Company would become a subsidiary of a newly formed holding company.
The holding company structure will allow for greater organizational flexibility,
and will provide the ability to conduct financing activities at the holding
company level. See PART II, ITEM 7, "Other Matters."
FINANCIAL INFORMATION
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During 1999, the Company's operating revenues totaled $3.4 billion of which $3.1
billion was related to the electric segment, $98.9 million to the natural gas
segment and $119.9 million to the other segment. During 1999, 34% of electric
revenues were derived from residential sales, 22% from commercial sales, 22%
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 0.5% from South Carolina wholesale
customers and 7% from sales to other utilities and other customers. For the
revenues related to the natural gas segment, 50% of the revenues were derived
from industrial sales while the remaining sales were evenly distributed among
residential, commercial, electric utilities and wholesale customers, all in
North Carolina. The operating revenues for the other segment primarily include
revenues of two of the Company's subsidiaries, SRS and Interpath.
For additional information see PART II, ITEM 7, "Results of Operations" and PART
II, ITEM 8, "Note 5."
BUSINESS ACTIVITIES
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GENERATING CAPABILITY
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1. FACILITIES. At December 31, 1999, the Company had a total system
installed generating capability (including the North Carolina Eastern
Municipal Power Agency's (Power Agency) share) of 10,128 megawatts
(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 10,128 MW, 53% is coal, 31% is nuclear, 2% is
hydro and 14% is fired by other fuels including No. 2 oil, natural gas
and propane.
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MAJOR INSTALLED GENERATING FACILITIES
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AT DECEMBER 31, 1999
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Year Maximum
Commercial Dependable
Plant Location Unit No. Operation Primary Fuel Capacity
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Asheville 1 1964 Coal 198 MW
(Skyland, N.C.) 2 1971 Coal 194 MW
3 1999 Gas/Oil 165 MW
4 2000 Gas/Oil 165 MW
Cape Fear 5 1956 Coal 143 MW
(Moncure, N.C.) 6 1958 Coal 173 MW
Darlington County Plant 12 1997 Gas/Oil 120 MW
(Hartsville, S.C.) 13 1997 Gas/Oil 120 MW
H.F. Lee 1 1952 Coal 79 MW
(Goldsboro, N.C.) 2 1951 Coal 76 MW
3 1962 Coal 252 MW
H.B. Robinson 1 1960 Coal 174 MW
(Hartsville, S.C.) 2 1971 Nuclear 683 MW
Roxboro 1 1966 Coal 385 MW
(Roxboro, N.C.) 2 1968 Coal 670 MW
3 1973 Coal 707 MW
4 1980 Coal 700 MW*
L.V. Sutton 1 1954 Coal 97 MW
(Wilmington, N.C.) 2 1955 Coal 106 MW
3 1972 Coal 410 MW
Brunswick 1 1977 Nuclear 820 MW*
(Southport, N.C.) 2 1975 Nuclear 811 MW*
Mayo 1 1983 Coal 745 MW*
(Roxboro, N.C.)
Harris 1 1987 Nuclear 860 MW*
(New Hill, N.C.)
* Facilities are jointly owned by the Company and Power Agency,
and the capacity shown includes Power Agency's share.
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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 1999. 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 2,872 MW of combustion
turbine capacity and 2,406 MW of combined cycle capacity over the
period 2000 to 2009 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" and PART I, ITEM
1, "Competition" for discussion of the Company's long-term purchase
power contracts.
On August 18, 1998 the Company filed with the 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 was anticipated
to begin in June 2000 for both units; however, the Asheville combustion
turbine became operational in February 2000, three months ahead of
schedule.
On March 19, 1999, the Company filed with the NCUC an application for a
Certificate of Public Convenience and Necessity to construct 1600 MW of
combustion turbine generating capacity between two sites, one in Rowan
County and a site in Richmond County. The NCUC granted the certificate
on November 11, 1999. Construction of the combustion turbine in Rowan
county began November 15, 1999 and the construction of the combustion
turbine in Richmond county began February 1, 2000.
During 1999, the Company invested approximately $47.5 million in new
generating plant facilities.
4. PEAK DEMAND. An instantaneous system peak demand record of 10,948 MW
was reached on August 11, 1999. 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 5.22%.
Total system peak demand increased for 1997 by 2.2%, for 1998 by 5.0%
and for 1999 by 4.0% 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 60.6% for 1997,
60.1% for 1998, and 58.2% for 1999. The Company forecasts capacity
margins of 10.5% over anticipated system peak load for 2000 and 10.6%
for 2001. 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
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purchases of power. However, some of the generating units included in
arriving at these capacity margins may be unavailable as a result of
scheduled and unplanned outages.
INTERCONNECTIONS WITH OTHER SYSTEMS
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1. INTERCONNECTIONS. 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). In
addition, the Company, on occasion, will reserve daily to hourly
transmission on Duke Energy's (Duke) system under the transmission
tariff in order to accommodate the peak demand in the western control
area.
2. INTERCHANGE AND POWER PURCHASE/SALE AGREEMENTS.
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a) The Company has interchange agreements with APCO, 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 2b below. Purchases and sales
under these agreements may be made due to economic or reliability
considerations.
In June 1999, the Company terminated Schedule G to the
Interchange Agreement between the Company and Duke. Schedule G
provided for the wheeling of electricity between the Company's
eastern area and its western area.
On December 31, 1999, the Company terminated the Standby
Concurrent Exchange Agreement (Standby Agreement) between the
Company and Duke. The Standby Agreement provided 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," 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) From July 1993 through June 1999, Duke provided 400 MW of firm
capacity to the Company's system. The Company terminated this
contract in 1999. Purchases under this agreement, including
transmission use charges, totaled $33.8 million in 1999.
b) The Company has 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
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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 1999, purchases
under this agreement, including transmission use charges, totaled
$59.5 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 MW. 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.
The estimated minimum annual payments for these purchases, which
reflect capital-related capacity costs, total approximately $26
million. Purchases under this agreement totaled $36.5 million in 1999.
COMPETITION
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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
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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 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.
On December 20, 1999, the FERC issued a rule on Regional Transmission
Organizations (RTO) that sets forth four minimum characteristics and
eight functions for transmission entities, including independent system
operators and transmission companies, to become FERC-approved RTOs. The
rule states that public utilities that own, operate or control
interstate transmission facilities must file by October 15, 2000,
either a proposal to participate in an RTO or an alternative filing
describing efforts and plans to participate in an RTO. The Company
plans to participate in an RTO and anticipates complying with this
filing requirement.
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. In April 1997, the North Carolina 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
study 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
North Carolina General Assembly, summarizing the numerous fact-finding
and educational activities and analytical projects the study commission
had initiated or completed. That report offered no judgments or
recommendations. In May 1999, the North Carolina General Assembly
approved legislation that expanded the study commission from 23 to 29
members. All 29 study commission members were appointed by August 1999.
The study commission conducted several meetings during August through
November to discuss the reports regarding deregulation issues prepared
by the Research Triangle Institute at the request of the study
commission. During those meetings, several entities, including the
Company and Duke, presented proposals for addressing the nearly $6
billion debt of North Carolina's Municipal Power Agencies. The study
commission resumed meeting in January 2000. On
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March 8, 2000, the commission co-chairs presented draft recommendations
regarding electric industry restructuring to the full study commission
for its consideration in preparing its report to the North Carolina
General Assembly. Key recommendations in the draft include (i) electric
retail competition should begin in North Carolina no later than June
30, 2006; (ii) recovery of utilities' stranded costs should not be
extended beyond June 30, 2006; and (iii) the generation and
distribution of assets of the municipal power agencies (including Power
Agency) should be sold no later than June 30, 2002, and the funds from
those sales should be used to pay off a portion of the municipal power
agencies' debt. The draft recommendations also address issues related
to the legislative timetable, consumer protection measures,
environmental concerns, tax laws, and transmission and distribution.
Implicit in recommendation is a rate freeze through the year 2006.
Initial comments on the draft recommendations were due on March 10,
2000. The Company and other interested parties submitted comments. The
draft recommendations will serve as a starting point for preparation of
the study commission's report addressing industry restructuring in the
State of North Carolina. The recommendations and related issues will be
debated and discussed at future study commission meetings. The
commission is expected to make a final report to the North Carolina
General Assembly in the spring of 2000. The Company cannot predict the
outcome of this matter.
5. SOUTH CAROLINA ACTIVITIES. The 1999 session of the South Carolina
General Assembly adjourned in June 1999 without approving any
legislation regarding electric industry 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 Senate. The task force was subsequently expanded
to 18 members, including the Company. The task force, including its
various committees, has conducted several meetings to receive input
from various experts and interested parties and to discuss issues
related to restructuring.
The House Public Utility Subcommittee is expected to continue
considering the electric industry restructuring bills that were
introduced in 1999, and the Senate task force is expected to continue
to consider the issue of restructuring during the South Carolina
General Assembly's 2000 legislative session. The Company cannot predict
the outcome of these matters.
6. FEDERAL ACTIVITIES. During 1999, over 20 bills were introduced in
Congress regarding electric industry restructuring. A draft bill passed
the House Commerce Subcommittee on October 27, 1999. This bill will
proceed to full Commerce Committee consideration in the first quarter
of 2000 where it is expected to be changed significantly. 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. The Company took a
major step towards implementing this strategy, by entering into the
Amended Agreement with FPC.
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 (BRE), in Cherokee County, South
Carolina. In conjunction with this agreement, the Company agreed to
provide bridge financing to BRE under a Financing Term Sheet. This
financing will be used by BRE to (i) make payments to Duke Energy in
connection with certain electrical interconnection agreements, (ii)
purchase two generator step up transformers and (iii) acquire land for
the Broad River Energy Center Project. Under the terms of this
agreement, the Company agreed to loan BRE up to $20.5 million that will
be due on July 1, 2000. In
11
<PAGE>
addition, in August of 1999 the Company agreed to loan Broad River
Investors, LLC up to $84.5 million that will be due on July 1, 2000 to
finance the purchase of the combustion turbines for the project.
Interest on each of the loans is calculated based on the London
Inter-Bank Offer Rate, LIBOR, plus a spread of 1%.
In August 1999, the Company signed a five-year agreement with Municipal
Electric Authority of Georgia (MEAG) pursuant to which MEAG will
receive the full output of a 160 MW combustion turbine owned and
operated by Monroe Power Company, a wholly owned subsidiary of the
Company. Headquartered in Atlanta, Georgia, MEAG represents 48
municipal electric utilities in Georgia and is part owner of four
generating facilities and the Georgia Integrated Transmission System.
In August 1999, the Company signed an off-system wholesale peaking
power sales agreement with Santee Cooper. The Company will provide up
to 150 MW of additional peaking power for a one-year term from June
2001 to May 2002, to help meet the increasing demand in Santee Cooper's
fast-growing service area.
In October 1999, the Company and the Albemarle-Pamlico Economic
Development Corporation (APEC) announced their intention to build an
850-mile natural gas transmission and distribution system to 14
currently unserved counties in eastern North Carolina. The Company will
operate both the transmission and distribution systems and APEC will
help ensure that the new facilities are built in the most advantageous
locations to promote development of the economic base in the region. In
conjunction with this proposal, the Company and APEC filed a joint
request with the NCUC for $186 million of a $200 million state bond
package established for clean water and natural gas infrastructure. If
granted, these funds will be used to pay for the portion of the project
that likely could not be recovered from future gas customers through
rates. The Company plans to invest an additional $11.5 million, thus
bringing the total cost of the project to $197.5 million. As proposed,
the project is scheduled to be developed in phases through 2003. The
NCUC has established a procedural schedule with hearings regarding the
first phase of the project to be conducted in April 2000. An order is
expected mid-2000. The Company cannot predict the outcome of this
matter.
In December 1999, the Company announced plans to build a 30-inch
natural gas pipeline in North Carolina that will extend approximately
82 miles from Williams Energy's Transcontinental interstate pipeline in
Iredell County to Richmond County. The pipeline will provide gas for
the Company's planned new power plant in Richmond County and is
scheduled to be completed during the spring of 2001. The pipeline is
expected to cost approximately $100 million and will accommodate
extension of natural gas service to future Company power plants and
normal load growth on NCNG's system. This pipeline plan replaces a plan
for a 175-mile pipeline, the Palmetto Pipeline that the Company and
Southern Natural Gas Company, a subsidiary of El Paso Energy, had been
assessing.
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."
12
<PAGE>
CAPITAL REQUIREMENTS
- --------------------
CAPITAL REQUIREMENTS. During 1999, the Company expended approximately
$862 million for capital requirements. Estimated capital requirements
for 2000 through 2002 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):
<TABLE>
<CAPTION>
2000 2001 2002
------- ------- -------
<S> <C> <C> <C>
Construction Expenditures $ 851 $ 876 $ 912
Nuclear Fuel Expenditures 64 94 66
AFUDC (21) (32) (38)
Mandatory Retirements of Long-Term Debt 201 5 251
------- ------- -------
TOTAL $ 1,095 $ 943 $ 1,191
======= ======== =======
</TABLE>
The table includes expenditures of approximately $311 million expected
to be incurred at fossil-fueled electric generating facilities to
comply with the Clean Air Act.
In addition, the Company has total projected cash requirements of
approximately $565 million over the years 2000 through 2002 relating to
expenditures in other areas such as affordable housing investments and
merchant generation. These projections are periodically reviewed and
may change significantly.
FINANCING REQUIREMENTS
- ----------------------
1. FINANCING REQUIREMENTS. The proceeds from the issuance of commercial
paper and/or internally generated funds financed the retirement of
long-term debt totaling $113 million in 1999. In addition, the issuance
of $500 million extendible notes in October 1999, financed the
retirement of $100 million of extendible commercial notes and reduced
the outstanding commercial paper balance. External funding
requirements, which do not include early redemptions of long-term debt,
redemption of preferred stock or issuances in conjunction with
acquisitions, are expected to approximate $490 million, $580 million
and $640 million in 2000, 2001 and 2002, 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.
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 first
mortgage bonds, senior notes and other debt
securities are available for issuance by the Company.
As of December 31, 1999, the Company had $600 million
available under this shelf registration.
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.
13
<PAGE>
3. ISSUANCES OF BONDS, PREFERRED STOCK AND DEBENTURES.
---------------------------------------------------
External financings during 1999 included:
i) The issuance on March 5, 1999 of $400 million
principal amount of Senior Notes, 5.95% Series due on
March 1, 2009. The net proceeds were used to reduce
the outstanding balance of commercial paper and for
other general corporate purposes.
ii) In October 1999, the Company issued $500 million of
unsecured Extendible Notes with a final maturity of
October 28, 2009, and an initial reset period from
October 28, 1999 to July 28, 2000 at an interest rate
to be reset and payable on a monthly basis at a rate
equal to the one month LIBOR plus a spread of 0.33%.
The net proceeds from this issuance were used to
reduce commercial paper borrowings and other
short-term indebtedness.
4. REDEMPTIONS/RETIREMENTS OF BONDS, PREFERRED STOCK AND DEBENTURES.
----------------------------------------------------------------
Redemptions and retirements during 1999 included:
i) The retirement on July 1, 1999 of $50 million
principal amount of First Mortgage Bonds, Medium Term
Notes, 7.15% Series B, which matured on that date.
ii) The redemption on August 9, 1999 of $25 million
principal amount of, 9.21% Debentures Series C, due
November 15, 2011 on behalf of NCNG.
iii) The redemption on August 13, 1999 of $30 million
principal amount of, 7.15% Debentures Series, due
November 15, 2015 on behalf of NCNG.
5. CREDIT FACILITIES. As of December 31, 1999, the Company's revolving
credit facilities totaled $750 million, all of which are long-term
agreements. 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, pollution control revenue
refunding bonds (pollution control bonds) and other short-term
indebtedness on a long-term basis, and as supported by its long-term
revolving credit facilities, the Company included in long-term debt
commercial paper, pollution control bonds and other short-term
indebtedness outstanding of approximately $363 million, $56 million and
$331 million, respectively, as of December 31, 1999. Commercial paper
and pollution control bonds outstanding of approximately $488 million
and $56 million, respectively, were reclassified as long-term debt as
of December 31, 1998. See PART II, ITEM 8, "Consolidated Financial
Statements and Supplementary Data," Note 6, for a more detailed
discussion of the Company's revolving credit facilities.
6. COMMERCIAL NOTES. In September 1999, the Company established a $150
million extendible commercial notes program. As of December 31, 1999,
there were no extendible commercial notes outstanding.
7. CREDIT RATINGS. The Company's access to outside capital depends on its
ability to maintain its credit ratings. The Company's credit ratings
are as follows:
14
<PAGE>
<TABLE>
<CAPTION>
Moody's
Duff and Phelps Investors Service Standard and Poor's
--------------- ----------------- -------------------
<S> <C>
First Mortgage Bonds A+ A2 A
Commercial Paper D-1 P-1 A-1
Extendible Commercial Notes N/A P-1 A-1
Extendible Notes D-1 P-1 A-1
</TABLE>
The following is a summary of the meanings of the ratings shown above
and the relative rank of the Company's rating within each agency's
classification system.
Duff and Phelps' top four bond ratings (AAA, AA, A and BBB) are
considered "investment grade." Debt that is rated "A" is considered
upper grade securities which possess adequate protection factors but
risk factors that are more variable in periods of economic stress. Duff
and Phelps may use a plus (+) or minus (-) sign to designate the
relative position of a credit within the rating category. Moody's top
four bond ratings (Aaa, Aa, A and Baa) are generally considered
"investment grade." Obligations that are rated "A" possess many
favorable investment attributes and are considered as upper medium
grade obligations. Factors giving security to principal and interest
are considered adequate but elements may be present which suggest a
susceptibility to impairment sometime in the future. A numerical
modifier ranks the security within the category with a "2" indicating
the mid-range. Standard & Poor's top four bond ratings (AAA, AA, A and
BBB) are considered "investment grade." Debt rated "A" has a strong
capacity to pay interest and repay principal although it is somewhat
more susceptible to the adverse effects of changes in economic
conditions than debt in higher rated categories. Standard & Poor's may
use a plus (+) or minus (-) sign after ratings to designate the
relative position of a credit within the rating category.
Duff and Phelps' top three commercial paper ratings (D-1, D-2 and D-3)
are generally considered "investment grade." Issuers rated "D-1" have a
very high certainty of timely payment, liquidity factors are excellent
and risk factors are minor. Moody's top three commercial paper ratings
(P-1, P-2 and P-3) are generally considered "investment grade." Issuers
rated "P-1" have a superior ability for repayment of senior short-term
debt obligations and repayment ability is often evidenced by a
conservative structure, broad margins in earnings coverage of fixed
financial charges and well established access to a range of financial
markets and assured sources of alternate liquidity. Standard & Poor's
commercial paper ratings are a current assessment of the likelihood of
timely payment of debt having an original maturity less than 365 days.
The top three Standard & Poor's commercial paper ratings (A-1, A-2 and
A-3) are considered "investment grade." Issues rated "A-1" indicate
that the degree of safety regarding timely payment is either
overwhelming or very strong. Those issues determined to possess
overwhelming safety are denoted with a plus (+) sign designation.
RETAIL RATE MATTERS
- -------------------
1. GENERAL. The Company is subject to regulation in North Carolina by the
NCUC and in South Carolina by the SCPSC with respect to, among other
things, rates and service for electric energy sold at retail, retail
service territory and issuances of securities. The Company is also
subject to regulation in North Carolina by the NCUC with respect to
rates and service for the transmission, distribution, and sale of
natural gas in portions of North Carolina.
2. ELECTRIC RETAIL RATES. The rates of return granted to the Company in
its most recent general rate cases are as follows:
15
<PAGE>
<TABLE>
<CAPTION>
1988 North Carolina Utilities Commission Order (test year ended March 31, 1987)
-------------------------------------------------------------------------------
Capital Weighted Weighted
Capital Structure Ratio Cost Rate Cost
----------------- ----- --------- ----
<S> <C> <C> <C>
Long-Term Debt 48.57% 8.62% 4.19%
Preferred Stock 7.43% 8.75% 0.65%
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% 0.65%
Common Equity 44.72% 12.75% 5.71%
-------
Rate of Return 10.48%
=======
</TABLE>
3. NATURAL GAS RATES. On October 27, 1995, the NCUC issued its Order
granting a general rate increase amounting to $4.2 million in annual
revenues effective November 1, 1995. The Commission's Order approved,
in all material respects, the Stipulation of Settlement reached among
NCNG, the NCUC Public Staff, which represents the using and consuming
public, the Carolina Utility Customers Association, Inc. (CUCA) and
other intervenors in the rate case. The Order provides for a rate of
return on net investment of 10.09% but, pursuant to the Stipulation of
Settlement, did not state separately the rate of return on common
equity nor the capital structure used to calculate revenue
requirements.
4. OTHER RETAIL RATE MATTERS. 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 and
expiring December 1999. The accelerated amortization of these
regulatory assets resulted 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, which expired
December 1999.
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 a minimum of $106 million up to a maximum of $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.
In conjunction with the acquisition, the Company and NCNG signed a
joint stipulation agreement with the Public Staff of the NCUC in which
the Company agreed to cap base retail electric rates, exclusive of fuel
16
<PAGE>
costs, with limited exceptions, through December 2004, and NCNG agreed
to cap margin rates for gas sales and transportation services, with
limited exceptions, through November 1, 2003. Management is of the
opinion that this agreement will not have a material effect on the
consolidated results of operations or financial position of the
Company.
5. 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.
6. 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 3, 1999, the Company filed its 1999 fuel cost recovery
application. The NCUC issued a final order approving the
Company's proposed billing fuel factor of 1.057 cents/kWh on
September 9, 1999. This new factor became effective on
September 15, 1999. On October 8, 1999, CUCA appealed the
Commission's decision.
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. The Company's fuel hearing was held
on March 24, 1999 and by order issued April 1, 1999, the SCPSC
approved the Company's proposed continuation of the existing
fuel factor of 1.122 cents/kWh.
7. 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. By order
issued July 16, 1999, the NCUC approved the Company's proposed avoided
cost rates.
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
17
<PAGE>
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 capital costs associated
with compliance with pollution control laws and regulations at the
Company's existing fossil facilities that the Company expects to incur
from 2000 through 2002 are included in the estimates under PART I, ITEM
1, "Capital Requirements."
2. CLEAN AIR LEGISLATION. The 1990 amendments to the Clean Air Act require
substantial reductions in sulfur dioxide and nitrogen oxide emissions
from fossil-fueled electric generating plants. The Clean Air Act
required the Company to meet more stringent provisions effective
January 1, 2000. The Company will meet the sulfur dioxide emissions
requirements by maintaining sufficient sulfur dioxide emission
allowances. Installation of additional equipment was necessary to
reduce nitrogen oxide emissions. Increased operation and maintenance
costs, including emission allowance expense, installation of additional
equipment and increased fuel costs are not expected to be material to
the consolidated financial position or results of operations of the
Company.
The EPA has been conducting an enforcement initiative related to a
number of coal-fired utility power plants in an effort to determine
whether modifications at those facilities were subject to New Source
Review requirements or New Source Performance Standards under the Clean
Air Act. The Company has recently been asked to provide information to
the EPA as part of this initiative and has cooperated in providing the
requested information. The EPA has initiated enforcement actions which
may have potentially significant penalties against other companies that
have been subject to this initiative. The Company cannot predict the
outcome of this matter.
On October 27, 1998, the 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 emissions 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, a portion of which is reflected in the "Capital Requirements"
discussion under PART II, ITEM 7, "Liquidity and Capital Resources."
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 have been
participating in litigation challenging the NOx SIP call. On March 3,
2000, a three-judge panel of the District of Columbia Circuit Court of
Appeals upheld the EPA's NOx SIP call. Further appeals are being
considered. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving certain petitions under the
Clean Air Act that requires certain sources to make reductions in
nitrogen oxide emissions by 2003. The Company's fossil-fueled electric
18
<PAGE>
generating plants in North Carolina are included in these petitions.
The Company and other states are participating in litigation
challenging the EPA's actions. 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 the 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 both the electric utility and the gas
utility have some connection. In this regard, the electric utility and
the gas utility, along with others, are 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. Both the electric utility and
the gas utility have signed AOCs to investigate certain sites. Both the
electric utility and the gas utility continue to identify parties
connected to individual MGP sites, and to determine their relationships
to other parties at 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 consolidated financial position or results of operations of the
Company.
The Company is periodically notified by regulators such as the North
Carolina Department of Environment and Natural Resources, the South
Carolina Department of Health and Environmental Control, and the U.S.
Environmental Protection Agency (EPA) of its involvement or potential
involvement in sites, other than MGP sites, that may require
investigation and/or remediation. Although the Company may incur costs
at these sites about which it has been notified, based upon current
status of these sites, the Company does not expect those costs to be
material to the consolidated financial position or results of
operations of the Company.
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.
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
19
<PAGE>
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 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 2000, 2001 and 2002 are expected
to total approximately $41 million, $80 million and $29 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, 1999, sufficient
on-site spent nuclear fuel storage capability is available for the
full-core discharge of Brunswick Unit No. 1 through 2001, 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 U.S. Department of Energy (DOE) under
which the DOE agreed to begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required
to sign the same standard contract. In April 1995, the DOE issued a
final interpretation that it did not have an unconditional obligation
to take spent nuclear fuel by January 31, 1998. In Indiana & Michigan
Power v. DOE, the U.S. Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan
Power v. DOE, a group of utilities (including the Company) petitioned
the U.S. Court of Appeals in Northern States Power (NSP) v. DOE,
seeking an order requiring the DOE to begin taking spent nuclear fuel
by January 31, 1998. The DOE took the position that their delay was
unavoidable, and the DOE was excused from performance under the terms
20
<PAGE>
and conditions of the contract. The Court of Appeals issued an order
that precluded the DOE from treating the delay as an unavoidable delay.
However, the Court of Appeals did not order the DOE to begin taking
spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities (including the Company) filed a motion with
the U.S. Court of Appeals to enforce the mandate in NSP v. DOE.
Specifically, the utilities asked the Court to permit the utilities to
escrow their waste fee payments, to order the DOE not to use the waste
fund to pay damages to the utilities, and to order the DOE to establish
a schedule for disposal of spent nuclear fuel. The Court denied this
motion based primarily on the grounds that a review of the matter was
premature and that some of the requested remedies fell outside of the
mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in
the Court of Claims and before the Court of Appeals. The Company is in
the process of evaluating whether it should file a similar action for
damages. In NSP v. United States, the United States Court of Claims
decided that NSP must pursue its administrative remedies instead of
filing an action in the Court of Claims. NSP has filed an interlocutory
appeal to the U.S. Court of Appeals based on NSP's position that the
Court of Claims has jurisdiction to decide the matter. A group of
utilities (including the Company) has submitted an amicus brief in
support of NSP's position.
The Company also continues to monitor legislation that has been
introduced in Congress which might provide some limited relief. The
Company cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC, the
Company's spent nuclear fuel storage facilities will be sufficient to
provide storage space for spent fuel generated on the Company's system
through the expiration of the current operating licenses for all of the
Company's nuclear generating units. Subsequent to the expiration of
these licenses, dry storage may be necessary. The Company has initiated
the process of obtaining the additional NRC approval.
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
21
<PAGE>
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 consolidated financial position or results of
operations 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 June 1991, the
Company began depositing funds into an external trust as a
vehicle to achieve such decommissioning funding.
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, $33.3 million, and
$33.2 million in 1999, 1998, and 1997, respectively.
Accumulated decommissioning costs, which are included in
accumulated depreciation, were $568.0 million and $496.3
million at December 31, 1999 and 1998, respectively. These
costs include amounts retained internally and amounts funded
in an external decommissioning trust. The balance of the
nuclear decommissioning trust was $379.9 million and $310.7
million at December 31, 1999 and 1998, 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
22
<PAGE>
$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 Capability," 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 was issued during the first quarter of 2000. It is
uncertain 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) 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 consolidated financial position or results of
operations of the Company.
c) The Company is insured against public liability for a nuclear
incident up to $9.7 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,
23
<PAGE>
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 16b.
FUEL
- ----
1. SOURCES OF GENERATION. Total system generation (including Power
Agency's share) by primary energy source, along with purchased power,
for the years 1996 through 2000 is set forth below:
1996 1997 1998 1999 2000
---- ---- ---- ---- ----
(estimated)
Fossil 45% 46% 47% 48% 48%
Nuclear 41 43 42 42 41
Purchased Power 12 10 9 8 8
Hydro 2 1 1 1 1
Combustion Turbine -- -- 1 1 2
2. COAL. The Company has intermediate and long-term agreements from which
it expects to receive approximately 80% of its coal burn requirements
in 2000. These agreements have expiration dates ranging from 2000 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 1999 was
$41.98 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, twelve combustion turbine units with a total
generating capacity of 766 MW can also burn natural gas. Over the last
five years, No. 2 oil, natural gas and propane accounted for 2.89% of
the Company's total burned fuel cost. In 1999, No. 2 oil, natural gas
and propane accounted for 4.37% 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), and 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
24
<PAGE>
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."
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 $40 million in D&D fees through
1999, and expects to pay a cumulative total of approximately $82
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 4,730,657 MWh in 1999, 5,336,867
MWh in 1998, and 5,886,722 MWh in 1997 or approximately 8%, 9%, and
10%, respectively, of its system energy requirements (including Power
Agency) and had available 1,489 MW in 1999, 1,438 MW in 1998, and 1,839
MW in 1997 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.
NATURAL GAS SUPPLY
- ------------------
During 1999, the Company purchased 7,647,462 dekatherms (dt) of natural
gas under its firm sales contracts on the pipeline/utility. It
purchased 20,023,674 dt in the spot market or from other nontraditional
sources, including long-term contracts with producers or national gas
marketers. The Company also transported 6,961,187 dt of customer-owned
gas in 1999. The outlook for natural gas supplies in the Company's
service area remains favorable and the Company has many sources of gas
available on a firm basis. Nationally, gas supplies are adequate and no
supply curtailments are anticipated.
25
<PAGE>
The following table summarizes the supply sources which are under
contract or otherwise available to the Company as of December 31, 1999.
<TABLE>
<CAPTION>
Maximum Contract
Daily Annual Expiration
Deliverability (a) Quantity (a) Date
Dt dt
Transco -
<S> <C> <C> <C>
Firm Transportation (FT) 145,935 (b) 53,266,275 2013
Firm Sales (FS) 55,935 20,416,275 2001
General Storage (GSS) 2,070 98,790 2013
Washington Storage (WSS) 32,154 (c) 2,734,180
Liquefied Gas Storage (LG-A) 5,320 26,600 2016
Southern Expansion (FT) 16,871 (b) (d) 2,444,553 2005
Eminence Storage (ESS) 39,373 (g) 316,914 2013
Columbia Gas Transmission -
Firm Transportation (FT) 19,801 (b) 7,227,365 2004
Firm Storage Services (FSS) 5,199 223,238 2004
Amerada Hess -
Firm Sales 15,000 (e) (f) 3,732,750 2004
Firm Sales 25,000 (f) 9,125,000 2001
Conoco, Inc. -
Firm Sales 10,000 (e) (f) 2,580,000 2001
Coral Energy Resources -
Firm Sales 25,000 (e) (f) 6,450,000 2000
Amoco Energy Trading Corp. -
Firm Sales 25,000 (f) 9,125,000 2001
Columbia Energy -
Firm Sales 25,000 (f) 9,125,000 2001
PanCanadian Energy -
Firm Sales 25,000 (f) 9,125,000 2001
Exxon Company, U.S.A. -
Firm Sales 14,888 (f) 5,434,120 2003
Southern Company Energy Marketing -
Firm Sales 25,000 (f) 9,125,000 2001
MEG Marketing -
Firm Sales 5,000 (d) (f) 755,000 2001
LNG Plant (Company Owned) - 97,200 (h) 1,000,000 N/A
</TABLE>
26
<PAGE>
(a) Quantities are shown in dekatherms (dt) (one dt equals 1,000,000 Btu or
one Mcf at Btu/cu. ft.).
(b) Firm Transportation (FT) contracts are for pipeline capacity only. The
Company is responsible for acquiring its own gas supplies to be
transported on a firm basis under the FT contracts. Gas supplies are
available under the Transco Firm Sales (FS) Agreement, other long-term
agreements (See f below), multi-month term agreements or agreements of
one month or less for supplies purchased in the spot market.
(c) Washington Storage volumes may be withdrawn to the extent that the
basic contract gas from Transco or other suppliers is unavailable on
any day or if the Company elects to take such gas instead of other
supplies. Service has continued subsequent to contract expiration under
provisions of Transco's FERC tariff. FERC approval of abandonment would
be required to terminate service.
(d) Winter months only (November through March).
(e) Provides for a lower daily deliverability volume in the summer period
(April through October).
(f) Contracts are for gas supply only - no pipeline capacity is included.
Supplies purchased from these suppliers flow on the Company's FT
contracts with Transco (See b above).
(g) Transco salt dome storage capacity allocated to customers of Transco FS
sales service by mandate of FERC order 636. Transco schedules
injections and withdrawals of gas from Eminence storage capacity under
agency agreements with the Company and the other FS sales service
customers.
(h) Deliverability of Company's transmission pipeline capacity to
distribute supplies withdrawn from storage at the Company's LNG plant
under normal operating conditions.
DIVERSIFIED BUSINESSES
- ----------------------
In 1999, the Company formed Monroe Power Company (Monroe), a wholly
owned subsidiary. Monroe is a North Carolina corporation, authorized to
do business in Georgia where it owns and operates a combustion turbine,
which became operational in December 1999.
In 1999, the Company completed the sale of Parke, a division of SRS
that performed lighting retrofit services.
In 1998, the Company formed Powerhouse Square, LLC, to facilitate the
renovation of several historic buildings in North Carolina.
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
27
<PAGE>
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 investigation 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.
28
<PAGE>
4. YEAR 2000. The Company's critical systems, devices and applications
successfully made the transition to the Year 2000. It is possible,
however, that the Company, its vendors, distributors, suppliers or
customers may encounter future Year 2000-related problems. If this
should occur, we do not expect to experience any material adverse
effects on our business, financial condition or results of operations.
As of January 31, 2000, the Company had incurred and expensed
approximately $18 million related to the inventory, assessment and
remediation of non-compliant systems, equipment and applications. The
Company does not expect additional costs related to the Year 2000
Project to be material to the consolidated financial position or
results of operations of the Company.
EMPLOYEES
- ---------
At December 31, 1999, the Company had 7,752 full-time employees. The
Company has a noncontributory defined benefit retirement plan for
substantially all full-time employees and an employee stock purchase
plan among other employee benefits. The Company also provides
contributory postretirement benefits, including certain health care and
life insurance benefits, for substantially all retired employees.
29
<PAGE>
<TABLE>
<CAPTION>
OPERATING STATISTICS-ELECTRIC
- -----------------------------
Years Ended December 31
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - coal 28,260 27,576 25,545 24,859 23,517
nuclear 22,451 22,014 21,690 20,284 19,949
hydro 520 790 799 882 824
combustion turbines 435 386 189 68 56
Purchased 5,132 5,675 6,318 7,292 7,433
---------- ---------- ---------- ---------- ----------
Total energy supply (Company share) 56,798 56,441 54,541 53,385 51,779
Power Agency share (c) 4,353 4,349 4,101 3,616 3,828
---------- ---------- ---------- ---------- ----------
Total system energy supply 61,151 60,790 58,642 57,001 55,607
========== ========== ========== ========== ==========
Average fuel cost (per million BTU)
Fossil $ 1.75 $ 1.71 $ 1.75 $ 1.75 $ 1.83
Nuclear fuel $ .46 $ 0.46 $ 0.46 $ 0.45 $ 0.46
All fuels $ 1.16 $ 1.14 $ 1.14 $ 1.14 $ 1.17
Energy sales (millions of kWh)
Retail
Residential 13,318 13,117 12,488 12,611 12,074
Commercial 11,074 10,664 10,010 9,615 9,276
Industrial 14,473 14,911 15,073 14,456 14,312
Other Retail 1,352 1,357 1,294 1,263 1,288
Wholesale 14,542 14,427 13,900 13,383 12,940
---------- ---------- ---------- ---------- ----------
Total energy sales 54,759 54,476 52,765 51,328 49,890
Company uses and losses 2,039 1,964 1,776 2,057 1,889
---------- ---------- ---------- ---------- ----------
Total energy requirements 56,798 56,440 54,541 53,385 51,779
========== ========== ========== ========== ==========
Electric customers billed
Residential 1,020,864 996,398 972,385 945,703 920,495
Commercial 183,914 178,588 172,821 167,151 159,064
Industrial 5,045 5,056 5,072 5,066 4,863
Government and municipal 2,731 2,757 2,785 2,774 2,328
Resale 39 35 43 27 17
---------- ---------- ---------- ---------- ----------
Total electric customers billed 1,212,593 1,182,834 1,153,106 1,120,721 1,086,767
========== ========== ========== ========== ==========
Electric revenues (in thousands)
Retail $2,519,348 $2,532,234 $2,450,509 $2,417,011 $2,399,354
Wholesale 549,870 528,253 507,720 512,579 560,676
Miscellaneous revenue 69,628 69,558 65,860 66,125 46,523
---------- ---------- ---------- ---------- ----------
Total electric revenues $3,138,846 $3,130,045 $3,024,089 $2,995,715 $3,006,553
========== ========== ========== ========== ==========
Peak demand of firm load (thousands of kW)
System 10,948 10,529 10,030 9,812 10,156
Company 10,344 9,875 9,344 9,264 9,500
Total capability at year-end (thousands of kW) (a)
Fossil plants 6,736 6,571 6,571 6,331 6,331
Nuclear plants 3,174 3,174 3,064 3,064 3,064
Hydro plants 218 218 218 218 218
Purchased 1,088 1,538 1,588 1,603 1,592
---------- ---------- ---------- ---------- ----------
Total system capability 11,216 11,501 11,441 11,216 11,205
Less Power Agency-owned portion (b) 593 593 690 686 682
---------- ---------- ---------- ---------- ----------
Total Company capability 10,623 10,908 10,751 10,530 10,523
========== ========== ========== ========== ==========
</TABLE>
(a) Represents maximum dependable capacity of installed generating units plus
other resources, including firm purchases.
For 1999, total system capability during the summer was higher by 800 MW
for term purchase contracts in place at time of summer peak.
(b) Net of the Company's purchases from Power Agency.
(c) Represents Power Agency's share of the energy supplied from the four
generating facilities that are jointly owned.
30
<PAGE>
<TABLE>
<CAPTION>
OPERATING STATISTICS-NATURAL GAS*
---------------------------------
Year Ended December 31,
1999
---------------
Natural gas sales and transportation revenues (in thousands)
<S> <C>
Residential $ 14,259
Commercial 12,433
Industrial 49,317
Electric Utilities 10,395
Wholesale 12,464
Other 35
---------------
Total natural gas sales and transportation revenues $ 98,903
===============
Natural gas sales (in thousands of dt)
Residential 1,601
Commercial 2,165
Industrial 17,755
Electric Utilities 1,960
Wholesale 4,083
---------------
Total natural gas sales 27,564
===============
Gas sold 20,711
Gas transported 6,853
---------------
Total natural gas sales 27,564
===============
Customers billed (peak month)
Residential 102,579
Commercial 13,856
Industrial and electric utilities 473
Wholesale 50,345
Propane 10,747
---------------
Total gas customers billed 178,000
===============
</TABLE>
*Statistics reflect natural gas operations since the acquisition of NCNG by
the Company.
31
<PAGE>
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 in addition to combustion turbines, with a total
generating capacity (including Power Agency's share) of 10,128 megawatts (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.
The Company, through Monroe, a wholly owned subsidiary, owns and operates a
combustion turbine in Georgia. The full output of 160 MW is received by MEAG,
which represents 48 municipal electric utilities located in Georgia.
At December 31, 1999, the Company had 5,585 pole miles of transmission lines
including 292 miles of 500 kilovolt (kV) lines and 2,857 miles of 230 kV lines,
and distribution lines of approximately 44,294 pole miles of overhead lines and
approximately 13,842 miles of underground lines. Distribution and transmission
substations in service had a transformer capacity of approximately 34,654
kilovolt-ampere (kVA) in 2,028 transformers. Distribution line transformers
numbered 436,334 with an aggregate 18,599,000 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 owns and operates a liquefied natural gas storage plant which
provides 120,000 dekatherms (dt) per day to the Company's peak-day delivery
capability.
The Company owns approximately 1,128 miles of transmission pipelines of two to
16 inches in diameter which connect its distribution systems with the
Texas-to-New York transmission system of Transco and the southern end of
Columbia's transmission system. Transco delivers gas to the Company at various
points conveniently located with respect to the Company's distribution area.
Columbia delivers gas to one delivery point near the North Carolina - Virginia
border. Gas is distributed by the Company through 2,865 miles of distribution
mains. These transmission pipelines and distribution mains are located primarily
on rights-of-way held under easement, license or permit on lands owned by
others.
The Company believes that all of its facilities are suitable, adequate,
well-maintained and in good operating condition.
32
<PAGE>
Plant Accounts (including nuclear fuel) - During the period January 1, 1995
through December 31, 1999, there were $2,614,194,099 additions to the Company's
electric utility plant accounts, $762,069,536 retirements and ($11,995,118)
transfers and adjustments resulting in net additions of $1,840,129,445 to the
electric utility plant. These net additions represent an increase of
approximately 18.89%.
During 1999, the Company acquired North Carolina Natural Gas Corporation
resulting in a December 31, 1999 gas utility balance of $354,772,562.
33
<PAGE>
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
- ------- ---------------------------------------------------
(a) A special shareholder meeting was held on October 20, 1999.
(b) The meeting was held to approve the Agreement and Plan of Share Exchange
between the Company and CP&L Energy, Inc.
(c) The total votes were as follows:
Total Shareholder Accounts Voting 39,010
Total Votes Cast 123,640,874
<TABLE>
<CAPTION>
Votes For Votes Against Votes Withheld
--------- ------------- --------------
<S> <C> <C> <C> <C> <C> <C>
104,960,978 - 65.5%* 16,998,911 - 10.6%* 1,680,985 - 1.0%*
</TABLE>
*percentages represent portion of total available votes not total votes cast.
34
<PAGE>
<TABLE>
<CAPTION>
EXECUTIVE OFFICERS OF THE REGISTRANT
------------------------------------
Name Age Recent Business Experience
- ---- --- --------------------------
<S> <C> <C>
William Cavanaugh III 61 CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER, May 1999 to present;
President and Chief Executive Officer, October 1996 to May 1999;
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.
Robert B. McGehee 57 EXECUTIVE VICE PRESIDENT, GENERAL COUNSEL, CHIEF ADMINISTRATIVE OFFICER
AND INTERIM CHIEF FINANCIAL OFFICER, Administrative Services, Corporate
Relations and Financial Services, March 3, 2000 to present; Executive
Vice President, General Counsel and Chief Administrative Officer,
Administrative Services and Corporate Relations, March 1999 to present;
Senior Vice President and General Counsel, Public and Corporate
Relations, May 1997 to March 1999. From 1974 to May 1997, Mr. McGehee
was a practicing attorney with Wise Carter Child & Caraway, a law firm
in Jackson, Mississippi. He primarily handled corporate, contract,
nuclear regulatory and employment matters. From 1987 to 1997 he
managed the firm, serving as chairman of its Board from 1992 to May
1997.
William S. Orser 55 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.
Fred N. Day, IV 56 SENIOR VICE PRESIDENT, Energy Delivery, July 1997 to present; Vice
President, Western Region, 1995 to July 1997; Manager, Total Quality
Performance, 1993 to 1995.
Cecil L. Goodnight 56 SENIOR VICE PRESIDENT, Retail Sales and Services (CEO of Strategic
Resource Solutions Corp., a wholly owned subsidiary of the Company),
December 1998 to present; Senior Vice President and Chief
Administrative Officer, Administrative Services, December 1996-
December 1998; Senior Vice President, Human Resources and Support
Services, March 1995 to December 1996; Vice President, Human Resources
(formerly Employee Relations Department), May 1983 to March 1995.
C.S. Hinnant 55 SENIOR VICE PRESIDENT AND CHIEF NUCLEAR OFFICER, Nuclear Generation,
June 1998 to present; Vice President, Brunswick Nuclear Plant, April
1997 to May 1998; Vice President, Robinson Nuclear Plant, March 1994 to
March 1997.
35
<PAGE>
William D. Johnson 46 SENIOR VICE PRESIDENT AND CORPORATE SECRETARY, Legal and Risk
Management, March 1999 to present; Vice President-Legal Department and
Corporate Secretary, 1997 to 1999; Vice President, Senior Counsel and
Manager-Legal Department, 1995 to 1997; Interim Manager-Legal
Department 1994 to 1995; Associate General Counsel and Practice Group
Leader, 1992 to 1994. Before joining the company, Mr. Johnson was a
practicing attorney and partner with Hunton & Williams, a law firm in
Raleigh, North Carolina.
Tom D. Kilgore 52 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.
Calvin B Wells 64 SENIOR VICE PRESIDENT, (President and Chief Executive Officer - NCNG, a
wholly owned subsidiary of the Company), July 1999 to present. Before
joining the company, Mr. Wells held the position of Chairman, President
and Chief Executive Officer of North Carolina Natural Gas Corporation
from December 1973 to July 1999.
Larry M. Smith 44 VICE PRESIDENT AND CONTROLLER, August 1999 to present. Before joining
the Company, Mr. Smith held the position of Vice President and
Controller for MidAmerican Energy Company from November 1996 to August
1999 and Controller of that company from 1990 to 1996.
</TABLE>
36
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
1. The Company's Common Stock is listed on the New York and Pacific Stock
Exchanges. The high and low sales prices per share, as reported as
composite transactions in The Wall Street Journal, and dividends
declared per share are as follows:
<TABLE>
<CAPTION>
1998 High Low Dividends Declared
- ----- ---- --- ------------------
<S> <C> <C> <C> <C> <C>
First Quarter $45 3/4 $40 5/8 $ .485
Second Quarter 45 1/2 39 1/2 .485
Third Quarter 46 5/8 39 15/16 .485
Fourth Quarter 49 1/16 45 1/16 .500
1999 High Low Dividends Declared
- ---- ---- --- ------------------
First Quarter $47 7/8 $37 5/8 $ .500
Second Quarter 45 36 5/8 .500
Third Quarter 43 1/4 34 1/8 .500
Fourth Quarter 36 13/16 29 1/4 .515
</TABLE>
The December 31 closing price of the Company's Common Stock was $47 1/16 in 1998
and $30 7/16 in 1999.
As of February 29, 2000, the Company had 66,791 holders of record of Common
Stock.
2. Installment Payment of Consideration for Acquisition of Parke
Industries, Incorporated:
a) Securities Delivered. On February 5, 1999, and on February 11,
2000, 10,418 and 14,294 shares, respectively, of the Company's
Common Shares were delivered to a former shareholder of Parke
Industries, Incorporated (Parke) pursuant to an asset purchase
agreement, dated January 30, 1998, by and between SRS and
Parke. The asset purchase agreement provides that on each of
the first three anniversaries of the closing of the above
transaction, SRS is obligated to deliver Parke additional
common shares having a market value of $450,000. The Common
Shares delivered by SRS were acquired in market transactions
and do not represent newly issued shares of the Company.
b) Underwriters and Other Purchases. No underwriters were used in
connection with this issuance of Common Shares. The Common
Shares were received by one individual.
c) Consideration. The consideration for the Common Shares was the
delivery of certain assets of Parke.
d) Exemption from Registration Claimed. The Common Shares
described in this Item were issued on the basis of an
exemption from registration under Section 4(2) of the
Securities Act of 1933. The Common Shares were received by one
individual and are subject to restrictions on resale
appropriate for private placement. Appropriate disclosure was
made to the recipient of the Common Shares.
37
<PAGE>
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
- ------- ------------------------------------
The selected consolidated financial data should be read in conjunction with the
consolidated financial statements and the notes thereto included elsewhere in
this report.
<TABLE>
<CAPTION>
Years Ended December 31
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- ----------
(dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Operating results
Operating revenues $3,357,615 $3,191,668 $3,036,587 $2,999,273 $3,006,553
Net income $ 382,255 $ 399,238 $ 388,317 $ 391,277 $ 372,604
Earnings for common stock $ 379,288 $ 396,271 $ 382,265 $ 381,668 $ 362,995
Ratio of earnings to fixed charges 4.12 4.38 4.17 4.12 3.67
Ratio of earnings to fixed
charges and preferred
stock dividends 4.03 4.28 3.98 3.83 3.43
Per share data
Basic earnings per
Common share $ 2.56 $ 2.75 $ 2.66 $ 2.66 $ 2.48
Diluted earnings per
Common share $ 2.55 $ 2.75 $ 2.66 $ 2.66 $ 2.48
Dividends declared per common
Share $ 2.015 $ 1.955 $ 1.895 $ 1.835 $ 1.775
Assets $9,494,019 $8,401,406 $8,220,728 $8,364,862 $8,199,655
Capitalization
Common stock equity $3,412,647 $2,949,305 $2,818,807 $2,690,454 $2,574,743
Preferred stock - redemption
Not required 59,376 59,376 59,376 143,801 143,801
Long-term debt, net 3,028,561 2,614,414 2,415,656 2,525,607 2,610,343
---------- ---------- ---------- ---------- ----------
Total capitalization $6,500,584 $5,623,095 $5,293,839 $5,359,862 $5,328,887
========== ========== ========== ========== ==========
</TABLE>
38
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
- ---------------------
FOR 1999 AS COMPARED TO 1998 AND 1998 AS COMPARED TO 1997
In this section, earnings and the factors affecting them are discussed. The
discussion begins with a general overview, then separately discusses earnings by
business segment.
In 1999, earnings available for common shareholders of Carolina Power & Light
Company (the Company) were $379.3 million, a 4.3% decrease from $396.3 million
in 1998. Earnings per share decreased from $2.75 per share in 1998 to $2.56 per
share in 1999. Earnings were negatively affected by a decline in electric sales
to industrial customers, a decline in electric revenues due to increased
utilization of the real-time pricing tariff, and the effects of Hurricanes
Dennis and Floyd. Continued customer growth and the addition of North Carolina
Natural Gas Corporation (NCNG) positively affected earnings available for common
shareholders. The Company issued common stock in connection with the acquisition
of NCNG, which resulted in a dilution of earnings per common share.
In 1998, earnings available for common shareholders were $396.3 million, a 3.7%
increase from $382.3 million in 1997. Earnings per share increased from $2.66
per share in 1997 to $2.75 per share in 1998. Contributing to the increase were
continued growth in the Company's service area in the commercial and residential
sectors as well as a more favorable cooling season. Earnings were negatively
affected by increased losses at two of the Company's subsidiaries, Interpath
Communications, Inc. and Strategic Resource Solutions Corp.
ELECTRIC
- --------
The electric segment is primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North and South Carolina.
The territory served 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.
Electric revenue fluctuations as compared to the prior year are due to the
following factors (in millions):
<TABLE>
<CAPTION>
1999 1998
----- ----
<S> <C> <C>
Customer growth/changes in usage patterns* $ 72 $ 90
Industrial sales (22) (8)
Price (31) (31)
Weather (14) 27
Sales to Power Agency - 25
Sales to other utilities 4 -
Other - 3
----- -------
Total $ 9 $ 106
===== =======
</TABLE>
*CUSTOMER GROWTH/CHANGES IN USAGE PATTERNS EXCLUDES INDUSTRIAL CUSTOMERS.
The increase in the customer growth/changes in usage patterns component of
revenue for both comparison periods reflects continued growth in the number of
customers served by the Company. While residential and commercial sales
increased in both periods, industrial sales have decreased resulting from a
decline in the chemical and textile industries. For the 1999 comparison period,
the price-related decrease is due to increased utilization of the real-time
pricing tariff. The price-related decrease for the 1998 comparison period is
attributable to changes in the Power Coordination Agreement between the Company
and North Carolina Electric Membership Corporation (NCEMC), as well as decreases
in the fuel cost component of revenue. The decrease in the weather component for
1999 reflects overall milder-than-
39
<PAGE>
normal weather conditions. The weather component and sales to North Carolina
Eastern Municipal Power Agency (Power Agency) increased during 1998 due to a
more favorable summer cooling season.
The change in fuel expense for 1999 primarily reflects changes in the Company's
generation mix. For 1998, the increase is attributable to a 5.3% increase in
generation.
For the 1999 comparison period, purchased power decreased due to the expiration
in mid-1999 of the Company's long-term purchase power agreement with Duke
Energy. The decrease in 1998 is attributable to a 9.4% reduction in kilowatt
hours (kWh) purchased, which was partially offset by an increase in the average
cost per kWh.
In 1999, other operation and maintenance expense was negatively affected by
$28.6 million of storm restoration expenses incurred as a result of Hurricanes
Dennis and Floyd. The current year was also negatively affected by an increase
in general and administrative expenses. For 1998, a decrease in the general and
administrative expenses portion of other operation and maintenance expense was
partially offset by expenses related to Hurricane Bonnie.
Harris Plant deferred cost, net, decreased in 1998 due to the completion, in
late 1997, of the amortization of the Harris Plant phase-in costs related to the
North Carolina retail jurisdiction.
NATURAL GAS
- -----------
On July 15, 1999, the Company completed its acquisition of NCNG, now a wholly
owned subsidiary. See "NCNG Acquisition" discussion under PART II, ITEM 7,
"Other Matters." NCNG, headquartered in North Carolina, is a natural gas
distribution utility. NCNG sells and transports natural gas to residential,
commercial, industrial and electric power generation customers. NCNG provides
natural gas, propane and related services to approximately 178,000 customers in
110 towns and cities and to four municipal gas distribution systems in
south-central and eastern North Carolina. Much of that area is also part of the
Company's electric service franchise. The ability to offer natural gas to
customers is a priority for the Company as part of its strategy to become a
total energy provider while securing fuel supplies for planned gas-fired
electric generation.
The results of NCNG are included in the Company's financial results since the
date of the acquisition. Natural gas revenues for the six-month period totaled
$98.9 million, while gas purchased for resale totaled $67.5 million and other
operation and maintenance expenses totaled $13.8 million. NCNG's operations
contributed $6.8 million of operating income.
OTHER
- -----
The other segment primarily includes the financial results of two of the
Company's subsidiaries, Strategic Resource Solutions Corp. (SRS) and Interpath
Communications, Inc. (Interpath), which are included in the caption Diversified
businesses on the Consolidated Statements of Income.
SRS, a wholly owned subsidiary, specializes in facilities and energy management
software, systems and services for educational, commercial, industrial and
governmental markets nationwide. SRS's operating losses were $9.9 million in
1999, down from a $34.7 million loss in 1998. Revenues for SRS in 1999 increased
$27.8 million or 61% as compared to the prior year. Of this increase,
unaffiliated revenues represented $25.2 million. This growth is primarily
attributable to large performance contracts in the education and federal
markets. Also contributing to the growth are strong sales in commercial and
industrial building automation and HVAC controls. Even with this growth in
revenues, operating expenses remained relatively flat in 1999 as compared to
1998 due to cost-cutting measures.
Interpath, a wholly owned subsidiary, is an application service provider
offering a full range of managed application services, Internet protocol-based
applications and Internet consulting to businesses. Revenues for Interpath
increased dramatically during 1999 to $73.2 million as compared to $37.6 million
in 1998 and $3.8 million in 1997. Of these amounts, unaffiliated revenues
represented $45.2 million, $15.7 million and $3.8 million in 1999, 1998 and
1997, respectively. This increase is primarily due to an increase in Interpath's
customer base. Operating expenses increased significantly for all years due to
the growth and business expansion of Interpath. This expansion contributed to
40
<PAGE>
Interpath's operating losses of $44.8 million and $15.3 million in 1999 and
1998, respectively. In 1997, prior to the acquisition of Capitol Information
Services, Inc., Interpath's operating income was $1.1 million.
Other Income (Expense)
- ----------------------
In 1997, interest income included $11 million related to an income tax refund.
For 1999, other, net was negatively affected by a $4.1 million loss incurred on
the sale of SRS's lighting division. The $21.1 million change in other, net for
1998 included a $6.0 million non-recurring charge related to an investment
write-off by SRS and various other items, none of which are individually
significant.
Income Taxes
- ------------
In general, income taxes fluctuate with changes in the Company's income before
income taxes. In addition, 1997 income tax expense was negatively affected by
tax provision adjustments of $10 million recorded in 1997 for potential audit
issues related to the in-service date of the Harris Plant.
Preferred Stock Dividend Requirements
- -------------------------------------
The decrease in the preferred stock dividend requirements for 1998 is the result
of the redemption of two preferred stock series in July 1997.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Cash Flow and Financing
- -----------------------
The net cash requirements of the Company arise primarily from operational needs
and support for investing activities, including replacement or expansion of
existing facilities, construction to comply with pollution control laws and
regulations and investments in diversified businesses.
The Company has on file with the Securities and Exchange Commission (SEC) a
shelf registration statement under which first mortgage bonds, senior notes and
other debt securities are available for issuance by the Company. As of December
31, 1999, the Company had $600 million available under this shelf registration.
The Company can also issue up to $180 million of additional preferred stock
under a shelf registration statement on file with the SEC.
The Company's ability to issue first mortgage bonds and preferred stock is
subject to earnings and other tests as stated in certain provisions of its
mortgage, as supplemented, and charter. The Company has the ability to issue an
additional $4.5 billion in first mortgage bonds and an additional 18 million
shares of preferred stock at an assumed price of $100 per share and a $7.40
annual dividend rate. The Company also has 10 million authorized preference
stock shares available for issuance that are not subject to an earnings test.
As of December 31, 1999, the Company's revolving credit facilities totaled $750
million, all of which are long-term agreements supporting its commercial paper
borrowings and other short-term indebtedness. 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 and other short-term
indebtedness on a long-term basis, and as supported by its long-term revolving
credit facilities, the Company included in long-term debt commercial paper and
other short-term indebtedness of $750 million and $488 million at December 31,
1999 and 1998, respectively.
In September 1999, the Company established a $150 million extendible commercial
notes program. As of December 31, 1999, there were no extendible commercial
notes outstanding.
The proceeds from the issuance of commercial paper related to the credit
facilities mentioned above and/or internally generated funds financed the
retirement of long-term debt totaling $113 million in 1999. In addition, the
issuance of $500 million extendible notes in October 1999, financed the
retirement of $100 million of extendible commercial notes and reduced the
outstanding commercial paper balance. External funding requirements, which do
not include early
41
<PAGE>
redemption of long-term debt, redemption of preferred stock or issuances in
conjunction with acquisitions, are expected to approximate $490 million, $580
million and $640 million in 2000, 2001 and 2002, respectively. These funds will
be required for construction, mandatory retirements of long-term debt and
general corporate purposes.
The Company's access to outside capital depends on its ability to maintain its
credit ratings. The Company's debt ratings are as follows:
<TABLE>
<CAPTION>
Moody's
Duff and Phelps Investors Service Standard and Poor's
--------------- ----------------- -------------------
<S> <C>
First Mortgage Bonds A+ A2 A
Commercial Paper D-1 P-1 A-1
Extendible Commercial Notes N/A P-1 A-1
Extendible Notes D-1 P-1 A-1
</TABLE>
The amount and timing of future sales of Company securities will depend on
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.
In addition to the above, an anticipated issuance of common stock and debt is
discussed in the "Florida Progress Corporation" discussion under PART II, ITEM
7, "Other Matters."
Capital Requirements
- --------------------
Estimated capital requirements for 2000 through 2002 primarily reflect
construction expenditures to add generation, transmission and distribution
facilities, as well as to upgrade existing facilities. Those capital
requirements are reflected in the following table (in millions):
<TABLE>
<CAPTION>
2000 2001 2002
---- ---- ----
<S> <C> <C> <C>
Construction expenditures $ 851 $ 876 $912
Nuclear fuel expenditures 64 94 66
AFUDC (21) (32) (38)
Mandatory retirements of long-term debt 201 5 251
------- ----- -------
Total $ 1,095 $ 943 $ 1,191
======= ===== =======
</TABLE>
The table includes expenditures of approximately $311 million expected to be
incurred at fossil-fueled electric generating facilities to comply with the
Clean Air Act.
In addition, the Company has total projected cash requirements of approximately
$565 million for the years 2000 through 2002 relating to expenditures in other
areas such as affordable housing investments and merchant generation plants.
These projections are periodically reviewed and may change significantly.
During 1999, the Company had two long-term agreements for the purchase of power
and related transmission services from other utilities. The first agreement
provides for the purchase of 250 megawatts of capacity through 2009 from Indiana
Michigan Power Company's Rockport Unit No. 2 (Rockport). The second agreement,
which expired mid-1999, was with Duke Energy for the purchase of 400 megawatts
of firm capacity. The estimated minimum annual payment for power purchases under
the Rockport agreement is approximately $31 million, representing
capital-related capacity costs. In 1999, total purchases (including transmission
use charges) under the Rockport and Duke Energy agreements amounted to $59.5
million and $33.8 million, respectively.
In addition, pursuant to the terms of the 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. The estimated minimum annual payments for these
purchases, representing capital-
42
<PAGE>
related capacity costs, total approximately $26 million. Purchases under the
agreement with Power Agency totaled $36.5 million in 1999.
OTHER MATTERS
- -------------
Florida Progress Corporation
- ----------------------------
The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L
Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned
subsidiary of the Company, formerly known as CP&L Holdings, Inc. entered into
an Amended and Restated Agreement and Plan of Share Exchange dated as of August
22, 1999, amended and restated as of March 3, 2000 (the "Amended Agreement").
Under the terms of the Agreement, all outstanding shares of common stock, no par
value, of FPC common stock would be acquired by CP&L Energy in a statutory share
exchange with an approximate value of $5.3 billion. Each share of FPC common
stock, at the election of the holder, will be exchanged for (i) $54.00 in cash
and one contingent value obligation (CVO), or (ii) the number of shares of
common stock, no par value, of CP&L Energy equal to the ratio determined by
dividing $54.00 by the average of the closing sale price per share of CP&L
Energy common stock (Final Stock Price) as reported on the New York Stock
Exchange composite tape for the twenty consecutive trading days ending with the
fifth trading day immediately preceding the closing date for the exchange, and
one CVO or (iii) a combination of cash and CP&L Energy common stock, and one
CVO; provided, however, that shareholder elections shall be subject to
allocation and proration to achieve a mix of the aggregate exchange
consideration that is 65% cash and 35% common stock. The number of shares of
CP&L Energy common stock that will be issued as stock consideration will vary if
the Final Stock Price is within a range of $37.13 to $45.39, but not outside
that range. Thus, the maximum number of shares of CP&L Energy common stock into
which one share of FPC common stock could be exchanged would be 1.4543, and the
minimum would be 1.1897. In addition, FPC shareholders will receive one
contingent value obligation for each share of FPC stock owned. Each contingent
value obligation will represent the right to receive contingent payments that
may be made by CP&L Energy based on certain cash flows that may be derived from
future operations of four synthetic fuel plants currently owned by FPC. In
conjunction with this proposed share exchange, CP&L Energy plans to issue debt
to fund the cash portion of the exchange.
The transaction has been approved by the Boards of Directors of FPC, the Company
and CP&L Energy. Consummation of the exchange is subject to the satisfaction or
waiver of certain closing conditions including, among others, the approval by
the shareholders of FPC and the approval of the issuance of CP&L Energy common
stock in the exchange by the shareholders of the Company or CP&L Energy; the
approval or regulatory review by the Federal Energy Regulatory Commission
(FERC), the SEC, the Nuclear Regulatory Commission (NRC), the North Carolina
Utilities Commission (NCUC), and certain other federal and state regulatory
bodies; the expiration or early termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976; and other customary
closing conditions. In addition, FPC's obligation to consummate the exchange is
conditioned upon the Final Stock Price being not less than $30.00. Both the
Company and FPC have agreed to certain undertakings and limitations regarding
the conduct of their respective businesses prior to the closing of the
transaction. The transaction is expected to be completed in the fall of 2000.
Either party may terminate the Agreement under certain circumstances, including
if the exchange has not been consummated on or before December 31, 2000;
provided that if certain conditions have not been satisfied on December 31,
2000, but all other conditions have been satisfied or waived then such date
shall be June 30, 2001. In the event that FPC or the Company terminate the
Agreement in certain limited circumstances, FPC would be required to pay the
Company a termination fee of $150 million, plus the Company's reasonable
out-of-pocket expenses which are not to exceed $25 million in the aggregate.
On January 31, 2000, applications were filed with the NRC seeking approval of
the change in control of FPC that will result from the share exchange. On
February 3, 2000, CP&L Energy filed an application with the NCUC for
authorization of the share exchange with FPC and the issuance of common stock in
connection with the transaction. On February 3, 2000, CP&L Energy and FPC filed
a joint application with the FERC requesting approval of the share exchange. The
Company cannot predict the outcome of these matters. On March 14, 2000, CP&L
Energy and FPC filed an application with the SEC requesting approval of the
share exchange under the Public Utility Holding Company Act.
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NCNG Acquisition
- ----------------
On July 15, 1999, the Company completed the previously announced acquisition of
NCNG for an aggregate purchase price of approximately $364 million. Each
outstanding share of NCNG common stock was converted into the right to receive
0.8054 shares of Company common stock, resulting in the issuance of
approximately 8.3 million shares. The acquisition has been accounted for as a
purchase and, accordingly, the operating results of NCNG have been included in
the Company's consolidated financial statements since the date of acquisition.
The excess of the aggregate purchase price over the fair value of net assets
acquired, approximately $240 million, has been recorded as goodwill of the
acquired business and is being amortized primarily over a period of 40 years.
NCNG, operating as a wholly owned subsidiary of the Company, is engaged in the
transmission and distribution of natural gas. These gas services are provided
under regulated rates to approximately 178,000 customers in eastern and
south-central North Carolina.
In conjunction with the acquisition, the Company and NCNG signed a joint
stipulation agreement with the Public Staff of the NCUC in which the Company
agreed to cap base retail electric rates, exclusive of fuel costs, with limited
exceptions, through December 2004, and NCNG agreed to cap margin rates for gas
sales and transportation services, with limited exceptions, through November 1,
2003. Management is of the opinion that this agreement will not have a material
effect on the consolidated results of operations or financial position of the
Company.
Diversified Businesses
- ----------------------
In addition to Interpath and SRS, whose results were previously discussed, the
following subsidiaries represent diversified businesses of the Company.
In 1999, the Company formed Monroe Power Company (Monroe), a wholly owned
subsidiary. Monroe is a North Carolina corporation, authorized to do business in
Georgia where it owns and operates a combustion turbine, which became
operational in December 1999. In 1998, the Company formed Powerhouse Square,
LLC, to facilitate the renovation of several historic buildings in North
Carolina.
Retail Rate Matters
- -------------------
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 began 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 a minimum of $106 million to a maximum of $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.
Environmental
- -------------
The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under federal and state laws.
There are several manufactured gas plant (MGP) sites to which both the electric
utility and the gas utility have some connection. In this regard, the electric
utility and the gas utility, along with others, are participating in a
cooperative effort with the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM). The DWM 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.
Both the electric utility and the gas
44
<PAGE>
utility have signed AOCs to investigate certain sites at which investigation
includes the completion of interim remedial measures where appropriate and
anticipate signing AOCs to remediate sites as well. Both the electric utility
and the gas utility continue to identify parties connected to individual MGP
sites, and to determine their relative relationship to other parties at those
sites and the degree to which they will undertake efforts with others at
individual sites. The Company does not expect the costs associated with these
sites to be material to the consolidated financial position or results of
operations of the Company.
The Company is periodically notified by regulators such as the North Carolina
Department of Environment and Natural Resources, the South Carolina Department
of Health and Environmental Control, and the U.S. Environmental Protection
Agency (EPA) of its involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. Although the
Company may incur costs at the sites about which it has been notified, based
upon the current status of these sites, the Company does not expect those costs
to be material to the consolidated financial position or results of operations
of the Company.
The EPA has been conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether modifications
at those facilities were subject to New Source Review requirements or New Source
Performance Standards under the Clean Air Act. The Company has recently been
asked to provide information to the EPA as part of this initiative and has
cooperated in providing the requested information. The EPA has initiated
enforcement actions which may have potentially significant penalties against
other companies that have been subject to this initiative. The Company cannot
predict the outcome of this matter.
The 1990 amendments to the Clean Air Act require substantial reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric
generating plants. The Clean Air Act required the Company to meet more stringent
provisions effective January 1, 2000. The Company will meet the sulfur dioxide
emissions requirements by maintaining sufficient sulfur dioxide emission
allowances. Installation of additional equipment was necessary to reduce
nitrogen oxide emissions. Increased operation and maintenance costs, including
emission allowance expense, installation of additional equipment and increased
fuel costs are not expected to be material to the consolidated financial
position or results of operations of the Company.
On October 27, 1998, the 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 emissions 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, a portion of which is reflected in the "Capital Requirements"
discussion under PART II, ITEM 7, "Liquidity and Capital Resources." 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 have been participating in litigation challenging
the NOx SIP call. On March 3, 2000, a three-judge panel of the District of
Columbia Circuit Court of Appeals upheld the EPA's NOx SIP call. Further appeals
are being considered. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under section 126 of the
Clean Air Act that requires certain sources to make reductions in nitrogen oxide
emissions by 2003. The Company's fossil-fueled electric generating plants are
included in these petitions. The Company and other states are participating in
litigation challenging the EPA's actions. The Company cannot predict the outcome
of this matter.
Nuclear
- -------
In the Company's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC and the Public Service Commission of South
Carolina (SCPSC) and are based on site-specific estimates that include 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. 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.
The Company's most recent site-specific estimates of decommissioning costs were
developed in 1998, using 1998 cost
45
<PAGE>
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.
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. Operating licenses for the
Company's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016
for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris
Plant.
The Financial Accounting Standards Board (FASB) 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 was issued during the first quarter of 2000. It is uncertain what
effects it may ultimately have on the Company's accounting for nuclear
decommissioning and other retirement costs.
As required under the Nuclear Waste Policy Act of 1982, the Company entered into
a contract with the U.S. Department of Energy (DOE) under which the DOE agreed
to begin taking spent nuclear fuel by no later than January 31, 1998. All
similarly situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation to begin
taking spent nuclear fuel. The Court did not specify a remedy because the DOE
was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan Power v.
DOE, a group of utilities (including the Company) petitioned the Court of
Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the
DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the
position that their delay was unavoidable, and the DOE was excused from
performance under the terms and conditions of the contract. The Court of Appeals
issued an order which precluded the DOE from treating the delay as an
unavoidable delay. However, the Court of Appeals did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially adequate
remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a
group of utilities (including the Company) filed a motion with the Court of
Appeals to enforce the mandate in NSP v. DOE. Specifically, the utilities asked
the Court to permit the utilities to escrow their waste fee payments, to order
the DOE not to use the waste fund to pay damages to the utilities, and to order
the DOE to establish a schedule for disposal of spent nuclear fuel. The Court
denied this motion based primarily on the grounds that a review of the matter
was premature and that some of the requested remedies fell outside of the
mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Court of Claims and before the Court of Appeals. The Company is in the process
of evaluating whether it should file a similar action for damages. In NSP v.
U.S., the Court of Claims decided that NSP must pursue its administrative
remedies instead of filing an action in the Court of Claims. NSP has filed an
interlocutory appeal to the Court of Appeals based on NSP's position that the
Court of Claims has jurisdiction to decide the matter. A group of utilities
(including the Company) has submitted an amicus brief in support of NSP's
position.
The Company also continues to monitor legislation that has been introduced in
Congress which might provide some limited relief. The Company cannot predict the
outcome of this matter.
With certain modifications and additional approval by the NRC, the Company's
spent nuclear fuel storage facilities will be sufficient to provide storage
space for spent fuel generated on the Company's system through the expiration of
the current operating licenses for all of the Company's nuclear generating
units. Subsequent to the expiration of these licenses, dry storage may be
necessary. The Company has initiated the process of obtaining the additional NRC
approval.
46
<PAGE>
Competition
- -----------
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.
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 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.
On December 20, 1999, the FERC issued a rule on Regional Transmission
Organizations (RTO) that sets forth four minimum characteristics and eight
functions for transmission entities, including independent system operators and
transmission companies, to become FERC-approved RTOs. The rule states that
public utilities that own, operate or control interstate transmission facilities
must file by October 15, 2000, either a proposal to participate in an RTO or an
alternative filing describing efforts and plans to participate in an RTO. The
Company plans to participate in an RTO and anticipates complying with this
filing requirement.
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.
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<PAGE>
NORTH CAROLINA ACTIVITIES
- -------------------------
In April 1997, the North Carolina 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 study 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 North
Carolina General Assembly, summarizing the numerous fact-finding and educational
activities and analytical projects the study commission had initiated or
completed. That report offered no judgments or recommendations. In May 1999, the
North Carolina General Assembly approved legislation that expanded the study
commission from 23 to 29 members. All 29 study commission members were appointed
by August 1999. The study commission conducted several meetings during August
through November to discuss the reports regarding deregulation issues prepared
by the Research Triangle Institute at the request of the study commission.
During those meetings, several entities, including the Company and Duke Energy,
presented proposals for addressing the nearly $6 billion debt of North
Carolina's Municipal Power Agencies. The study commission resumed meeting in
January 2000. On March 8, 2000, the commission co-chairs presented draft
recommendations regarding electric industry restructuring to the full study
commission for its consideration in preparing its report to the North Carolina
General Assembly. Key recommendations in the draft include (i) electric retail
competition should begin in North Carolina no later than June 30, 2006; (ii)
recovery of utilities' stranded costs should not be extended beyond June 30,
2006; and (iii) the generation and distribution of assets of the municipal power
agencies (including Power Agency) should be sold no later than June 30, 2002,
and the funds from those sales should be used to pay off a portion of the
municipal power agencies' debt. The draft recommendations also address issues
related to the legislative timetable, consumer protection measures,
environmental concerns, tax laws, and transmission and distribution. Implicit in
recommendation is a rate freeze through the year 2006. Initial comments on the
draft recommendations were due on March 10, 2000. The Company and other
interested parties submitted comments. The draft recommendations will serve as a
starting point for preparation of the study commission's report addressing
industry restructuring in the State of North Carolina. The recommendations and
related issues will be debated and discussed at future study commission
meetings. The commission is expected to make a final report to the North
Carolina General Assembly in the spring of 2000. The Company cannot predict the
outcome of this matter.
SOUTH CAROLINA ACTIVITIES
- -------------------------
The 1999 session of the South Carolina General Assembly adjourned in June 1999
without approving any legislation regarding electric industry 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
Senate. The task force was subsequently expanded to 18 members, including the
Company. The task force, including its various committees, has conducted several
meetings to receive input from experts and interested parties and to discuss
issues related to restructuring.
The House Public Utility Subcommittee is expected to continue considering the
electric industry restructuring bills that were introduced in 1999, and the
Senate task force is expected to continue to consider the issue of restructuring
during the South Carolina General Assembly's 2000 legislative session. The
Company cannot predict the outcome of these matters.
FEDERAL ACTIVITIES
- ------------------
During 1999, over 20 bills were introduced in Congress regarding electric
industry restructuring. A draft bill passed the House Commerce Subcommittee on
October 27, 1999. This bill will proceed to full Commerce Committee
consideration in the first quarter of 2000 where it is expected to be changed
significantly. The Company cannot predict the outcome of this matter.
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<PAGE>
COMPANY ACTIVITIES
- ------------------
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 (BRE), in Cherokee County, South Carolina. In conjunction with
this agreement, the Company agreed to provide bridge financing to BRE under a
Financing Term Sheet. This financing will be used by BRE to (i) make payments to
Duke Energy in connection with certain electrical interconnection agreements,
(ii) purchase two generator step up transformers and (iii) acquire land for the
Broad River Energy Center Project. Under the terms of this agreement, the
Company agreed to loan BRE up to $20.5 million that will be due on July 1, 2000.
In addition, in August 1999 the Company agreed to loan Broad River Investors,
LLC up to $84.5 million that will be due on July 1, 2000 to finance the purchase
of the combustion turbines for the project. Interest on each of the loans is
calculated based on the London Inter-Bank Offer Rate, LIBOR, plus a spread of
1%.
In August 1999, the Company signed a five-year agreement with Municipal Electric
Authority of Georgia (MEAG) pursuant to which MEAG will receive the full output
of a 160 MW combustion turbine owned and operated by Monroe Power Company, a
wholly owned subsidiary of the Company. Headquartered in Atlanta, MEAG
represents 48 municipal electric utilities in Georgia and is part owner of four
generating facilities and the Georgia Integrated Transmission System.
In August 1999, the Company signed an off-system wholesale peaking power sales
agreement with Santee Cooper. The Company will provide up to 150 MW of
additional peaking power for a one-year term from June 2001 to May 2002, to help
meet the increasing demand in Santee Cooper's fast-growing service area.
In October 1999, the Company and the Albemarle-Pamlico Economic Development
Corporation (APEC) announced their intention to build an 850-mile natural gas
transmission and distribution system to 14 currently unserved counties in
eastern North Carolina. The Company will operate both the transmission and
distribution systems and APEC will help ensure that the new facilities are built
in the most advantageous locations to promote development of the economic base
in the region. In conjunction with this proposal, the Company and APEC filed a
joint request with the NCUC for $186 million of a $200 million state bond
package established for clean water and natural gas infrastructure. If granted,
these funds will be used to pay for the portion of the project that likely could
not be recovered from future gas customers through rates. The Company plans to
invest an additional $11.5 million, thus bringing the total cost of the project
to $197.5 million. As proposed, the project is scheduled to be developed in
phases through 2003. The NCUC has established a procedural schedule with
hearings regarding the first phase of the project to be conducted in April 2000.
An order is expected mid-2000. The Company cannot predict the outcome of this
matter.
In December 1999, the Company announced plans to build a 30-inch natural gas
pipeline in North Carolina that will extend approximately 82 miles from Williams
Energy's Transcontinental interstate pipeline in Iredell County to Richmond
County. The pipeline will provide gas for the Company's planned new power plant
in Richmond County and is scheduled to be completed during the spring of 2001.
The pipeline is expected to cost approximately $100 million and will accommodate
extension of natural gas service to future Company power plants. This pipeline
replaces a plan for a 175-mile pipeline, the Palmetto Pipeline, that the Company
and Southern Natural Gas Company, a subsidiary of El Paso Energy, had been
assessing.
As a regulated entity, the Company is subject to the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." 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 No. 71 may be affected in the future by competitive forces
and restructuring in the electric utility industry. In the event that SFAS No.
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 SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of."
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Transition to Holding Company Structure
- ---------------------------------------
The Company is in the process of converting to a holding company structure, in
which the Company would become a subsidiary of a newly formed holding company.
This conversion will offer certain advantages as the Company continues to
confront the rapidly changing environment facing electric utilities. The holding
company structure would allow greater organizational flexibility, including a
clearer separation of regulated businesses from each other and from unregulated
businesses such as energy services, telecommunications and electric generation
projects for wholesale markets. The ability to conduct financing activities at
the holding company level without the need for state regulatory approvals will
enable the Company to satisfy financing needs more quickly and efficiently.
The Company's shareholders approved the contemplated holding company structure
on October 20, 1999. The necessary approvals from various regulatory authorities
are expected by the end of the first quarter of 2000. Upon conversion to a
holding company structure, each share of the Company's common stock will
automatically be exchanged for one share of common stock of the new holding
company.
On September 15, 1999, the Company filed an application with the NRC for consent
to indirectly transfer control of its nuclear plant operating licenses to the
newly formed holding company. This application was approved on December 31,
1999.
On October 15, 1999, the Company filed an application with the NCUC to approve
the transfer of ownership of the Company, Interpath and NCNG to the newly formed
holding company. The Company cannot predict the outcome of this proceeding.
On October 18, 1999, the Company filed an application with the SEC for approval
which allows the holding company to acquire voting securities resulting in
control over the Company and NCNG. The Company cannot predict the outcome of
this matter.
On October 20, 1999, the Company filed an application with the SCPSC to approve
the transfer of the Company and Interpath to the newly formed holding company.
The SCPSC issued an order approving the application on March 6, 2000.
On October 25, 1999, the Company filed an application with the FERC for approval
of the proposed reorganization of the Company related to the establishment of
the new holding company. This application was approved on December 23, 1999.
Year 2000
- ---------
The Company's critical systems, devices and applications successfully made the
transition to the Year 2000. It is possible, however, that the Company, its
vendors, distributors, suppliers or customers may encounter future Year
2000-related problems. If this should occur, we do not expect to experience any
material adverse effects on our business, financial condition or consolidated
results of operations.
As of January 31, 2000, the Company had incurred and expensed approximately $18
million related to the inventory, assessment and remediation of non-compliant
systems, equipment and applications. The Company does not expect additional
costs related to the Year 2000 Project to be material to the consolidated
financial position or consolidated results of operations of the Company.
New Accounting Standard
- -----------------------
The FASB has delayed the effective date for SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The delay, published as SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133," changes the effective date to
fiscal years beginning after June 15, 2000. The Company expects to determine any
effects of SFAS No. 133 by mid-2000.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------- ----------------------------------------------------------
The Company is exposed to certain market risks that are inherent in the
Company's financial instruments, which arise from transactions entered into in
the normal course of business. The Company's primary exposures are changes in
interest rates with respect to its long-term debt and commercial paper, and
fluctuations in the return on marketable securities with respect to its nuclear
decommissioning trust funds. These financial instruments are held for purposes
other than trading. The risks discussed below do not include the price risks
associated with nonfinancial instrument transactions and positions associated
with the Company's operations, such as sales commitments and inventory.
INTEREST RATE RISK The Company manages its interest rate risks through use of a
combination of fixed and variable rate debt. Variable rate debt has rates that
adjust in periods ranging from daily to monthly. Interest rate derivative
instruments may be used to adjust interest rate exposures and to protect against
adverse movements in rates. The table below presents principal cash flows and
related weighted-average interest rates, by maturity date, for the Company's
long-term debt, commercial paper and other short-term indebtedness at December
31, 1999, including current portions. In conjunction with the issuance of $400
million principal amount of Senior Notes on March 5, 1999, the Company settled
its interest rate lock, receiving approximately $9.7 million which will reduce
interest expense over the 10-year debt term.
<TABLE>
<CAPTION>
Fair
2000 2001 2002 2003 2004 Thereafter Total Value
-------- -------- -------- -------- -------- ---------- -------- --------
(Dollars in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Fixed rate long-term
debt $ 197 - $ 100 $ 7 $ 300 $ 1,319 $ 1,923 $ 1,845
Average interest rate 6.15% - 7.17% 12.88% 6.88% 7.09% 7.01% -
Variable rate long-
term debt - - - - - $ 620 $ 620 $ 622
Average interest rate - - - - - 3.32% 3.32% -
Commercial paper $ 363 - - - - - $ 363 $ 363
Average interest rate 6.07% - - - - - 6.07% -
Extendible notes $ 500 - - - - - $ 500 $ 500
Average interest rate 5.88% - - - - - 5.88% -
</TABLE>
The fixed and variable rate debt principal cash flows reflected in the table
above are substantially the same as reported at December 31, 1998 for post-1999
debt, except for the issuance of $400 million principal amount of Senior Notes,
5.95% Series due March 1, 2009. Commercial paper outstanding at December 31,
1998 was approximately $488 million. There were no extendible notes outstanding
at December 31, 1998.
MARKETABLE SECURITIES RETURN RISK: The Company maintains trust funds, as
required by the Nuclear Regulatory Commission, to fund certain costs of
decommissioning. These funds are primarily invested in stocks, bonds and cash
equivalents, which are exposed to price fluctuations in equity markets and to
changes in interest rates. At December 31, 1999 and 1998, the fair values of
these funds were approximately $380 million and $311 million, respectively. The
Company actively monitors its portfolio by benchmarking the performance of its
investments against certain indices and by maintaining, and periodically
reviewing, target allocation percentages for various asset classes. The
accounting for nuclear decommissioning recognizes the costs as recovered through
the Company's regulated electric rates and; therefore, fluctuations in trust
fund marketable security returns do not affect the earnings of the Company.
51
<PAGE>
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ------- --------------------------------------------------------
The following consolidated financial statements, supplementary data and
consolidated financial statement schedules are included herein:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Report 53
Consolidated Financial Statements:
Consolidated Statements of Income for the Years Ended December 31,
1999, 1998, and 1997 54
Consolidated Balance Sheets as of December 31, 1999 and 1998 55
Consolidated Statements of Cash Flow for the Years Ended December 31, 1999, 1998
and 1997 56
Consolidated Schedules of Capitalization as of December 31, 1999 and 1998 57
Consolidated Statements of Retained Earnings for the Years Ended December 31, 1999, 1998
and 1997 58
Consolidated Quarterly Financial Data (Unaudited) 58
Notes to Consolidated Financial Statements 59
Consolidated Financial Statement Schedules for the Years Ended December 31, 1999, 1998, and 1997:
II-Valuation and Qualifying Accounts 78
</TABLE>
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Consolidated
Financial Statements or the accompanying Notes to the Consolidated Financial
Statements.
52
<PAGE>
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY:
We have audited the accompanying consolidated balance sheets and schedules of
capitalization of Carolina Power & Light Company and subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended December
31, 1999. Our audits also included the financial statement schedules listed in
the Index at Item 8. These financial statements and financial statement
schedules are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company and subsidiaries at
December 31, 1999 and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1999, in
conformity with generally accepted accounting principles. Also, in our opinion,
such financial statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 8, 2000, except for Note 2, as to which the date is March 3, 2000.
53
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
- ---------------------------------
YEARS ENDED DECEMBER 31
(IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Electric $ 3,138,846 $ 3,130,045 $ 3,024,089
Natural gas 98,903 - -
Diversified businesses 119,866 61,623 12,498
- -----------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,357,615 3,191,668 3,036,587
- -----------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Fuel used in electric generation 581,340 571,419 534,268
Purchased power 365,425 382,547 387,296
Gas purchased for resale 67,465 - -
Other operation and maintenance 682,407 642,478 661,466
Depreciation and amortization 495,670 487,097 481,650
Taxes other than on income 142,741 141,504 139,478
Harris Plant deferred costs, net 7,435 7,489 24,296
Diversified businesses 174,589 111,584 22,156
- -----------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,517,072 2,344,118 2,250,610
- -----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 840,543 847,550 785,977
- -----------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE)
Interest income 10,336 9,526 18,335
Other, net (30,739) (26,108) (4,991)
- -----------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (20,403) (16,582) 13,344
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES AND INCOME TAXES 820,140 830,968 799,321
- -----------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES
Long-term debt 180,676 169,901 163,468
Other interest charges 10,298 11,156 18,743
Allowance for borrowed funds used during construction (11,510) (6,821) (4,923)
- -----------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 179,464 174,236 177,288
- -----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES 640,676 656,732 622,033
INCOME TAXES 258,421 257,494 233,716
- -----------------------------------------------------------------------------------------------------------------------
NET INCOME $ 382,255 $ 399,238 $388,317
- -----------------------------------------------------------------------------------------------------------------------
PREFERRED STOCK DIVIDEND REQUIREMENTS (2,967) (2,967) (6,052)
- -----------------------------------------------------------------------------------------------------------------------
EARNINGS FOR COMMON STOCK $ 379,288 $ 396,271 $382,265
- -----------------------------------------------------------------------------------------------------------------------
AVERAGE COMMON SHARES OUTSTANDING 148,344 143,941 143,645
- -----------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER COMMON SHARE $ 2.56 $ 2.75 $ 2.66
- -----------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER COMMON SHARE $ 2.55 $ 2.75 $ 2.66
- -----------------------------------------------------------------------------------------------------------------------
DIVIDENDS DECLARED PER COMMON SHARE $ 2.015 $ 1.955 $ 1.895
- -----------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
- ---------------------------
(IN THOUSANDS) DECEMBER 31
ASSETS 1999 1998
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C>
UTILITY PLANT
Electric utility plant in service $10,633,823 $10,280,638
Gas utility plant in service 354,773 -
Accumulated depreciation (4,975,405) (4,496,632)
- ------------------------------------------------------------------------------------------------------------
Utility plant in service, net 6,013,191 5,784,006
Held for future use 11,282 11,984
Construction work in progress 536,017 306,866
Nuclear fuel, net of amortization 204,323 196,684
- ------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 6,764,813 6,299,540
- ------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents 79,871 28,872
Accounts receivable 446,367 406,418
Taxes receivable 3,770 21,000
Inventory 247,913 224,701
Deferred fuel cost 81,699 42,647
Prepayments 42,631 19,907
Other current assets 177,082 57,311
- ------------------------------------------------------------------------------------------------------------
Total Current Assets 1,079,333 800,856
- ------------------------------------------------------------------------------------------------------------
DEFERRED DEBITS AND OTHER ASSETS
Income taxes recoverable through future rates 229,008 277,894
Abandonment costs 1,675 16,083
Harris Plant deferred costs 56,142 60,021
Unamortized debt expense 10,924 27,010
Nuclear decommissioning trust funds 379,949 310,702
Diversified businesses property, net 239,982 66,014
Miscellaneous other property and investments 252,454 282,664
Goodwill, net (Note 3E) 288,970 67,017
Other assets and deferred debits 190,769 193,605
- ------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,649,873 1,301,010
- ------------------------------------------------------------------------------------------------------------
Total Assets $9,494,019 $8,401,406
- ------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- ------------------------------------------------------------------------------------------------------------
CAPITALIZATION (SEE CONSOLIDATED SCHEDULES OF
CAPITALIZATION)
- ------------------------------------------------------------------------------------------------------------
Common stock equity $3,412,647 $2,949,305
Preferred stock - redemption not required 59,376 59,376
Long-term debt, net 3,028,561 2,614,414
- ------------------------------------------------------------------------------------------------------------
Total Capitalization 6,500,584 5,623,095
- ------------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES
Current portion of long-term debt 197,250 53,172
Accounts payable 269,053 319,163
Interest accrued 47,607 39,941
Dividends declared 80,939 74,400
Notes payable 168,240 -
Other current liabilities 130,036 108,824
- ------------------------------------------------------------------------------------------------------------
Total Current Liabilities 893,125 595,500
- ------------------------------------------------------------------------------------------------------------
DEFERRED CREDITS AND OTHER LIABILITIES
Accumulated deferred income taxes 1,632,778 1,678,924
Accumulated deferred investment tax credits 203,704 211,822
Other liabilities and deferred credits 263,828 292,065
- ------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,100,310 2,182,811
- ------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTE 16)
- ------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $9,494,019 $8,401,406
- ------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
55
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------
YEARS ENDED DECEMBER 31
(IN THOUSANDS) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------------
OPERATING ACTIVITIES
<S> <C> <C> <C>
Net income $ 382,255 $ 399,238 $ 388,317
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 588,123 578,348 565,212
Harris Plant deferred costs 3,878 3,704 19,670
Deferred income taxes (32,495) (38,517) (66,546)
Investment tax credit (10,299) (10,206) (10,232)
Deferred fuel credit (39,052) (22,017) (24,969)
Net decrease in receivables, inventories, prepaid expenses
and other current assets (168,148) (62,351) (111,216)
Net increase in payables and accrued expenses 31,991 43,652 65,330
Other 75,867 2,330 59,191
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 832,120 894,181 884,757
- ---------------------------------------------------------------------------------------------------------------------------------
INVESTING ACTIVITIES
Gross property additions (689,054) (424,263) (322,205)
Nuclear fuel additions (75,641) (102,511) (61,509)
Contributions to nuclear decommissioning trust (30,825) (30,848) (30,726)
Contributions to retiree benefit trusts - - (21,096)
Net cash flow of company-owned life insurance program (6,542) (1,954) 138,508
Investments in non-utility activities (199,525) (103,543) (54,733)
- ---------------------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,001,587) (663,119) (351,761)
- ---------------------------------------------------------------------------------------------------------------------------------
FINANCING ACTIVITIES
Proceeds from issuance of long-term debt 400,970 6,255 199,075
Net increase (decrease) in short-term indebtedness 339,100 242,100 (166,324)
Net increase (decrease) in outstanding payments (117,643) 26,211 (71,744)
Retirement of long-term debt (113,335) (208,050) (103,410)
Redemption of preferred stock - - (85,850)
Purchase of Company common stock - - (23,418)
Dividends paid on common and preferred stock (296,671) (282,684) (277,840)
Other 6,169 (448) -
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 218,590 (216,616) (529,511)
- ---------------------------------------------------------------------------------------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 49,123 14,446 3,485
- ---------------------------------------------------------------------------------------------------------------------------------
INCREASE IN CASH FROM ACQUISITION (SEE NONCASH ACTIVITIES) 1,876 - -
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR 28,872 14,426 10,941
- ---------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 79,871 $ 28,872 $ 14,426
- ---------------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid during the year - interest $180,395 $ 179,526 $171,511
income taxes $284,535 $ 329,739 $289,693
</TABLE>
Noncash Activities
- ------------------
In July 1999, the Company purchased all outstanding shares of North Carolina
Natural Gas Corporation (NCNG). In conjunction with the purchase of NCNG, the
Company issued approximately $360 million in common stock.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
56
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED SCHEDULES OF CAPITALIZATION
- ----------------------------------------
DECEMBER 31
(DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
COMMON STOCK EQUITY
Common stock without par value, authorized 200,000,000 shares, issued and
outstanding 159,599,650 and 151,337,503 shares, respectively (Note 11) $1,746,249 $1,374,773
Unearned ESOP common stock (140,153) (152,979)
Capital stock issuance expense (794) (790)
Retained earnings (Note 8) 1,807,345 1,728,301
- -------------------------------------------------------------------------------------------------------------------------
Total Common Stock Equity $3,412,647 $2,949,305
- -------------------------------------------------------------------------------------------------------------------------
CUMULATIVE PREFERRED STOCK, WITHOUT PAR VALUE
(entitled to $100 a share plus accumulated dividends in the event of
liquidation; aggregate liquidation preference of $59,468; outstanding
shares are as of December 31, 1999)
- -------------------------------------------------------------------------------------------------------------------------
Preferred stock - redemption not required:
Authorized - 300,000 shares $5.00 Preferred Stock; 20,000,000 shares
Serial Preferred Stock
$5.00 Preferred - 237,259 shares outstanding (redemption price $110.00) $24,376 $24,376
4.20 Serial Preferred - 100,000 shares outstanding (redemption price
$102.00) 10,000 10,000
5.44 Serial Preferred - 250,000 shares outstanding (redemption price
$101.00) 25,000 25,000
- -------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock - redemption not required $59,376 $59,376
- -------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT (interest rates are as of December 31,
1999) First mortgage bonds:
6.125% due 2000 $150,000 $ 150,000
6.75% due 2002 100,000 100,000
5.875% and 7.875% due 2004 300,000 300,000
6.80% due 2007 200,000 200,000
6.875% to 8.625% due 2021-2023 500,000 500,000
First mortgage bonds - secured senior notes:
5.95% due 2009 400,000 -
First mortgage bonds - secured medium-term notes:
7.15% due 1999 - 50,000
First mortgage bonds - pollution control series:
6.30% to 6.90% due 2009-2014 93,530 93,530
4.19% and 4.20% due 2024 122,600 122,600
- -------------------------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 1,866,130 1,516,130
- -------------------------------------------------------------------------------------------------------------------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 4.50% to 5.40% due
2014-2017 442,000 442,000
Other pollution control obligations, 5.70% due 2019 55,640 55,640
Unsecured subordinated debentures, 8.55% due 2025 125,000 125,000
Commercial paper reclassified to long-term debt (Note 6) 362,600 488,000
Extendible notes reclassified to long-term debt (Note 6) 331,760 -
Miscellaneous notes 54,846 56,691
- -------------------------------------------------------------------------------------------------------------------------
Total Other Long-Term Debt 1,371,846 1,167,331
- -------------------------------------------------------------------------------------------------------------------------
Unamortized premium and discount, net (12,165) (15,875)
Current portion of long-term debt (197,250) (53,172)
- -------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net $3,028,561 $2,614,414
- -------------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,500,584 $5,623,095
- -------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
57
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
- --------------------------------------------
YEARS ENDED DECEMBER 31
(IN THOUSANDS EXCEPT PER SHARE DATA) 1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $1,728,301 $1,613,881 $1,503,658
Net income 382,255 399,238 388,317
Preferred stock dividends at stated rates (2,967) (2,967) (4,627)
Common stock dividends at annual per share rate of
$2.015, $1.955 and $1.895, respectively (300,244) (281,851) (272,011)
Other adjustments - - (1,456)
- ---------------------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $1,807,345 $1,728,301 $1,613,881
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
- -------------------------------------------------
(IN THOUSANDS EXCEPT PER SHARE DATA) FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1999
Operating revenues $762,902 $762,822 $1,025,746 $806,145
Operating income 199,408 157,371 308,963 174,801
Net income 92,212 63,159 147,854 79,030
Common stock data:
Basic and diluted earnings per common share .63 .43 .97 .51
Dividend paid per common share .50 .50 .50 .50
Price per share - high 47 7/8 45 43 1/4 36 13/16
low 37 5/8 36 5/8 34 1/8 29 1/4
- -------------------------------------------------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31, 1998
Operating revenues $761,495 $748,941 $964,291 $716,941
Operating income 194,266 159,593 354,536 139,155
Net income 86,571 65,469 186,024 61,174
Common stock data:
Basic earnings per common share .60 .45 1.29 .42
Diluted earnings per common share .60 .45 1.28 .42
Dividend paid per common share .485 .485 .485 .485
Price per share - high 45 3/4 45 1/2 46 5/8 49 1/16
low 40 5/8 39 1/2 39 15/16 45 1/16
- -------------------------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
</TABLE>
58
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Basis of Presentation
a. Organization
Carolina Power & Light Company (the Company) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North and South Carolina and the transmission,
distribution and sale of natural gas in portions of North Carolina.
b. Basis of Presentation
The consolidated financial statements are prepared in accordance with generally
accepted accounting principles. The accounting records of the Company are
maintained in accordance with uniform systems of accounts prescribed by the
Federal Energy Regulatory Commission (FERC), the North Carolina Utilities
Commission (NCUC) and the Public Service Commission of South Carolina (SCPSC).
Certain amounts for 1998 and 1997 have been reclassified to conform to the 1999
presentation, with no effect on previously reported net income or common stock
equity.
2. Florida Progress Corporation
The Company, Florida Progress Corporation (FPC), a Florida corporation, and CP&L
Energy, Inc. (CP&L Energy), a North Carolina corporation and wholly owned
subsidiary of the Company, formerly known as CP&L Holdings, Inc. entered into
an Amended and Restated Agreement and Plan of Share Exchange dated as of August
22, 1999, amended and restated as of March 3, 2000 (the "Amended Agreement").
Under the terms of the Agreement, all outstanding shares of common stock, no par
value, of FPC common stock would be acquired by CP&L Energy in a statutory share
exchange with an approximate value of $5.3 billion. Each share of FPC common
stock, at the election of the holder, will be exchanged for (i) $54.00 in cash
and one contingent value obligation (CVO), or (ii) the number of shares of
common stock, no par value, of CP&L Energy equal to the ratio determined by
dividing $54.00 by the average of the closing sale price per share of CP&L
Energy common stock (Final Stock Price) as reported on the New York Stock
Exchange composite tape for the twenty consecutive trading days ending with the
fifth trading day immediately preceding the closing date for the exchange, and
one CVO or (iii) a combination of cash and CP&L Energy common stock, and one
CVO; provided, however, that shareholder elections shall be subject to
allocation and proration to achieve a mix of the aggregate exchange
consideration that is 65% cash and 35% common stock. The number of shares of
CP&L Energy common stock that will be issued as stock consideration will vary if
the Final Stock Price is within a range of $37.13 to $45.39, but not outside
that range. Thus, the maximum number of shares of CP&L Energy common stock into
which one share of FPC common stock could be exchanged would be 1.4543, and the
minimum would be 1.1897. In addition, FPC shareholders will receive one
contingent value obligation for each share of FPC stock owned. Each contingent
value obligation will represent the right to receive contingent payments that
may be made by CP&L Energy based on certain cash flows that may be derived from
future operations of four synthetic fuel plants currently owned by FPC. In
conjunction with this proposed share exchange, CP&L Energy plans to issue debt
to fund the cash portion of the exchange.
The transaction has been approved by the Boards of Directors of FPC, the Company
and CP&L Energy. Consummation of the exchange is subject to the satisfaction or
waiver of certain closing conditions including, among others, the approval by
the shareholders of FPC and the approval of the issuance of CP&L Energy common
stock in the exchange by the shareholders of the Company or CP&L Energy; the
approval or regulatory review by the Federal Energy Regulatory Commission
(FERC), the SEC, the Nuclear Regulatory Commission (NRC), the North Carolina
Utilities Commission (NCUC), and certain other federal and state regulatory
bodies; the expiration or early termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976; and other customary
closing conditions. In addition, FPC's obligation to consummate the exchange is
conditioned upon the Final Stock Price being not less than $30.00. Both the
Company and FPC have agreed to certain undertakings and limitations regarding
the conduct of their respective businesses prior to the closing of the
transaction. The transaction is expected to be completed in the fall of 2000.
Either party may terminate the Agreement under certain circumstances, including
if the exchange has not been consummated on or before December 31, 2000;
provided that if certain conditions have not been satisfied on
59
<PAGE>
December 31, 2000, but all other conditions have been satisfied or waived then
such date shall be June 30, 2001. In the event that FPC or the Company terminate
the Agreement in certain limited circumstances, FPC would be required to pay the
Company a termination fee of $150 million, plus the Company's reasonable
out-of-pocket expenses which are not to exceed $25 million in the aggregate.
On January 31, 2000, applications were filed with the NRC seeking approval of
the change in control of FPC that will result from the share exchange. On
February 3, 2000, CP&L Energy filed an application with the NCUC for
authorization of the share exchange with FPC and the issuance of common stock in
connection with the transaction. On February 3, 2000, CP&L Energy and FPC filed
a joint application with the FERC requesting approval of the share exchange. The
Company cannot predict the outcome of these matters.
3. Summary of Significant Accounting Policies
a. Principles of Consolidation
The consolidated financial statements include the activities of the Company and
its majority-owned subsidiaries. These subsidiaries have invested in areas such
as natural gas transmission and distribution, communications technology,
energy-management services and merchant generation plants. Significant
intercompany balances and transactions have been eliminated in consolidation
except as permitted by Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," which provides
that profits on intercompany sales to regulated affiliates are not eliminated if
the sales price is reasonable and the future recovery of the sales price through
the rate-making process is probable.
b. Use of Estimates and Assumptions
In preparing financial statements that conform with generally accepted
accounting principles, management must make estimates and assumptions that
affect the reported amounts of assets and liabilities, disclosure of contingent
assets and liabilities at the date of the financial statements and amounts of
revenues and expenses reflected during the reporting period. Actual results
could differ from those estimates.
c. Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to utility plant. Maintenance and repairs of property, and
replacements and renewals of items determined to be less than units of property,
are charged to maintenance expense. The cost of units of property replaced,
renewed or retired, plus removal or disposal costs, less salvage, is charged to
accumulated depreciation. Generally, electric utility plant other than nuclear
fuel is subject to the lien of the Company's mortgage. Gas utility plant is not
currently subject to the lien of the Company's mortgage.
The balances of utility plant in service at December 31 are listed below (in
thousands), with a range of depreciable lives for each:
1999 1998
----------- -----------
Electric
Production plant (7-33 years) $6,413,121 $6,295,252
Transmission plant (30-75 years) 1,018,114 986,609
Distribution plant (12-50 years) 2,676,881 2,469,613
General plant and other (8-75 years) 525,707 529,164
----------- -----------
Total electric utility plant $10,633,823 $10,280,638
Gas plant (10-40 years) 354,773 -
----------- -----------
Utility plant in service $10,988,596 $10,280,638
=========== ===========
As prescribed in regulatory uniform systems of accounts, an allowance for the
cost of borrowed and equity funds used to finance utility plant construction
(AFUDC) is charged to the cost of plant. Regulatory authorities consider AFUDC
an
60
<PAGE>
appropriate charge for inclusion in the Company's utility rates to customers
over the service life of the property. The equity funds portion of AFUDC is
credited to other income and the borrowed funds portion is credited to interest
charges. The composite AFUDC rate for electric utility plant was 6.4% in 1999
and 5.6% in both 1998 and 1997. The composite AFUDC rate for gas utility plant
was 10.09% in 1999.
d. Diversified Business Property
The following is a summary of diversified business property (in thousands):
1999 1998
--------- ---------
Property, plant and equipment $ 195,892 $27,422
Construction work in progress 65,848 43,619
Accumulated depreciation (21,758) (5,027)
--------- ---------
Diversified business property, net $ 239,982 $66,014
========= =========
Diversified business property is stated at cost. Depreciation is computed on a
straight-line basis using estimated useful lives of the assets, ranging from 3
to 20 years.
e. Depreciation and Amortization
For financial reporting purposes, depreciation of utility plant other than
nuclear fuel is computed on the straight-line method based on the estimated
remaining useful life of the property, adjusted for estimated net salvage.
Depreciation provisions, including decommissioning costs (see Note 3f), as a
percent of average depreciable property other than nuclear fuel, were
approximately 3.9% in 1999, 1998 and 1997. Depreciation provisions totaled
$409.6 million, $394.4 million and $382.1 million in 1999, 1998 and 1997,
respectively.
Depreciation and amortization expense also includes amortization of deferred
operation and maintenance expenses associated with Hurricane Fran, which struck
significant portions of the Company's service territory in September 1996. In
1996, the NCUC authorized the Company to defer these expenses (approximately $40
million) with amortization over a 40-month period, which expired in December
1999.
Pursuant to authorizations from the NCUC and the SCPSC, the Company accelerated
the amortization of certain regulatory assets over a three-year period beginning
January 1997 and expiring December 1999. The accelerated amortization of these
regulatory assets resulted in additional depreciation and amortization expenses
of approximately $68 million in each year of the three-year period. Depreciation
and amortization expense also includes amortization of plant abandonment costs
(see Note 9c).
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE), is computed primarily on the
unit-of-production method and charged to fuel expense. Costs related to
obligations to the DOE for the decommissioning and decontamination of enrichment
facilities are also charged to fuel expense.
Goodwill, the excess of purchase price over fair value of net assets of
businesses acquired, is being amortized on a straight-line basis over periods
ranging from 10 to 40 years. Accumulated amortization was $11.5 million and $4.7
million at December 31, 1999 and 1998, respectively.
f. Nuclear Decommissioning
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 include 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
61
<PAGE>
upon in applicable rate agreements. Decommissioning cost provisions, which are
included in depreciation and amortization expense, were $33.3 million in 1999
and 1998 and $33.2 million in 1997.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $568.0 million and $496.3 million at December 31, 1999 and
1998, respectively. These costs include amounts retained internally and amounts
funded in an external decommissioning trust. The balance of the nuclear
decommissioning trust was $379.9 million and $310.7 million at December 31, 1999
and 1998, 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.
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. 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 North
Carolina Eastern Municipal Power Agency (Power Agency), which holds an undivided
ownership interest in the Brunswick and Harris nuclear generating facilities.
Operating licenses for the Company's nuclear units expire in the year 2010 for
Robinson Unit No. 2, 2016 for Brunswick Unit No. 1, 2014 for Brunswick Unit No.
2 and 2026 for the Harris Plant.
The Financial Accounting Standards Board (FASB) 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 was issued during the first quarter of 2000. It is uncertain what
effects it may ultimately have on the Company's accounting for nuclear
decommissioning and other retirement costs.
g. Other Policies
The Company recognizes utility revenues as service is rendered to customers.
Fuel expense includes fuel costs or recoveries that are deferred through fuel
clauses established by the Company's regulators. These clauses allow the Company
to recover fuel costs and the fuel component of purchased power costs through
the fuel component of customer rates. The Company is also allowed to recover the
costs of gas purchased for resale through customer rates.
Other property and investments are stated principally at cost. The Company
maintains an allowance for doubtful accounts receivable, which totaled
approximately $16.8 million and $14.2 million at December 31, 1999 and 1998,
respectively. Inventory, which includes fuel, materials and supplies, and gas in
storage, is carried at average cost. Long-term debt premiums, discounts and
issuance expenses are amortized over the life of the related debt using the
straight-line method. Any expenses or call premiums associated with the
reacquisition of debt obligations are amortized over the remaining life of the
original debt using the straight-line method, except that the balance existing
at December 31, 1996 was amortized on a three-year accelerated basis (see Note
9a). The Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents.
h. New Accounting Standard
The FASB has delayed the effective date for SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The delay, published as SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of
the Effective Date of FASB Statement No. 133," changes the effective date to
fiscal years beginning after June 15, 2000. The Company expects to determine any
effects of SFAS No. 133 by mid-2000.
62
<PAGE>
4. NCNG Acquisition
On July 15, 1999, the Company completed the acquisition of North Carolina
Natural Gas Corporation (NCNG) for an aggregate purchase price of approximately
$364 million. Each outstanding share of NCNG common stock was converted into the
right to receive 0.8054 shares of Company common stock, resulting in the
issuance of approximately 8.3 million shares. The acquisition has been accounted
for as a purchase and, accordingly, the operating results of NCNG have been
included in the Company's consolidated financial statements since the date of
acquisition. The excess of the aggregate purchase price over the fair value of
net assets acquired, approximately $240 million, has been recorded as goodwill
of the acquired business and is being amortized primarily over a period of 40
years.
NCNG, operating as a wholly owned subsidiary of the Company, is engaged in the
transmission and distribution of natural gas. These gas services are provided
under regulated rates to approximately 178,000 customers in eastern and south
central North Carolina.
In conjunction with the acquisition, the Company and NCNG signed a joint
stipulation agreement with the Public Staff of the NCUC in which the Company
agreed to cap base retail electric rates, exclusive of fuel costs, with limited
exceptions, through December 2004, and NCNG agreed to cap margin rates for gas
sales and transportation services, with limited exceptions, through November 1,
2003. Management is of the opinion that this agreement will not have a material
effect on the consolidated results of operations or financial position of the
Company.
The acquisition of NCNG was not deemed significant to the Company's consolidated
results of operations; therefore, proforma financial information has been
omitted.
5. Financial Information by Business Segment
The Company provides services through the following business segments: electric,
natural gas and other.
The electric segment generates, transmits, distributes and sells electric energy
in North and South Carolina. Electric operations are subject to the rules and
regulations of the FERC, the NCUC and the SCPSC.
The natural gas segment transmits, distributes and sells gas in portions of
North Carolina. Gas operations are subject to the rules and regulations of the
NCUC.
The other segments primarily include telecommunication services, energy
management services, propane and miscellaneous non-regulated activities.
For reportable segments presented in the accompanying table, segment earnings
(losses) before taxes include intersegment sales accounted for at prices
representative of unaffiliated party transactions.
63
<PAGE>
<TABLE>
<CAPTION>
Natural Segment
(in thousands) Electric Gas Other Elimination Totals
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
For the year ended 12/31/99
Revenues
Unaffiliated $ 3,138,846 $ 97,886 $ 119,866 $ - $ 3,356,598
Intersegment - 1,017 30,618 (30,618) 1,017
--------------------------------------------------------------------------------
Total Revenues $ 3,138,846 $ 98,903 $ 150,484 $ (30,618) $ 3,357,615
Depreciation and Amortization $ 486,502 $ 9,168 $ 16,804 - $ 512,474
Interest Expense $ 183,098 $ 3,225 $ 1,403 $ (6,859) 180,867
Earnings(Losses) Before Taxes $ 715,359 $ 4,360 $ (72,759) $ (6,284) $ 640,676
Total Segment Assets $ 8,705,547 $ 550,132 $ 370,805 $ (132,465) $ 9,494,019
Capital and Investment
Expenditures $ 671,401 $ 24,047 $ 193,131 $ - $ 888,579
=====================================================================================================================
Natural Segment
Electric Gas Other Elimination Totals
- ---------------------------------------------------------------------------------------------------------------------
For the year ended 12/31/98
Revenues
Unaffiliated $ 3,130,045 $ - $ 61,623 $ - $ 3,191,668
Intersegment - - 21,887 (21,887) -
--------------------------------------------------------------------------------
Total Revenues $ 3,130,045 $ - $ 83,510 $ (21,887) $ 3,191,668
Depreciation and Amortization $ 487,097 $ - $ 2,951 - $ 490,048
Interest Expense $ 174,433 $ - $ 149 $ (197) $ 174,385
Earnings(Losses) Before Taxes $ 737,999 $ - $ (70,325) $ (10,942) $ 656,732
Total Segment Assets $ 8,211,372 $ - $ 189,175 $ 859 $ 8,401,406
Capital and Investment
Expenditures $ 463,729 $ - $ 64,077 $ - $ 527,806
=====================================================================================================================
Natural Segment
Electric Gas Other Elimination Totals
- ---------------------------------------------------------------------------------------------------------------------
For the year ended 12/31/97
Revenues
Unaffiliated $ 3,024,089 $ - $ 12,498 $ - $ 3,036,587
Intersegment - - - - -
--------------------------------------------------------------------------------
Total Revenues $ 3,024,089 $ - $ 12,498 $ - $ 3,036,587
Depreciation and Amortization $ 481,650 $ - $ 228 $ - $ 481,878
Interest Expense $ 177,874 $ - $ 58 $ (586) $ 177,346
Earnings(Losses) Before Taxes $ 658,840 $ - $ (25,278) $ (11,529) $ 622,033
Total Segment Assets $ 8,138,282 $ - $ 89,694 $ (7,248) $ 8,220,728
Capital and Investment
Expenditures $ 372,512 $ - $ 4,426 $ - $ 376,938
=====================================================================================================================
</TABLE>
64
<PAGE>
RECONCILIATION OF FINANCIAL INFORMATION BY BUSINESS SEGMENT TO CONSOLIDATED
FINANCIAL STATEMENTS:
DEPRECIATION AND AMORTIZATION
(in thousands)
<TABLE>
<CAPTION>
SEGMENT CONSOLIDATED
PERIOD TOTALS ADJUSTMENTS TOTALS
---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
For the year ended 12/31/99 $ 512,474 $ (16,804) $ 495,670
For the year ended 12/31/98 $ 490,048 $ (2,951) $ 487,097
For the year ended 12/31/97 $ 481,878 $ (228) $ 481,650
INTEREST EXPENSE
(in thousands)
SEGMENT CONSOLIDATED
PERIOD TOTALS ADJUSTMENTS TOTALS
----------------------------------------------------------------------------
For the year ended 12/31/99 $180,867 $ (1,403) $ 179,464
For the year ended 12/31/98 $174,385 $ (149) $ 174,236
For the year ended 12/31/97 $177,346 $ (58) $ 177,288
</TABLE>
Adjustments to depreciation and amortization and interest expense consist of
expenses related to the other segments that are included in diversified business
operating expenses on a consolidated basis.
6. Revolving Credit Facilities
As of December 31, 1999, the Company's revolving credit facilities totaled $750
million, all of which are long-term agreements. 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, pollution control
revenue refunding bonds (pollution control bonds) and other short-term
indebtedness on a long-term basis, and as supported by its long-term revolving
credit facilities, the Company included in long-term debt commercial paper,
pollution control bonds, and other short-term indebtedness outstanding of
approximately $363 million, $56 million and $331 million, respectively, as of
December 31, 1999. Commercial paper and pollution control bonds outstanding of
approximately $488 million and $56 million, respectively, were reclassified as
long-term debt as of December 31, 1998. For commercial paper, pollution control
bonds and other short-term indebtedness, weighted-average interest rates were
6.07%, 3.32% and 5.88%, respectively, at December 31, 1999. The weighted-average
interest rates for commercial paper and pollution control bonds were 5.22% and
3.67%, respectively, as of December 31, 1998.
7. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, commercial paper and
extendible notes approximate fair value due to the short maturities of these
instruments. At December 31, 1999 and 1998, there were miscellaneous investments
with carrying amounts of approximately $60 million and $66 million,
respectively, included in miscellaneous other property and investments. The
carrying amount of these investments approximates fair value due to the short
maturity of certain instruments and certain instruments are presented at fair
value. The carrying amount of the Company's long-term debt was $2.54 billion and
$2.20 billion at December 31, 1999 and 1998, respectively. The estimated fair
value of this debt, as obtained from quoted market prices for the same or
similar issues, was $2.47 billion and $2.31 billion at December 31, 1999 and
1998, respectively.
External funds have been established, as required by the NRC, as a mechanism to
fund certain costs of nuclear decommissioning (see Note 3f). These nuclear
decommissioning trust funds are invested in stocks, bonds and cash equivalents.
Nuclear decommissioning trust funds are presented at amounts that approximate
fair value. Fair value is obtained from quoted market prices for the same or
similar investments.
65
<PAGE>
8. Capitalization
As of December 31, 1999, the Company had 21,594,424 shares of authorized but
unissued common stock reserved and available for issuance, primarily to satisfy
the requirements of the Company's stock plans. The Company intends, however, to
meet the requirements of these stock plans with issued and outstanding shares
presently held by the Trustee of the Stock Purchase-Savings Plan or with open
market purchases of common stock shares, as appropriate. During 1999, the
Company issued stock in conjunction with the NCNG acquisition as discussed in
Note 4. In addition, CP&L Energy's Board of Directors has authorized the
issuance of shares in conjunction with the planned share exchange with FPC (see
Note 2).
The Company's mortgage, as supplemented, and charter contain provisions limiting
the use of retained earnings for the payment of dividends under certain
circumstances. As of December 31, 1999, there were no significant restrictions
on the use of retained earnings.
As of December 31, 1999, long-term debt maturities for the years 2000, 2002,
2003 and 2004 amounted to $197 million, $100 million, $7 million and $300
million, respectively, excluding commercial paper, pollution control bonds and
other short-term indebtedness reclassified as long-term debt. There are no
long-term debt maturities in 2001.
9. Regulatory Matters
a. Regulatory Assets
As a regulated entity, the Company is subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." See Note 16c for
additional discussion of SFAS No. 71. Accordingly, the Company records certain
assets resulting from the effects of the ratemaking process, which would not be
recorded under generally accepted accounting principles for unregulated
entities. At December 31, 1999 and 1998, the balances of the Company's
regulatory assets were as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Income taxes recoverable through future rates* $229,008 $277,894
Harris Plant deferred costs 56,142 60,021
Abandonment costs* 1,675 16,083
Loss on reacquired debt (included in unamortized debt expense)* 4,719 20,953
Deferred fuel 81,699 42,647
Items included in other assets and deferred debits:
Deferred DOE enrichment facilities-related costs 40,897 45,917
Deferred hurricane-related costs - 11,927
Emission allowance carrying costs* - 4,144
----------- ----------
Total $414,140 $479,586
=========== ==========
</TABLE>
* ALL OR CERTAIN PORTIONS OF THESE REGULATORY ASSETS HAVE BEEN SUBJECT TO
ACCELERATED AMORTIZATION (SEE NOTE 3E).
b. Retail Rate Matters
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 began immediately after the 1999 expiration of the accelerated
amortization of certain regulatory assets (see Note 3e). Pursuant to the orders,
the Company's depreciation expense for nuclear generating assets will increase
by a minimum of $106 million to a maximum of $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.
66
<PAGE>
In conjunction with the acquisition with NCNG, the Company signed a joint
stipulation agreement with the Public Staff of the NCUC in which the Company
agreed to cap base retail electric rates and margin rates for gas sales and
transportation services (see Note 4).
c. Plant-Related Deferred Costs
In the 1988 rate orders, the Company was ordered to remove from rate base and
treat as abandoned plant certain costs related to the Harris Plant. Abandoned
plant amortization related to the 1988 rate orders was completed in 1998 for the
wholesale and North Carolina retail jurisdictions and in 1999 for the South
Carolina retail jurisdiction.
Amortization of plant abandonment costs is included in depreciation and
amortization expense and totaled $15.0 million, $24.2 million and $30.8 million
in 1999, 1998 and 1997, respectively. The unamortized balances of plant
abandonment costs are reported at the present value of future recoveries of
these costs. The associated accretion of the present value was $0.6 million,
$1.7 million and $3.5 million in 1999, 1998 and 1997, respectively, and is
reported in other, net.
10. Risk Management Activities and Derivatives Transactions
The Company uses a variety of instruments, including swaps, options and forward
contracts, to manage exposure to fluctuations in commodity prices and interest
rates. Such instruments contain credit risk if the counterparty fails to perform
under the contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. Potential nonperformance by counterparties is not expected to
have a material effect on the consolidated financial position or consolidated
results of operations of the Company.
a. Commodity Instruments - Non-Trading
At December 31, 1999, the Company held several forward contracts that reduced
the exposure to market fluctuations relative to the price and delivery of
electricity products. Selling electricity forward contracts can reduce price
risk on the Company's available but unsold generation. These contracts provide
for physical delivery of the related commodity, and the financial effects of
such contracts are recorded in the month of settlement.
The Company from time to time enters into electricity option contracts to ensure
a reliable source of capacity to meet its customers' electricity requirements or
to limit risk associated with electricity prices. It is management's intent to
take or make physical delivery under such contracts. Premiums paid or received
are deferred and charged to income during the option period. The Company's
maximum exposure associated with purchased options is limited to premiums paid.
Option sales are made only if the Company can, with reasonable certainty, make
physical delivery from Company-owned resources.
b. Commodity Instruments - Trading
The Company from time to time engages in the trading of electricity commodity
instruments and, therefore, experiences net open positions. The Company manages
open positions with strict policies which limit its exposure to market risk and
require daily reporting to management of potential financial exposures. When
such instruments are entered into for trading purposes, the instruments are
carried on the balance sheet at fair value, with changes in fair value
recognized in earnings. Net losses related to trading electricity commodity
instruments were not material during 1999 and 1998, and there was no trading
activity in 1997.
c. Other Financial Instruments
The Company may from time to time enter into derivative instruments to hedge
interest rate risk or equity securities risk. At December 31, 1998, the Company
had an outstanding interest rate lock with a fair value asset position of
approximately $1 million. The interest rate lock was settled during 1999 in
conjunction with the issuance of long-term debt, and the Company received
approximately $9.7 million, which will reduce interest expense over the 10-year
debt term.
67
<PAGE>
11. Stock-Based Compensation Plans
a. Employee Stock Ownership Plan
The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which
substantially all full-time employees and certain part-time employees are
eligible. The SPSP, which has Company matching and incentive goal features,
encourages systematic savings by employees and provides a method of acquiring
Company common stock and other diverse investments. The SPSP, as amended in
1989, is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition
loans to acquire Company common stock to satisfy SPSP common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the SPSP. Common stock acquired with the proceeds of an ESOP
loan is held by the SPSP Trustee in a suspense account. The common stock is
released from the suspense account and made available for allocation to
participants as the ESOP loan is repaid. Such allocations are used to partially
meet common stock needs related to Company matching and incentive contributions
and/or reinvested dividends. All or a portion of the dividends paid on ESOP
suspense shares and on ESOP shares allocated to participants may be used to
repay ESOP acquisition loans. To the extent used to repay such loans, the
dividends are deductible for income tax purposes.
There were 6,365,364 and 6,953,612 ESOP suspense shares at December 31, 1999 and
1998, respectively, with a fair value of $193.7 million and $327.3 million,
respectively. ESOP shares allocated to plan participants totaled 12,966,269 and
12,416,040 at December 31, 1999 and 1998, respectively. The Company's matching
and incentive goal compensation cost under the SPSP is determined based on
matching percentages and incentive goal attainment as defined in the plan. Such
compensation cost is allocated to participants' accounts in the form of Company
common stock, with the number of shares determined by dividing compensation cost
by the common stock market value. The Company currently meets common stock share
needs with open market purchases and with shares released from the ESOP suspense
account. Total matching and incentive compensation cost recorded in 1999, 1998
and 1997 was approximately $17.3 million, $15.3 million and $13.4 million,
respectively, substantially all of which was met with shares released from the
suspense account. The Company has a long-term note receivable from the SPSP
Trustee related to the purchase of common stock from the Company in 1989. The
balance of the note receivable from the SPSP Trustee is included in the
determination of unearned ESOP common stock, which reduces common stock equity.
ESOP shares that have not been committed to be released to participants'
accounts are not considered outstanding for the determination of earnings per
common share. Interest income on the note receivable and dividends on
unallocated ESOP shares are not recognized for financial statement purposes.
b. Other Stock-Based Compensation Plans
The Company has compensation plans for officers and key employees of the Company
that are stock-based in whole or in part. The two primary active stock-based
compensation programs are the Performance Share Sub-Plan (PSSP) and the
Restricted Stock Awards program (RSA), both of which were established pursuant
to the Company's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares that vest over a three-year consecutive period. Each
performance share has a value that is equal to, and changes with, the value of a
share of the Company's common stock, and dividend equivalents are accrued on,
and reinvested in, the performance shares. For grant years prior to 1999, the
sole performance measure under the PSSP is the Company's total shareholder
return as compared to that of a peer group of utilities. Beginning in the 1999
grant year, the Company added an additional performance measure, earnings before
interest, income taxes, depreciation and amortization, which is also compared to
a peer group of utilities. Compensation expense is recognized over the vesting
period based on the expected ultimate cash payout. Compensation expense is
reduced by any forfeitures.
The RSA, which began in 1998, allows the Company to grant shares of restricted
common stock to key employees of the Company. The restricted shares vest on a
graded vesting schedule over a minimum of three years. Compensation expense,
which is based on the fair value of common stock at the grant date, is
recognized over the applicable vesting period, with corresponding increases in
common stock equity. Compensation expense is reduced by any forfeitures.
Restricted shares are not included as shares outstanding in the basic earnings
per share calculation until the shares are no longer forfeitable. Changes in
restricted stock shares outstanding were:
68
<PAGE>
<TABLE>
<CAPTION>
1999 1998
---- ----
<S> <C> <C>
Beginning balance 265,300 -
Granted 66,600 274,800
Forfeited - (9,500)
-------------- ---------------
Ending balance 331,900 265,300
============== ===============
</TABLE>
The total amount expensed for other stock-based compensation plans was $2.2
million, $1.3 million and $4.3 million in 1999, 1998 and 1997, respectively.
12. Postretirement Benefit Plans
The Company has a noncontributory defined benefit retirement (pension) plan for
substantially all full-time employees.
The components of net periodic pension cost are (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Actual return on plan assets $(127,167) $ (87,382) $(110,346)
Variance from expected return,
Deferred 52,043 17,462 57,368
--------- --------- ---------
Expected return on plan assets $ (75,124) $ (69,920) $ (52,978)
Service cost 20,467 18,357 18,643
Interest cost 46,846 45,877 42,468
Amortization of transition obligation 106 106 106
Amortization of prior service cost (benefit) (1,314) (158) 967
Amortization of actuarial gain (3,932) (6,440) (36)
--------- --------- ---------
Net periodic pension cost (benefit) $ (12,951) $ (12,178) $ 9,170
========= ========= =========
</TABLE>
Prior service costs and benefits are amortized on a straight-line basis over the
average remaining service period of active participants. Actuarial gains and
losses in excess of 10% of the greater of the pension obligation or the
market-related value of assets are amortized over the average remaining service
period of active participants.
69
<PAGE>
Reconciliations of the changes in the plan's benefit obligations and the plan's
funded status are (in thousands):
1999 1998
--------- ---------
Pension obligation
Pension obligation at January 1 $ 678,210 $ 598,160
Interest cost 46,846 45,877
Service cost 20,467 18,357
Benefit payments (41,585) (25,466)
Actuarial loss (gain) (50,120) 77,785
Plan amendments 5,546 (36,503)
Acquisition of NCNG 28,760 --
--------- ---------
Pension obligation at December 31 $ 688,124 $ 678,210
Fair value of plan assets at December 31 947,143 830,213
--------- ---------
Funded status $ 259,019 $ 152,003
Unrecognized transition obligation 582 688
Unrecognized prior service benefit (18,175) (25,429)
Unrecognized actuarial gain (245,343) (145,657)
--------- ---------
Accrued pension obligation at December 31 $ (3,917) $ (18,395)
========= =========
Reconciliations of the fair value of pension plan assets are (in thousands):
1999 1998
---------- ---------
Fair value of plan assets at January 1 $ 830,213 $ 768,297
Actual return on plan assets 127,167 87,382
Benefit payments (41,585) (25,466)
Acquisition of NCNG 31,348 -
---------- ---------
Fair value of plan assets at December 31 $ 947,143 $ 830,213
========= =========
The weighted-average discount rate used to measure the pension obligation was
7.5% in 1999 and 7.0% in 1998. The assumed rate of increase in future
compensation used to measure the pension obligation was 4.20% in 1999, 1998 and
1997. The expected long-term rate of return on pension plan assets used in
determining the net periodic pension cost was 9.25% in 1999, 1998 and 1997.
In addition to pension benefits, the Company provides contributory
postretirement benefits (OPEB), including certain health care and life insurance
benefits, for substantially all retired employees.
70
<PAGE>
The components of net periodic OPEB cost are (in thousands):
1999 1998 1997
-------- -------- --------
Actual return on plan assets $ (5,931) $ (3,877) $ (4,628)
Variance from expected return,
Deferred 2,553 785 2,186
-------- -------- --------
Expected return on plan assets $ (3,378) $ (3,092) $ (2,442)
Service cost 7,936 7,182 7,988
Interest cost 13,914 13,402 11,065
Amortization of transition obligation 5,760 5,641 5,889
Amortization of actuarial gain (1) (549) --
-------- -------- --------
Net periodic OPEB cost $ 24,231 $ 22,584 $ 22,500
======== ======== ========
Actuarial gains and losses in excess of 10% of the greater of the OPEB
obligation or the market-related value of assets are amortized over the average
remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the plan's
funded status are (in thousands):
1999 1998
--------- ---------
OPEB obligation
OPEB obligation at January 1 $ 196,846 $ 181,324
Interest cost 13,914 13,402
Service cost 7,936 7,182
Benefit payments (5,769) (4,774)
Actuarial loss (gain) (7,307) 3,428
Plan amendment 1,062 (3,716)
Acquisition of NCNG 6,806 --
--------- ---------
OPEB obligation at December 31 $ 213,488 $ 196,846
Fair value of plan assets at December 31 43,235 37,304
--------- ---------
Funded status $(170,253) $(159,542)
Unrecognized transition obligation 76,593 78,978
Unrecognized prior service cost 1,062 --
Unrecognized actuarial gain (17,261) (7,314)
--------- ---------
Accrued OPEB obligation at December 31 $(109,859) $ (87,878)
========= =========
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<PAGE>
Reconciliations of the fair value of OPEB plan assets are (in thousands):
1999 1998
--------- ---------
Fair value of plan assets at January 1 $37,304 $33,427
Actual return on plan assets 5,931 3,877
--------- ---------
Fair value of plan assets at December 31 $43,235 $37,304
========= =========
The assumptions used to measure the OPEB obligation are:
1999 1998
--------- ---------
Weighted-average discount rate 7.50% 7.00%
Initial medical cost trend rate for
pre-Medicare benefits 7.50% 6.60%
Initial medical cost trend rate for
post-Medicare benefits 7.25% 6.40%
Ultimate medical cost trend rate 5.00% 4.50%
Year ultimate medical cost trend rate is achieved 2006 2006
The expected long-term rate of return on plan assets used in determining the net
periodic OPEB cost was 9.25% in 1999, 1998 and 1997. The medical cost trend
rates were assumed to decrease gradually from the initial rates to the ultimate
rates. Assuming a 1% increase in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for 1999
would increase by $4.0 million, and the OPEB obligation at December 31, 1999,
would increase by $29.3 million. Assuming a 1% decrease in the medical cost
trend rates, the aggregate of the service and interest cost components of the
net periodic OPEB cost for 1999 would decrease by $3.1 million and the OPEB
obligation at December 31, 1999, would decrease by $23.6 million.
During 1999, the Company completed the acquisition of NCNG (see Note 4). NCNG's
pension and OPEB liabilities, assets and net periodic costs are reflected in the
above information as appropriate. Effective January 1, 2000, NCNG's benefit
plans were merged with those of the Company.
13. Earnings Per Common Share
Restricted stock awards and contingently issuable shares had a dilutive effect
on earnings per share for 1999 and increased the weighted-average number of
common shares outstanding for dilutive purposes by 290,474, 250,660 and 11,893
for 1999, 1998 and 1997, respectively. The weighted-average number of common
shares outstanding for dilutive purposes was 148.6 million, 144.2 million and
143.7 million for 1999, 1998 and 1997, respectively.
14. Income Taxes
Deferred income taxes are provided for temporary differences between book and
tax bases of assets and liabilities. Investment tax credits related to operating
income are amortized over the service life of the related property.
72
<PAGE>
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
1999 1998
---------- ----------
Accelerated depreciation and property
cost differences $1,583,610 $1,632,119
Deferred costs, net 70,478 66,757
Miscellaneous other temporary
differences, net 26,403 10,885
---------- ----------
Net accumulated deferred income
tax liability $1,680,491 $1,709,761
========== ==========
Total deferred income tax liabilities were $2.20 billion and $2.21 billion at
December 31, 1999 and 1998, respectively. Total deferred income tax assets were
$519 million and $501 million at December 31, 1999 and 1998, respectively. The
net of deferred income tax liabilities and deferred income tax assets is
included on the Consolidated Balance Sheets under the captions other current
liabilities and accumulated deferred income taxes.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
1999 1998 1997
---- ---- ----
Effective income tax rate 40.3% 39.2% 37.5%
State income taxes, net of federal
income tax benefit (4.6) (4.7) (4.9)
Investment tax credit amortization 1.6 1.5 1.7
Other differences, net (2.3) (1.0) 0.7
---- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
==== ==== ====
The provisions for income tax expense are comprised of (in thousands):
1999 1998 1997
--------- --------- ---------
Income tax expense (credit)
Current - federal $ 253,140 $ 254,400 $ 258,050
state 48,075 51,817 56,747
Deferred - federal (30,011) (34,842) (61,384)
state (2,484) (3,675) (9,465)
Investment tax credit (10,299) (10,206) (10,232)
--------- --------- ---------
Total income tax expense $ 258,421 $ 257,494 $ 233,716
========= ========= =========
15. Joint Ownership of Generating Facilities
Power Agency holds undivided ownership interests in certain generating
facilities of the Company. The Company and Power Agency are entitled to shares
of the generating capability and output of each unit equal to their respective
ownership interests. Each also pays its ownership share of additional
construction costs, fuel inventory purchases and
73
<PAGE>
operating expenses. The Company's share of expenses for the jointly owned units
is included in the appropriate expense category.
The Company's ownership interest in the jointly owned generating facilities is
listed below with related information as of December 31, 1999 (dollars in
thousands):
<TABLE>
<CAPTION>
Company
Megawatt Ownership Accumulated Under
Facility Capability Interest Plant Investment Depreciation Construction
- ------------------------ ----------------- ------------- ------------------ --------------- --------------
<S> <C> <C> <C> <C> <C>
Mayo Plant 745 83.83% $ 451,640 $ 205,278 $10,471
Harris Plant 860 83.83% 3,002,812 910,144 67,088
Brunswick Plant 1,631 81.67% 1,426,398 1,065,561 3,163
Roxboro Unit No. 4 700 87.06% 240,649 116,237 19,175
</TABLE>
In the table above, plant investment and accumulated depreciation, which
includes accumulated nuclear decommissioning, are not reduced by the regulatory
disallowances related to the Harris Plant.
16. Commitments and Contingencies
a. Purchased Power
Pursuant to the terms of the 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. In 1993, the Company and Power Agency entered into an agreement to
restructure portions of their contracts covering power supplies and interests in
jointly owned units. Under the terms of the 1993 agreement, the Company
increased the amount of capacity and energy purchased from Power Agency's
ownership interest in the Harris Plant, and the buyback period was extended six
years through 2007. The estimated minimum annual payments for these purchases,
which reflect capital-related capacity costs, total approximately $26 million.
These contractual purchases, including purchases from the Mayo Plant that ended
in 1997, totaled $36.5 million, $34.4 million and $36.2 million for 1999, 1998
and 1997, respectively. In 1987, the NCUC ordered the Company to reflect the
recovery of the capacity portion of these costs on a levelized basis over the
original 15-year buyback period, thereby deferring for future recovery the
difference between such costs and amounts collected through rates. In 1988, the
SCPSC ordered similar treatment, but with a 10-year levelization period. At
December 31, 1999 and 1998, the Company had deferred purchased capacity costs,
including carrying costs accrued on the deferred balances, of $56.1 million and
$60.0 million, respectively. Increased purchases (which are not being deferred
for future recovery) resulting from the 1993 agreement with Power Agency were
approximately $23 million, $19 million and $17 million for 1999, 1998 and 1997,
respectively.
During 1999, the Company had two long-term agreements for the purchase of power
and related transmission services from other utilities. The first agreement
provides for the purchase of 250 megawatts of capacity through 2009 from Indiana
Michigan Power Company's Rockport Unit No. 2 (Rockport). The second agreement,
which expired mid-1999, was with Duke Energy for the purchase of 400 megawatts
of firm capacity. The estimated minimum annual payment for power purchases under
the Rockport agreement is approximately $31 million, representing
capital-related capacity costs. Total purchases (including transmission use
charges) under the Rockport agreement amounted to $59.5 million, $59.3 million
and $61.9 million for 1999, 1998 and 1997, respectively. Total purchases
(including transmission use charges) under the agreement with Duke Energy
amounted to $33.8 million, $75.5 million and $69.5 million for 1999, 1998 and
1997, respectively.
b. Insurance
The Company is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, the Company
is insured for $500 million at each of its nuclear plants. In addition to
primary coverage, NEIL also provides decontamination, premature decommissioning
and excess property insurance with limits of $1.4 billion on the Brunswick
Plant, $2 billion on the Harris Plant and $800 million on the Robinson Plant.
74
<PAGE>
Insurance coverage against incremental costs of replacement power resulting from
prolonged accidental outages at nuclear generating units is also provided
through membership in NEIL. The Company is insured thereunder, following a
twelve week deductible period, for 52 weeks in weekly amounts of $1.95 million
at Brunswick Unit No. 1, $1.93 million at Brunswick Unit No. 2, $2.0 million at
the Harris Plant and $1.7 million at Robinson Unit No. 2. An additional 104
weeks of coverage is provided at 80% of the above weekly amounts. For the
current policy period, the Company is subject to retrospective premium
assessments of up to approximately $12.5 million with respect to the primary
coverage, $13.7 million with respect to the decontamination, decommissioning and
excess property coverage and $5.0 million for the incremental replacement power
costs coverage in the event covered expenses at insured facilities exceed
premiums, reserves, reinsurance and other NEIL resources. These resources as of
December 31, 1999 totaled approximately $5.0 billion. Pursuant to regulations of
the NRC, the Company's property damage insurance policies provide that all
proceeds from such insurance be applied, first, to place the plant in a safe and
stable condition after an accident and, second, to decontamination costs, before
any proceeds can be used for decommissioning, plant repair or restoration. The
Company is responsible to the extent losses may exceed limits of the coverage
described above. Power Agency would be responsible for its ownership share of
such losses and for certain retrospective premium assessments on jointly owned
nuclear units.
The Company is insured against public liability for a nuclear incident up to
$9.7 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.
c. Applicability of SFAS No. 71
The Company's ability to continue to meet the criteria for application of SFAS
No. 71 (see Note 9a) may be affected in the future by competitive forces and
restructuring in the electric utility industry. In the event that SFAS No. 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 SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of."
d. Claims and Uncertainties
1. The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under federal and state laws.
There are several manufactured gas plant (MGP) sites to which both the electric
utility and the gas utility have some connection. In this regard, both the
electric utility and the gas utility, along with others, are participating in a
cooperative effort with the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM). The DWM 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.
Both the electric utility and the gas utility have signed AOCs to investigate
certain sites at which investigation includes the completion of interim remedial
measures where appropriate and anticipate signing AOCs to remediate sites as
well. Both the electric utility and the gas utility continue to identify parties
connected to individual MGP sites, and to determine their relative relationship
to other parties at those sites and the degree to which they 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 or
consolidated results of operations of the Company.
The Company is periodically notified by regulators such as the North Carolina
Department of Environment and Natural Resources, the South Carolina Department
of Health and Environmental Control, and the U.S. Environmental Protection
Agency (EPA) of its involvement or potential involvement in sites, other than
MGP sites, that may require investigation
75
<PAGE>
and/or remediation. Although the Company may incur costs at the sites about
which it has been notified, based upon the current status of these sites, the
Company does not expect those costs to be material to the consolidated financial
position or results of operations of the Company.
The EPA has been conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether modifications
at those facilities were subject to New Source Review requirements or New Source
Performance Standards under the Clean Air Act. The Company has recently been
asked to provide information to the EPA as part of this initiative and has
cooperated in providing the requested information. The EPA has initiated
enforcement actions, which may have potentially significant penalties against
other companies that have been subject to this initiative. The Company cannot
predict the outcome of this matter.
The EPA published a final rule approving petitions under section 126 of the
Clean Air Act which requires certain sources to make reductions in nitrogen
oxide emissions by 2003. The Company's fossil-fueled electric generating plants
are included in these petitions. The Company and other states are participating
in litigation challenging the EPA's action. The Company cannot predict the
outcome of this matter.
2. 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 no later than January 31, 1998. All similarly situated utilities
were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's final
interpretation and ruled that the DOE had an unconditional obligation to begin
taking spent nuclear fuel. The Court did not specify a remedy because the DOE
was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan Power v.
DOE, a group of utilities (including the Company) petitioned the Court of
Appeals in Northern States Power (NSP) v. DOE, seeking an order requiring the
DOE to begin taking spent nuclear fuel by January 31, 1998. The DOE took the
position that their delay was unavoidable, and the DOE was excused from
performance under the terms and conditions of the contract. The Court of Appeals
issued an order which precluded the DOE from treating the delay as an
unavoidable delay. However, the Court of Appeals did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially adequate
remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998, a
group of utilities (including the Company) filed a motion with the Court of
Appeals to enforce the mandate in NSP v. DOE. Specifically, the utilities asked
the Court to permit the utilities to escrow their waste fee payments, to order
the DOE not to use the waste fund to pay damages to the utilities, and to order
the DOE to establish a schedule for disposal of spent nuclear fuel. The Court
denied this motion based primarily on the grounds that a review of the matter
was premature, and that some of the requested remedies fell outside of the
mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Court of Claims and before the Court of Appeals. The Company is in the process
of evaluating whether it should file a similar action for damages. In NSP v.
U.S., the Court of Claims decided that NSP must pursue its administrative
remedies instead of filing an action in the Court of Claims. NSP has filed an
interlocutory appeal to the Court of Appeals based on NSP's position that the
Court of Claims has jurisdiction to decide the matter. A group of utilities
(including the Company) has submitted an amicus brief in support of NSP's
position.
The Company also continues to monitor legislation that has been introduced in
Congress which might provide some limited relief. The Company cannot predict the
outcome of this matter.
With certain modifications and additional approval by the NRC, the Company's
spent nuclear fuel storage facilities will be sufficient to provide storage
space for spent fuel generated on the Company's system through the expiration of
the current operating licenses for all of the Company's nuclear generating
units. Subsequent to the expiration of these licenses, dry storage may be
necessary. The Company has initiated the process of obtaining the additional NRC
approval.
76
<PAGE>
3. In the opinion of management, liabilities, if any, arising under other
pending claims would not have a material effect on the financial position and
consolidated results of operations of the Company.
77
<PAGE>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Year Ended December 31, 1999
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -----------------------------------------------------------------------------------------------------------------------
Additions
-----------------------------------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves deducted from related
assets on the balance sheet:
Uncollectible accounts $ 14,226,931 $ 6,966,304 $ 2,607,368 $ 6,990,838 $ 16,809,765
=============== =============== =============== ================ ===============
Reserves deducted from related
assets on the balance sheet:
Inventory $ 145,051 $ 75,752 $ 322,279 $ 145,582 $ 397,500
=============== =============== =============== ================ ===============
Reserves other than those
deducted from assets on the
balance sheet:
Injuries and damages $ 1,010,556 $ 1,194,082 $ -0- $ 1,465,077 $ 739,561
=============== =============== =============== ================ ===============
Reserve for possible coal
mine investment losses $ 7,328,465 $ -0- $ -0- $ 307,369 $ 7,021,096
=============== =============== =============== ================ ===============
Reserve for employee
retirement and
compensation plans $ 151,475,256 $ 10,314,770 $ 5,016,896 $ 5,130,952 $ 161,675,970
=============== =============== =============== ================ ===============
Reserve for environmental
investigation and
remediation costs $ 321,448 $ -0- $ 1,025,000 $ -0- $ 1,346,448
=============== =============== =============== ================ ===============
Reserve for product
warranty $ 465,000 $ 438,168 $ -0- $ 87,939 $ 815,229
=============== =============== =============== ================ ===============
</TABLE>
78
<PAGE>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Year Ended December 31, 1998
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -----------------------------------------------------------------------------------------------------------------------
Additions
-----------------------------------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- -----------------------------------------------------------------------------------------------------------------------
Reserves deducted from related
assets on the balance sheet:
Uncollectible accounts $ 3,366,361 $ 17,993,081$ -0- $ 7,132,511 $ 14,226,931
=============== =============== =============== ================ ===============
Reserves deducted from related
assets on the balance sheet:
Inventory $ -0- $ 145,051 $ -0- $ -0- $ 145,051
=============== =============== =============== ================ ===============
Reserves other than those
deducted from assets on the
balance sheet:
Injuries and damages $ 1,319,664 $ 806,828 $ -0- $ 1,115,936 $ 1,010,556
=============== =============== =============== ================ ===============
Reserve for possible coal
mine investment losses $ 7,505,994 $ -0- $ -0- $ 177,529 $ 7,328,465
=============== =============== =============== ================ ===============
Reserve for employee
retirement and
compensation plans $ 142,232,971 $ 16,569,740 $ -0- $ 7,327,455 $ 151,475,256
=============== =============== =============== ================ ===============
Reserve for environmental
investigation and
remediation costs $ 1,815,909 $ -0- $ -0- $ 1,494,461 $ 321,448
=============== =============== =============== ================ ===============
Reserve for product
warranty $ -0- $ 465,000 $ -0- $ -0- $ 465,000
=============== =============== =============== ================ ===============
</TABLE>
79
<PAGE>
<TABLE>
<CAPTION>
CAROLINA POWER & LIGHT COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Year Ended December 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ---------------------------------------------------------------------------------------------------------------------------
Additions
-------------------------------------
Balance at (1) (2) Deductions Balance at
Beginning Charged to Charged to from Close of
Description of Period Income Other Accounts Reserves Period
- ---------------------------------------------------------------------------------------------------------------------------
Reserves deducted from related
assets on the balance sheet:
Uncollectible accounts $ 3,689,783 $ 6,296,392 $ -0- $ 6,619,814 $ 3,366,361
=============== =============== ================ ================ ================
Reserves other than those
deducted from assets on the
balance sheet:
Injuries and damages $ 1,277,888 $ 714,353 $ -0- $ 672,577 $ 1,319,664
=============== =============== ================ ================ ================
Reserve for possible coal
mine investment losses $ 7,625,008 $ -0- $ -0- $ 119,014 $ 7,505,994
=============== =============== ================ ================ ================
Reserve for employee
retirement and
compensation plans $ 107,569,407 $ 39,690,015 $ -0- $ 5,026,451 $ 142,232,971
=============== =============== ================ ================ ================
Reserve for environmental
investigation and
remediation costs $ 1,815,909 $ -0- $ -0- $ -0- $ 1,815,909
=============== =============== ================ ================ ================
</TABLE>
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<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
NONE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
a) Information on the Company's directors is set forth in the Company's
2000 definitive proxy statement dated March 31, 2000, and incorporated
by reference herein.
b) Information on the Company's executive officers is set forth in PART I
and incorporated by reference herein.
ITEM 11. EXECUTIVE COMPENSATION
Information on executive compensation is set forth in the Company's
2000 definitive proxy statement dated March 31, 2000, and incorporated
by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
a) The Company knows of no person who is a beneficial owner of more than
five (5%) percent of any class of the Company's voting securities
except for Capital Research and Management Company, 333 South Hope
Street, Los Angeles, CA 90071, which as of December 31, 1999, owned
9,450,000 shares of common stock (5.9% of class) as investment advisor
and manager of The American Funds Group of Mutual Funds.
b) Information on security ownership of the Company's management is set
forth in the Company's 2000 definitive proxy statement dated March 31,
2000, and incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on certain relationships and related transactions is set
forth in the Company's 2000 definitive proxy statement dated March 31,
2000, and incorporated by reference herein.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8-Consolidated Financial Statements and
Supplementary Data.
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8-Consolidated Financial Statements and
Supplementary Data
81
<PAGE>
3. Exhibits Filed:
See EXHIBIT INDEX
b) Reports on Form 8-K filed during or with respect to the last
quarter of 1999 and the portion of the first quarter of 2000
prior to the filing of this Form 10-K:
1. Current Report on Form 8-K dated October 25, 1999.
82
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CAROLINA POWER & LIGHT COMPANY
------------------------------
Date: 3/24/00 (Registrant)
------- By: /s/Robert B. McGehee
--------------------
Executive Vice President and
Interim Chief Financial Officer
By: /s/Larry M. Smith
---------------------
Vice President and Controller
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
<TABLE>
<CAPTION>
Signature Title Date
- --------- ----- ----
<S> <C> <C>
/s/ William Cavanaugh III Principal Executive 3/15/00
- -------------------------- Officer and Director
(William Cavanaugh III,
Chairman, President and
Chief Executive Officer)
/s/ Robert B. McGehee Principal Financial 3/15/00
- ---------------------- Officer
(Robert B. McGehee, Executive
Vice President, General Counsel,
Chief Administrative Officer and
Interim Chief Financial Officer)
/s/ Leslie M. Baker, Jr. Director 3/15/00
- ------------------------
(Leslie M. Baker, Jr.)
/s/ Edwin B. Borden Director 3/15/00
- --------------------
(Edwin B. Borden)
/s/ David L. Burner Director 3/15/00
- --------------------
(David L. Burner)
/s/ Charles W. Coker Director 3/15/00
- ---------------------
(Charles W. Coker)
83
<PAGE>
Director 3/15/00
- ------------------------
(Richard L. Daugherty)
/s/ Robert L. Jones Director 3/15/00
- --------------------
(Robert L. Jones)
/s/ Estell C. Lee Director 3/15/00
- ------------------
(Estell C. Lee)
/s/ William O. McCoy Director 3/15/00
- ---------------------
(William O. McCoy)
/s/ E. Marie McKee Director 3/15/00
- -------------------
(E. Marie McKee)
/s/ John H. Mullin, III Director 3/15/00
- ------------------------
(John H. Mullin, III)
/s/ Sherwood H. Smith, Jr. Director 3/15/00
- --------------------------
(Sherwood H. Smith, Jr.,
Chairman Emeritus)
/s/ J. Tylee Wilson Director 3/15/00
- --------------------
(J. Tylee Wilson)
</TABLE>
84
<PAGE>
EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION
*2(a) Agreement and Plan of Merger By and Among
Carolina Power & Light Company, North
Carolina Natural Gas Corporation and
Carolina Acquisition Corporation, dated as
of November 10, 1998 (filed as Exhibit No.
2(b) to Quarterly Report on Form 10-Q for
the quarterly period ended September 30,
1998, File No. 1-3382.)
*2(b) Agreement and Plan of Merger by and among
Carolina Power & Light Company, North
Carolina Natural Gas Corporation and
Carolina Acquisition Corporation, Dated as
of November 10, 1998, as Amended and
Restated as of April 22, 1999 (filed as
Exhibit 2 to Quarterly Report on Form 10-Q
for the quarterly period ended March 31,
1999, File No. 1-3382).
*2(c) Agreement and Plan of Exchange, dated as of
August 22, 1999, by and among Carolina Power
& Light Company, Florida Progress
Corporation and CP&L Holdings, Inc. (filed
as Exhibit 2.1 to Current Report on Form 8-K
dated August 22, 1999, File No. 1-3382).
*2(4) Amended and Restated Agreement and Plan of
Exchange, by and among Carolina Power &
Light Company, Florida Progress Corporation
and CP&L Energy, Inc., dated as of August
22, 1999, amended and restated as of March
3, 2000 (filed as Annex A to Joint
Preliminary Proxy Statement of Carolina
Power & Light Company and Florida Progress
Corporation dated March 6, 2000, File No.
1-03382).
*3a(1) Restated Charter of Carolina Power & Light
Company, as amended May 10, 1996 (filed as
Exhibit No. 3(i) to Quarterly Report on Form
10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
*3a(2) Restated Charter of Carolina Power & Light
Company as amended on May 10, 1996 (filed as
Exhibit 3(i) to Quarterly Report on Form
10-Q for the quarterly period ended June 30,
1997, File No. 1-3382).
*3b(1) By-Laws of Carolina Power & Light Company,
as amended May 10, 1996 (filed as Exhibit
No. 3(ii) to Quarterly Report on Form 10-Q
for the quarterly period ended June 30,
1995, File No. 1-3382).
*3b(2) By-Laws of Carolina Power & Light Company,
as amended on September 18, 1996 (filed as
Exhibit 3(ii) to Quarterly Report on Form
10-Q for the quarterly period ended June 30,
1997, File No.1-3382).
*3b(3) By-Laws of Carolina Power & Light Company,
as amended on March 17, 1999 (filed as
Exhibit No. 3b(3) to Annual Report on Form
10-K for the fiscal year ended December 31,
1998, File No. 1-3382).
*4a(1) Resolution of Board of Directors, dated
December 8, 1954, authorizing the issuance
of, and establishing the series designation,
dividend rate and redemption
85
<PAGE>
prices for the Company's Serial Preferred
Stock, $4.20 Series (filed as Exhibit 3(c),
File No. 33-25560).
*4a(2) Resolution of Board of Directors, dated
January 17, 1967, authorizing the issuance
of, and establishing the series designation,
dividend rate and redemption prices for the
Company's Serial Preferred Stock, $5.44
Series (filed as Exhibit 3(d), File No.
33-25560).
*4a(3) Statement of Classification of Shares dated
January 13, 1971, relating to the
authorization of, and establishing the
series designation, dividend rate and
redemption prices for the Company's Serial
Preferred Stock, $7.95 Series (filed as
Exhibit 3(f), File No. 33-25560).
*4a(4) Statement of Classification of Shares dated
September 7, 1972, relating to the
authorization of, and establishing the
series designation, dividend rate and
redemption prices for the Company's Serial
Preferred Stock, $7.72 Series (filed as
Exhibit 3(g), File No. 33-25560).
*4b Mortgage and Deed of Trust dated as of May
1, 1940 between the Company and The Bank of
New York (formerly, Irving Trust Company)
and Frederick G. Herbst (Douglas J.
MacInnes, Successor), Trustees and the First
through Fifth Supplemental Indentures
thereto (Exhibit 2(b), File No. 2-64189);
and the Sixth through Sixty-sixth
Supplemental Indentures (Exhibit 2(b)-5,
File No. 2-16210; Exhibit 2(b)-6, File No.
2-16210; Exhibit 4(b)-8, File No. 2-19118;
Exhibit 4(b)-2, File No. 2-22439; Exhibit
4(b)-2, File No. 2-24624; Exhibit 2(c), File
No. 2-27297; Exhibit 2(c), File No. 2-30172;
Exhibit 2(c), File No. 2-35694; Exhibit
2(c), File No. 2-37505; Exhibit 2(c), File
No. 2-39002; Exhibit 2(c), File No. 2-41738;
Exhibit 2(c), File No. 2-43439; Exhibit
2(c), File No. 2-47751; Exhibit 2(c), File
No. 2-49347; Exhibit 2(c), File No. 2-53113;
Exhibit 2(d), File No. 2-53113; Exhibit
2(c), File No. 2-59511; Exhibit 2(c), File
No. 2-61611; Exhibit 2(d), File No. 2-64189;
Exhibit 2(c), File No. 2-65514; Exhibits
2(c) and 2(d), File No. 2-66851; Exhibits
4(b)-1, 4(b)-2, and 4(b)-3, File No.
2-81299; Exhibits 4(c)-1 through 4(c)-8,
File No. 2-95505; Exhibits 4(b) through
4(h), File No. 33-25560; Exhibits 4(b) and
4(c), File No. 33-33431; Exhibits 4(b) and
4(c), File No. 33-38298; Exhibits 4(h) and
4(I), File No. 33-42869; Exhibits 4(e)-(g),
File No. 33-48607; Exhibits 4(e) and 4(f),
File No. 33-55060; Exhibits 4(e) and 4(f),
File No. 33-60014; Exhibits 4(a) and 4(b) to
Post-Effective Amendment No. 1, File No.
33-38349; Exhibit 4(e), File No. 33-50597;
Exhibit 4(e) and 4(f), File No. 33-57835;
Exhibit to Current Report on Form 8-K dated
August 28, 1997, File No. 1-3382; Form of
Carolina Power & Light Company First
Mortgage Bond, 6.80% Series Due August 15,
2007 filed as Exhibit 4 to Form 10-Q for the
period ended September 30, 1998, File No.
1-3382; Exhibit 4(b), File No. 333-69237;
and Exhibit 4(c), File No. 1-03382.)
*4c(1) Indenture, dated as of March 1, 1995,
between the Company and Bankers Trust
Company, as Trustee, with respect to
Unsecured Subordinated Debt Securities
(filed as Exhibit No. 4(c) to Current Report
on Form 8-K dated April 13, 1995, File No.
1-3382).
*4c(2) Resolutions adopted by the Executive
Committee of the Board of Directors at a
86
<PAGE>
meeting held on April 13, 1995, establishing
the terms of the 8.55% Quarterly Income
Capital Securities (Series A Subordinated
Deferrable Interest Debentures) (filed as
Exhibit 4(b) to Current Report on Form 8-K
dated April 13, 1995, File No. 1-3382).
*4d Indenture (for Senior Notes), dated as of
March 1, 1999 between Carolina Power & Light
Company and The Bank of New York, as
Trustee, and the First Supplemental Senior
Note Indenture thereto, (filed as Exhibits
No. 4(a) and 4(b) to Current Report on Form
8-K dated March 19, 1999, File No. 1-03382).
*4(e) Indenture (For Debt Securities), dated as of
October 28, 1999 between Carolina Power &
Light Company and The Chase Manhattan Bank,
as Trustee (filed as Exhibit 4(a) to Current
Report on Form 8-K dated November 5, 1999,
File No. 1-03382).
*10a(1) Purchase, Construction and Ownership
Agreement dated July 30, 1981 between
Carolina Power & Light Company and North
Carolina Municipal Power Agency Number 3 and
Exhibits, together with resolution dated
December 16, 1981 changing name to North
Carolina Eastern Municipal Power Agency,
amending letter dated February 18, 1982, and
amendment dated February 24, 1982 (filed as
Exhibit 10(a), File No. 33-25560).
*10a(2) Operating and Fuel Agreement dated July 30,
1981 between Carolina Power & Light Company
and North Carolina Municipal Power Agency
Number 3 and Exhibits, together with
resolution dated December 16, 1981 changing
name to North Carolina Eastern Municipal
Power Agency, amending letters dated August
21, 1981 and December 15, 1981, and
amendment dated February 24, 1982 (filed as
Exhibit 10(b), File No. 33-25560).
*10a(3) Power Coordination Agreement dated July 30,
1981 between Carolina Power & Light Company
and North Carolina Municipal Power Agency
Number 3 and Exhibits, together with
resolution dated December 16, 1981 changing
name to North Carolina Eastern Municipal
Power Agency and amending letter dated
January 29, 1982 (filed as Exhibit 10(c),
File No. 33-25560).
*10a(4) Amendment dated December 16, 1982 to
Purchase, Construction and Ownership
Agreement dated July 30, 1981 between
Carolina Power & Light Company and North
Carolina Eastern Municipal Power Agency
(filed as Exhibit 10(d), File No. 33-25560).
*10a(5) Agreement Regarding New Resources and
Interim Capacity between Carolina Power &
Light Company and North Carolina Eastern
Municipal Power Agency dated October 13,
1987 (filed as Exhibit 10(e), File No.
33-25560).
*10a(6) Power Coordination Agreement - 1987A between
North Carolina Eastern Municipal Power
Agency and Carolina Power & Light Company
for Contract Power From New Resources Period
1987-1993 dated October 13, 1987 (filed as
Exhibit 10(f), File No. 33-25560).
87
<PAGE>
+ *10b(1) Directors Deferred Compensation Plan
effective January 1, 1982 as amended (filed
as Exhibit 10(g), File No. 33-25560).
+ *10b(2) Supplemental Executive Retirement Plan
effective January 1, 1984 (filed as Exhibit
10(h), File No. 33-25560).
+ *10b(3) Retirement Plan for Outside Directors (filed
as Exhibit 10(i), File No. 33-25560).
+ *10b(4) Executive Deferred Compensation Plan
effective May 1, 1982 as amended (filed as
Exhibit 10(j), File No. 33-25560).
+ *10b(5) Key Management Deferred Compensation Plan
(filed as Exhibit 10(k), File No. 33-25560).
+ *10b(6) Resolutions of the Board of Directors, dated
March 15, 1989, amending the Key Management
Deferred Compensation Plan (filed as Exhibit
10(a), File No. 33-48607).
+*10b(7) Resolutions of the Board of Directors dated
May 8, 1991, amending the Directors Deferred
Compensation Plan (filed as Exhibit 10(b),
File No. 33-48607).
+*10b(8) Resolutions of the Board of Directors dated
May 8, 1991, amending the Executive Deferred
Compensation Plan (filed as Exhibit 10(c),
File No. 33-48607).
+*10b(9) 1997 Equity Incentive Plan, approved by the
Company's shareholders May 7, 1997,
effective as of January 1, 1997 (filed as
Appendix A to the Company's 1997 Proxy
Statement, File No. 1-03382).
+*10b(10) Performance Share Sub-Plan of the 1997
Equity Incentive Plan, adopted by the
Personnel, Executive Development and
Compensation Committee of the Board of
Directors, March 19, 1997, subject to
shareholder approval of the 1997 Equity
Incentive Plan, which was obtained on May 7,
1997, (filed as Exhibit 10(b), File No.
1-03382).
+*10b(11) Resolutions of Board of Directors dated July
9, 1997, amending the Deferred Compensation
Plan for Key Management Employees of
Carolina Power & Light Company.
+*10b(12) Resolutions of Board of Directors dated July
9, 1997, amending the Supplemental Executive
Retirement Plan of Carolina Power & Light
Company.
+*10b(13) Amended Management Incentive Compensation
Program of Carolina Power & Light Company,
as amended December 10, 1997.
+*10b(14) Carolina Power & Light Company Restoration
Retirement Plan, effective January 1, 1998.
+*10b(15) Carolina Power & Light Company Non-Employee
Director Stock Unit Plan, effective January
1, 1998.
+*10b(16) Carolina Power & Light Company Restricted
Stock Agreement, as approved
88
<PAGE>
January 7, 1998, pursuant to the Company's
1997 Equity Incentive Plan (filed as Exhibit
No. 10 to Quarterly Report on Form 10-Q for
the quarterly period ended March 31, 1998,
File No. 1-3382.)
+*10b(17) Resolutions of Board of Directors dated July
17, 1998, amending the Supplemental
Executive Retirement Plan of Carolina Power
& Light Company, effective January 1, 1999,
(filed as Exhibit No. 10(a) to Quarterly
Report on Form 10-Q for the quarterly period
ended June 30, 1998, File No. 1-3382.)
+*10b(18) Amended Management Incentive Compensation
Plan of Carolina Power & Light Company,
effective January 1, 1999, as amended by the
Organization and Compensation Committee of
the Board of Directors on July 17, 1998,
(filed as Exhibit No. 10(b) to Quarterly
Report on Form 10-Q for the quarterly period
ended June 30, 1998, File No. 1-3382.)
+*10b(19) Supplemental Senior Executive Retirement
Plan of Carolina Power & Light Company, as
amended January 1, 1999 (filed as Exhibit
No. 10b(19) to Annual Report on Form 10-K
for the fiscal year ended December 31, 1998,
File No. 1-3382).
+*10b(20) Carolina Power & Light Company Restoration
Retirement Plan, as amended January 1, 1999
(filed as Exhibit No. 10b(20) to Annual
Report on Form 10-K for the fiscal year
ended December 31, 1998, File No. 1-3382).
+10b(21) Performance Share Sub-Plan of the 1997
Equity Incentive Plan, as Revised and
Restated March 17, 1999.
+10b(22) Amended Management Incentive Compensation
Plan of Carolina Power & Light Company, as
amended January 1, 2000.
+*10b(23) Carolina Power & Light Company Management
Deferred Compensation Plan, adopted as of
January 1, 2000, (filed as Exhibit 4 to Form
S-8 dated October 25, 1999, File No.
333-89685).
+10b(24) Amended and Restated Supplemental Senior
Executive Retirement Plan of Carolina Power
& Light Company, effective January 1, 1984,
as last amended March 15, 2000.
+*10b(25) Employment Agreement dated September 1,
1992, by and between the Company and William
Cavanaugh III (filed as Exhibit 10b, File
No. 1-03382).
+*10b(26) Employment Agreement dated April 1, 1993, by
and between the Company and William S. Orser
(filed as Exhibit 10b, File No. 1-03382).
+*10b(27) Employment Arrangement dated September 27,
1994 by and between the Company and Glenn E.
Harder (filed as Exhibit 10b, File No.
1-03382).
+*10b(28) Personal Services Agreement dated September
18, 1996, by and between the Company and
Sherwood H. Smith, Jr. (filed as Exhibit
10b, File No.1-03382).
89
<PAGE>
+*10b(29) Employment Agreement dated June 2, 1997, by
and between the Company and Robert B.
McGehee (filed as Exhibit 10b, File No.
1-03382).
+*10b(30) Employment Agreement dated September 24,
1997, by and between the Company and John E.
Manczak (filed as Exhibit 10b, File No.
1-03382).
+*10b(31) Employment Agreement dated August 3, 1998,
by and between the Company and Tom D.
Kilgore (filed as Exhibit 10b(27) to the
Company's Annual Report on Form 10-K for the
year ended December 31, 1998, File No.
1-3382).
+10b(32) Agreement dated April 27, 1999 between the
Company and Sherwood H. Smith, Jr.
+10b(33) Employment Agreement dated July 15, 1999 by
and between North Carolina Natural Gas
Corporation and Calvin B. Wells.
+10b(34) Employment Arrangement dated August 5, 1999
by and between the Company and Larry M.
Smith.
12 Computation of Ratio of Earnings to Fixed
Charges and Preferred Dividends Combined and
Ratio of Earnings to Fixed Charges.
21 Subsidiaries of Carolina Power & Light
Company
23(a) Consent of Deloitte & Touche LLP.
27 Financial Data Schedule
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement required to be filed as
an exhibit to this report pursuant to Item 14 (c) of Form 10-K.
90
EXHIBIT 10B(21)
EXHIBIT A
TO
1997 EQUITY INCENTIVE PLAN
PERFORMANCE SHARE SUB-PLAN
--------------------------
(As Revised and Restated March 17, 1999)
This Performance Share Sub-Plan ("Sub-Plan") sets forth the rules and
regulations adopted by the Committee for issuance of Performance Share Awards
under Section 10 of the 1997 Equity Incentive Plan ("Plan"). Capitalized terms
used in this Sub-Plan that are not defined herein shall have the meaning given
in the Plan. In the event of any conflict between this Sub-Plan and the Plan,
the terms and conditions of the Plan shall control. No Award Agreement shall be
required for participation in this Sub-Plan.
SECTION 1. DEFINITIONS
When used in this Sub-Plan, the following terms shall have the meanings as set
forth below, and are in addition to the definitions set forth in the Plan.
1.1 "Account" means the account used to record and track the number of
Performance Shares granted to each Participant as provided in Section
2.4.
1.2 "Award" as used in this Sub-Plan means each aggregate award of
Performance Shares as provided in Section 2.2.
1.3 "EBITDA" means earnings before interest, taxes, depreciation, and
amortization as determined from time to time by the Committee.
1.4 "EBITDA Growth" means the percentage increase (if any) in EBITDA for
any Year, as compared to the previous Year as determined from time to
time by the Committee.
1.5 "Peer Group" means the utilities included in the Standard & Poors
Utility (Electric Power Companies) Index.
1.6 "Performance Period" for purposes of this Sub-Plan means three
consecutive Years beginning with the Year in which an Award is granted.
1.7 "Performance Schedule" means Attachment 1 to this Sub-Plan, which sets
forth the Performance Measures applicable to this Sub-Plan.
<PAGE>
1.8 "Performance Share" for purposes of this Sub-Plan means each unit of an
Award granted to a Participant, the value of which is equal to the
value of Company Stock as hereinafter provided.
1.9 "Retire" or "Retirement" means termination of employment on or after:
(a) becoming 65 years old with at least 5 years of service;
(b) becoming 55 years old with at least 15 years of service; or
(c) achieving at least 35 years of service, regardless of age.
1.10 "Salary" means the regular base rate of compensation payable by the
Company to a Participant on an annual basis as of the date an Award is
Granted. Salary does not include bonuses, if any, or incentive
compensation, if any. Such compensation shall not be reduced by any
deferrals made under any other plans or programs maintained by the
Company.
1.11 "Total Shareholder Return" means the total percentage return realized
by the owner of a share of stock during a relevant Year or any part
thereof. Total Shareholder Return is equal to the appreciation or
depreciation in value of the stock (which is equal to the closing value
of the stock on the last trading day of the relevant period minus the
closing value of the stock on the last trading day of the preceding
Year) plus the dividends declared during the relevant period, divided
by the closing value of the stock on the last trading day of the
preceding Year. Closing values for the stock on the dates given above
shall be those published in the Wall Street Journal.
1.12 "Year" means a calendar year.
SECTION 2. SUB-PLAN PARTICIPATION AND AWARDS
2.1 Participant Selection. Participants under this Sub-Plan shall be
selected by the Committee in its sole discretion as provided in Section 4.2
of the Plan.
2.2 Awards. Subject to any adjustments to be made under Section 2.5, the
Compensation Committee may, in its sole discretion, grant Awards to some or all
of the Participants in the form of a specific number of Performance Shares. The
total value of any Award shall not exceed the following limitations, based on
the Participant's Salary on the date that the Award is granted:
----------------------------------- ---------------------
Participant Award Limitation
----------------------------------- ---------------------
President/CEO 75% of Salary
----------------------------------- ---------------------
Group Executives 50% of Salary
----------------------------------- ---------------------
Department Heads and Key Managers*
Level I 30% of Salary
Level II 25% of Salary
Level III 20% of Salary
----------------------------------- ---------------------
*Levels shall be determined in the sole discretion of the Committee
2
<PAGE>
2.3 Award Valuation at Grant. In calculating the limitations set forth in
Section 2.2, the value of each Performance Share shall be equal to the closing
price of a share of Stock on the last trading day before the Award is granted,
as published in the Wall Street Journal. Each Award is deemed to be granted on
the day that it is approved by the Committee.
2.4 Accounting and Adjustment of Awards. The number of Performance Shares
awarded to a Participant shall be recorded in a separate Account for each
Participant. The number of Performance Shares recorded in a Participant's
Account shall be adjusted to reflect any splits or other adjustments in the
Stock. If any cash dividends are paid on the Stock, the number of Performance
Shares in each Participant's Account shall be increased by a number equal to (i)
the dividend multiplied times the number of Performance Shares in each
Participant's Account, divided by (ii) the closing price of a share of Stock on
the payment date of the dividend, as published in the Wall Street Journal.
2.5 Performance Schedule and Calculation of Awards. Each Award shall become
vested on January 1 immediately following the end of the applicable Performance
Period, subject to adjustment in accordance with the following procedure.
(a) One half of the Award shall be adjusted as follows:
(i) The Total Shareholder Return for the Company shall be
determined for each Year during the Performance Period, and
shall then be averaged (the "Company TSR").
(ii) The average Total Shareholder Return for all Peer Group
utilities shall be determined for each Year during the
Performance Period, and shall then be averaged ( the "Peer
Group TSR").
(iii) The Peer Group TSR for the Performance Period shall be
subtracted from the Company TSR for the Performance Period.
The remainder shall then be used to determine the number of
vested Performance Shares using the Performance Schedule,
based on one half of the number of Performance Shares in the
Participant's Account.
(b) The other half of the Award shall be adjusted as follows:
(i) The EBITDA Growth for the Company shall be determined for
each Year during the Performance Period, and shall then be
averaged (the Company EBITDA Growth").
3
<PAGE>
(ii) The average EBITDA Growth for all Peer Group utilities
shall be determined for each Year during the Performance
period, and shall be averaged (the Peer Group EBITDA Growth").
(iii) The Peer Group EBITDA Growth for the Performance Period
shall be subtracted from the Company EBITDAGrowth for the
Performance Period. The remainder shall then be used to
determine the number of vested Performance Shares using the
Performance Schedule, based on one half of the number of
Performance Shares in the Participant's Account.
(c) The total number of vested Performance Shares payable to the
Participant shall be the sum of the amounts determined in accordance with
subsections (a) and (b) above.
(d) The Performance Measures and the Performance Schedule will not
change during any Performance Period with regard to any Awards that have already
been granted. The Committee reserves the right to modify or adjust the
Performance Measures and/or the Performance Schedule in the Committee's sole
discretion with regard to future grants.
2.6 Payment Options. Except as provided in Section 3, Awards shall be paid after
expiration of the Performance Period. The Company will pay in cash to each
Participant the aggregate value of vested Performance Shares, which shall be
determined in accordance with Section 2.7. Payment shall be made as follows:
(a) 100% on or about April 1 of the Year immediately following
expiration of the Performance Period; or
(b) in accordance with an alternative payment election made by
Participant substantially in the form attached hereto as Attachment 2, provided
that such election is executed by the Participant and returned to the Vice
President, Human Resources Department no later than the end of the first Year of
the Performance Period. Once made, this election is irrevocable.
2.7 Valuation of Performance Shares. For the purposes of payment of under
Section 2.6, the aggregate value of vested Performance Shares shall be equal to
the total number of vested Performance Shares in the Participant's Account
(after any applicable adjustments under Section 2.5) multiplied times the
closing price of the Stock on the last trading day before payment of the Award,
as published in the Wall Street Journal.
SECTION 3. EARLY VESTING AND FORFEITURE
3.1 Retirement, Death, Disability, Divestiture or Change in Control. If prior to
expiration of the Performance Period the Participant Retires, dies or becomes
disabled, or in the event of a Divestiture or a Change in Control during a
Performance Period, the
4
<PAGE>
Participant's Award shall immediately become vested, and the aggregate value of
the Award shall be paid in cash after being adjusted accordance with the
following procedure.
(a) One half of the Award shall be adjusted as follows:
(i) The Total Shareholder Return for the Company shall be
determined for each Year or partial Year, and a weighted
average Total Shareholder Return for the Company shall be
calculated for the period between the first day of the
Performance Period and the date the Participant Retires, dies
or becomes Disabled, or the date of the Divestiture, or the
date that the Change in Control becomes effective (the
"Prorated Company TSR").
(ii) The average Total Shareholder Return for all Peer Group
utilities shall be determined for each Year or partial Year,
and a weighted average Total Shareholder Return shall be
calculated for the period between the first day of the
Performance Period and the date the Participant Retires, dies
or becomes Disabled, or the date of the Divestiture, or the
date that the Change in Control becomes effective ( the
"Prorated Peer Group TSR").
(iii) The Prorated Peer Group TSR for the Performance Period
shall be subtracted from the Prorated Company TSR for the
Performance Period. The remainder shall then be used to
determine the vested Performance Shares using the Performance
Schedule, based on one half of the number of Performance
Shares in the Participant's Account.
(b) The other half of the Award shall be adjusted as follows:
(i) The EBITDA Growth for the Company shall be determined for
each Year or partial Year, and a weighted average EBITDA
Growth for the Company shall be calculated for the period
between the first day of the Performance Period and the end of
the calendar quarter immediately preceding the date that the
Participant Retires, dies or becomes Disabled, or end of the
calendar quarter immediately preceding the date of the
Divestiture, or the date that the Change in Control becomes
effective (the "Prorated Company EBITDA Growth").
(ii) The average EBITDA Growth for all Peer Group utilities
shall be determined for each Year or partial Year, and a
weighted average EBITDA Growth shall be calculated for the
period between the first day of the Performance Period and the
end of the calendar quarter immediately preceding the date the
Participant Retires, dies or becomes Disabled, or the end of
the calendar quarter immediately preceding the date of the
5
<PAGE>
Divestiture, or the date that the Change in Control becomes
effective ( the "Prorated Peer Group EBITDA Growth").
(iii) The Prorated Peer Group EBITDA Growth for the
Performance Period shall be subtracted from the Prorated
Company EBITDA Growth for the Performance Period. The
remainder shall then be used to determine the vested
Performance Shares using the Performance Schedule, based on
one half of the number of Performance Shares in the
Participant's Account.
(c) The total number of vested Performance Shares payable to the
Participant shall be the sum of the amounts determined in accordance with
subsections (a) and (b) above.
(d) If the Participant Retires, the Award shall be paid in accordance
with the Participant's election as provided in Section 2.6. If the Participant
dies or becomes disabled, or in the event of a Divestiture or Change in Control,
payment shall be made in cash within a reasonable time after the Participant
dies or becomes Disabled, or within a reasonable time after the Divestiture or
Change in Control becomes effective, notwithstanding any election under Section
2.6. Payment upon death shall be made to the Participant's Designated
Beneficiary. The aggregate value of the vested Performance Shares shall be
determined in accordance with section 3.2.
3.2 Valuation of Performance Shares. For the purposes of payment under Section
3.1, the aggregate value of vested Performance Shares shall be equal to the
number of vested Performance Shares in the Participant's Account (after any
applicable adjustments under Section 3.1) multiplied times the closing price of
the Stock on the date that the Participant Retires, dies or becomes Disabled, or
on the date of the Divestiture or Change in Control (as applicable), as
published in the Wall Street Journal.
3.3 Termination of Employment. In the event that a Participant's employment with
the Company terminates for any reason other than Retirement, death or
Disability, any Award made to the Participant which has not vested as provided
in Section 2 shall be forfeited. Any vested Awards shall be paid within a
reasonable time after termination, notwithstanding any election to defer the
payment of any Award under Section 2.6.
4. NON-ASSIGNABILITY OF AWARDS
The Awards and any right to receive payment under the Plan and this Sub-Plan may
not be anticipated, alienated, pledged, encumbered, or subject to any charge or
legal process, and if any attempt is made to do so, or a Participant becomes
bankrupt, then in the sole discretion of the Committee, any Award made to the
Participant which has not vested as provided in Sections 2 and 3 shall be
forfeited.
5. AMENDMENT AND TERMINATION
6
<PAGE>
This Sub-Plan shall be subject to amendment, suspension, or termination as
provided in the Plan.
7
<PAGE>
ATTACHMENT 1
------------
PERFORMANCE SCHEDULE
--------------------
PERFORMANCE SHARE CALCULATION(1)
--------------------------------
The following table shall be used to adjust one half of the Participant's Award
in accordance with Section 2.5(a) or Section 3.1(a) of the Plan:
IF THE COMPANY TSR(2) MINUS THEN THE 50% OF THE VESTED
THE PEER GROUP TSR(2) IS: PERFORMANCE SHARE AWARD
SHALL BE MULTIPLIED BY:
5% or better 2.00
4.0 - 4.99 1.75
3.0 - 3.99 1.50
2.0 - 2.99 1.25
1.0 - 1.99 1.00
(0.99) - 0.99 .50
(1.0) - (1.99) .25
(2.0) or less 0.00
8
<PAGE>
The following table shall be used to adjust one half of the Participant's Award
in accordance with Section 2.5(b) or Section 3.1(b) of the Plan:
IF THE COMPANY EBITDA GROWTH(2) MINUS THEN THE 50% OF THE VESTED
THE PEER GROUP EBITDA GROWTH(2) IS: PERFORMANCE SHARE AWARD
SHALL BE MULTIPLIED BY:
5% or better 2.00
4.0 - 4.99 1.75
3.0 - 3.99 1.50
2.0 - 2.99 1.25
1.0 - 1.99 1.00
0.00 - 0.99 .50
Less than 0 0
(1) The number of Performance Shares as calculated above shall be paid in
accordance with the provisions of Section 2.5 and 2.6 of the Sub-Plan.
(2) For purposes of Section 3, the Prorated Company TSR and EBITDA Growth and
Prorated Peer Group TSR and EBITDA Growth shall be used, and the number of
Performance Shares as calculated above shall be paid in accordance with the
provisions of Section 3.1 of the Sub-Plan.
9
<PAGE>
ATTACHMENT 2
------------
PERFORMANCE SHARE SUB-PLAN
199_ DEFERRAL ELECTION FORM
As an employee of Carolina Power & Light Company ("Company"), and a participant
in the Performance Share Sub-Plan of the 1997 Equity Incentive Plan
("Sub-Plan"), I hereby elect to defer payment of my Award otherwise payable to
me by the Company and attributable to services to be performed by me during the
Performance Period beginning on January __, 199__. This election shall apply to
[CHECK ONE]:
[ ] 100% of the Award [ ] 50% of the Award
[ ] 75% of the Award [ ] 25% of the Award
Upon vesting, I understand that my Award shall continue be recorded in my
Account as Performance Shares as described in the Sub-Plan and adjusted to
reflect the payment and reinvesting of the Company's common stock dividends over
the deferral period, until paid in full.
I hereby elect to defer receipt (or commencement of receipt) of my Award until
the date specified below, or as soon as practical thereafter [CHECK ONE]:
[ ] a specific date certain at least 5 years from expiration
of the Performance Period:
4 / 1 / *
---------------------
(month/day/year)
[ ] the April 1 following the date of retirement
[ ] the April 1 following the first anniversary of my date of
retirement
* Notwithstanding my election above, if I elect a date certain distribution and
I retire before that date certain, I understand that the Company will commence
distribution of my account no later than the April 1 following the first
anniversary of the date of retirement, or as soon as practical thereafter, even
though said date is earlier than 5 years from expiration of the Performance
Period.
I hereby elect to be paid as described in the Sub-Plan in the form of [CHECK
ONE]:
[ ] a single payment [ ] annual payments commencing on the date
set forth above and payable on the
anniversary date thereof over:
[ ] a two year period [ ] a three year period
[ ] a four year period [ ] a five year period
I understand that I will receive "earnings" on those deferred amounts when they
are paid to me.
I understand that the election made as indicated herein is irrevocable and that
all deferral elections are subject to the provisions of the Sub-Plan, including
provisions that may affect timing of distributions.
I understand and acknowledge that my interests herein and my rights to receive
distribution of the deferred amounts may not be anticipated, alienated, sold,
transferred, assigned, pledged, encumbered, or subjected to any charge or legal
process, and if any attempt is made to do so, or I become bankrupt, my interest
may be terminated by the Committee, which, in his sole discretion. I further
understand that nothing in the Sub-Plan shall be interpreted or construed to
require the Company in any manner to fund any obligation to me, or to my
beneficiary(ies) in the event of my death.
- ------------------------------- -----------------------------------
(Signature) (Date)
- ------------------------------- -----------------------------------
(Print Name) (Company Location)
Received:
Agent of Chief Executive Officer
- ------------------------------- -----------------------------------
(Signature) (Date)
EXHIBIT 10B(22)
AMENDED MANAGEMENT INCENTIVE COMPENSATION PLAN
OF
CAROLINA POWER & LIGHT COMPANY
AS AMENDED JANUARY 1, 2000
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
Page
<S> <C>
ARTICLE I PURPOSE........................................................................1
ARTICLE II DEFINITIONS....................................................................1
ARTICLE III ADMINISTRATION.................................................................4
ARTICLE IV PARTICIPATION..................................................................5
ARTICLE V AWARDS.........................................................................5
ARTICLE VI DISTRIBUTION AND DEFERRAL OF AWARDS............................................9
ARTICLE VII TERMINATION OF EMPLOYMENT......................................................15
ARTICLE VIII MISCELLANEOUS..................................................................15
</TABLE>
ii
<PAGE>
ARTICLE I
---------
PURPOSE
-------
The purpose of the Management Incentive Compensation Plan (the "Plan")
of Carolina Power & Light Company (the "Sponsor") is to promote the financial
interest of the Sponsor and its Affiliated Companies, including its growth, by
(i) attracting and retaining executive officers and other management-level
employees who can have a significant positive impact on the success of the
Sponsor and its Affiliated Companies; (ii) motivating such personnel to help the
Sponsor and its Affiliated Companies achieve annual incentive, performance and
safety goals; (iii) motivating such personnel to improve their own as well as
their business unit/work group's performance through the effective
implementation of human resource strategic initiatives; and (iv) providing
annual cash incentive compensation opportunities that are competitive with those
of other major corporations.
The Sponsor amends the Plan effective January 1, 2000.
ARTICLE II
----------
DEFINITIONS
-----------
The following definitions are applicable to the Plan:
1. "Award": The benefit payable to a Participant hereunder, consisting of a
Corporate Component and a Noncorporate Component.
2. "Affiliated Company" shall mean any corporation or other entity that is
required to be aggregated with the Sponsor pursuant to Sections 414(b), (c),
(m), or (o) of the Internal Revenue Code of 1986, as amended (the "Code"), but
only to the extent required.
<PAGE>
3. "Company": Carolina Power & Light Company, a North Carolina corporation,
or any successor to it in the ownership of substantially all of its assets and
each Affiliated Company that, with the consent of the Compensation Committee,
adopts the Plan and is included in Exhibit B, as in effect from time to time.
4. "Compensation Committee": The Organization and Compensation Committee of
the Board of Directors of the Sponsor.
5. "Corporate Factor": The factor determined by the Compensation Committee
to be utilized in calculating the Corporate Component of an Award pursuant to
Article V, Section 3.a. hereof, which can range from 0 to 1.5.
6. "Corporate Component": That portion of an Award based upon the overall
performance of the Sponsor, as determined in Article V, Section 3.a. hereof.
7. "Date of Retirement": The first day of the calendar month immediately
following the Participant's Retirement.
8. "EBITDA": The earnings of the Sponsor before interest, taxes,
depreciation, and amortization as determined from time to time by the
Compensation Committee.
9. "EBITDA Growth": The percentage increase (if any) in EBITDA of the
Sponsor for any Year, as compared to the previous Year as determined from time
to time by the Compensation Committee.
10. "Noncorporate Component": That portion of an Award based upon the level
of attainment of a Company, business unit/group, departmental, and individual
Performance Measures, as provided in Article V, Section 3 .b. hereof, which can
range from 0 to 1.5.
11. "Participant": An employee of any Company who is selected pursuant to
Article IV hereof to be eligible to receive an Award under the Plan.
2
<PAGE>
12. "Peer Group": The utilities included in the Standard & Poors Utility
(Electric Power Companies) Index.
13. "Performance Measure": A goal or goals established for measuring the
performance of a Company, business unit/group, department, or individual used
for the purpose of computing the Noncorporate Component of an Award for a
Participant.
14. "Performance Unit": A unit or credit, linked to the value of the
Sponsor's Common Stock under the terms set forth in Article VI hereof.
15. "Plan": The Management Incentive Compensation Plan of Carolina Power &
Light Company as contained herein, and as it may be amended from time to time.
16. "Retirement": A Participant's termination of employment with a Company
after having met at least one of the following requirements: at least age 65
with 5+ years of service, at least age 55 with 15+ years of service, or 35+
years of service regardless of age.
17. "Salary": The compensation paid by a Company to a Participant in a
relevant Year, consisting of regular or base compensation, such compensation
being understood not to include bonuses, if any, or incentive compensation, if
any. Provided, that such compensation shall not be reduced by any cash deferrals
of said compensation made under any other plans or programs maintained by such
Company.
18. "Section 16 Participants": Those Participants who are subject to the
provisions of Section 16 of the Securities Exchange Act of 1934, as amended (the
"1934 Act"). Individuals who are subject to Section 16 of the 1934 Act include,
without limitation, directors and certain officers of the Sponsor, and any
individual who beneficially owns more than ten percent of a class of the
Sponsor's equity securities registered under Section 12 of the 1934 Act.
3
<PAGE>
19. "Senior Management Committee": The Senior Management Committee of the
Sponsor.
20. "Target Award Opportunity": The target for an Award under this Plan as
set forth in Section 2 of Article V hereof.
21. "Year": A calendar year.
ARTICLE III
-----------
ADMINISTRATION
--------------
The Plan shall be administered by the Chief Executive Officer of the
Sponsor. Except as otherwise provided herein, the Chief Executive Officer of the
Sponsor shall have sole and complete authority to (i) select the Participants;
(ii) establish and adjust (either before or during the relevant Year) a
Participant's Performance Measures, their relative percentage weight, and the
performance criteria necessary for attainment of various performance levels;
(iii) approve Awards; (iv) establish from time to time regulations for the
administration of the Plan; and (v) interpret the Plan and make all
determinations deemed necessary or advisable for the administration of the Plan,
all subject to its express provisions. Notwithstanding the foregoing, with
respect to Participants who are at or above the Department Head level in any
Company, the performance criteria and Awards shall be subject to the specific
approval of the Compensation Committee. In addition, the Compensation Committee
shall have the sole authority to determine the total payout under the Plan up to
a maximum of three percent (3%) of the Sponsor's after-tax income for a relevant
Year.
4
<PAGE>
A majority of the Compensation Committee shall constitute a quorum, and
the acts of a majority of the members present at any meeting at which a quorum
is present, or acts approved in writing by a majority of the members of the
Committee without a meeting, shall be the acts of such Committee.
ARTICLE IV
PARTICIPATION
-------------
The Chief Executive Officer of the Sponsor shall select from time to
time the Participants in the Plan for each Year from those employees of each
Company who, in his opinion, have the capacity for contributing in a substantial
measure to the successful performance of the Company that Year. No employee
shall at any time have a right to be selected as a Participant in the Plan for
any Year nor, having been selected as a Participant for one Year, have the right
to be selected as a Participant in any other Year.
ARTICLE V
---------
AWARDS
------
1. Eligibility. In order for any Participant to be eligible to receive
an Award, two conditions must be met. First, a contribution must be earned by
one or more groups of employees under the Employee Stock Incentive Plan feature
of the Sponsor's Stock Purchase-Savings Plan. Second, the Sponsor must also meet
minimum threshold performance levels for return on common equity, EBITDA Growth,
and other measures for the relevant Year as may be established by the
Compensation Committee. Threshold performance for return on common
5
<PAGE>
equity and EBITDA Growth is the weighted average of a Peer Group of utilities,
averaged over the most recent three-year period. To satisfy threshold
performance, the Sponsor must be above the three-year average with respect to
return on common equity and EBITDA Growth.
2. Target Award Opportunities. The following table sets forth Target Award
Opportunities, expressed as a percentage of Salary, for various levels of
participation in the Plan:
------------------------------------------ -------------------------------
Participation Target Award 0pportunities
------------------------------------------ -------------------------------
Chief Executive Officer of Sponsor 60%
------------------------------------------ -------------------------------
Chief Operating Officer of Sponsor 60%
------------------------------------------ -------------------------------
Executive Vice Presidents of Sponsor 40%
------------------------------------------ -------------------------------
------------------------------------------ -------------------------------
Senior Vice Presidents of Sponsor 35%
------------------------------------------ -------------------------------
Department Heads (or equivalent) 25%
------------------------------------------ -------------------------------
Other Participants:
Key Managers 20%
Other Managers 15%
------------------------------------------ -------------------------------
The Target Award Opportunity for the Chief Executive Officer of the Sponsor
shall be 60%; however, the Compensation Committee of the Board shall be
authorized to change that amount from year to year, or to award an amount of
compensation based on other considerations, in its complete discretion.
3. Award Components. Awards under the Plan to which Participants are
eligible consist of the sum of a Corporate Component and a Noncorporate
Component. The portion of the Target Award Opportunities attributable to the
Corporate Component and Noncorporate Component, respectively, for various levels
of participation, is set forth in the following table:
6
<PAGE>
- ---------------------------------------------- ---------------- ---------------
Participants Corporate Noncorporate
Component Component
- ---------------------------------------------- ---------------- ---------------
Chief Executive Officer of Sponsor 100% -
- ---------------------------------------------- ---------------- ---------------
Chief Operating Officer of Sponsor 100% -
- ---------------------------------------------- ---------------- ---------------
Executive Vice Presidents of Sponsor 75% 25%
- ---------------------------------------------- ---------------- ---------------
Senior Vice Presidents of Sponsor 75% 25%
- ---------------------------------------------- ---------------- ---------------
Department Heads (or equivalent) 50% 50%
- ---------------------------------------------- ---------------- ---------------
Other Participants 50% 50%
- ---------------------------------------------- ---------------- ---------------
a. Corporate Component. The Corporate Component of an Award is
based upon the overall performance of the Sponsor. In the event the conditions
set forth in Section 1 of Article V are met and the Compensation Committee, in
its discretion, determines an appropriate Corporate Factor, that Corporate
Factor shall be multiplied by the portion of a Participant's Target Award
Opportunity attributable to the Corporate Component in order to determine the
percentage of such Participant's Salary which will comprise the Corporate
Component of his or her Award. Notwithstanding the foregoing, if the second
condition set forth in Section 1 of Article V is not fully met, the Compensation
Committee may nevertheless in its discretion determine an appropriate Corporate
Factor and grant a Corporate Component of an Award to the Participants.
b. Noncorporate Component. The Noncorporate Component of an
Award for a Participant is based upon the level of attainment of Company,
business unit/group, departmental and individual Performance Measures.
Performance Measures for each Participant and their relative weight are
determined pursuant to authority granted in Article III hereof.
(i) Performance Levels. There are three levels of
performance related to each of a Participant's Performance Measures:
outstanding, target, and threshold. The specific performance criteria for each
level of a Participant's Performance Measures shall be set forth in
7
<PAGE>
writing prior to the beginning of an applicable Year, or within thirty (30) days
after a Participant first becomes eligible to participate in the Plan, and shall
be determined pursuant to authority granted in Article III hereof. The payout
percentages to be applied to each Participant's Target Award Opportunity are as
follows:
Performance Level Payout Percentage
----------------- -----------------
Outstanding 150%
Target 100%
Threshold 50%
Payout percentages shall be adjusted for performance between the designated
performance levels, provided, however, that performance which falls below the
"Threshold" performance level results in a payout percentage of zero unless the
Chief Executive Officer of Sponsor directs otherwise.
(ii) Determination of Noncorporate Component. In order
to determine a Participant's Noncorporate Component, if any, for a particular
Year, the Chief Executive Officer of Sponsor initially shall determine the
appropriate payout percentage for each of such Participant's Performance
Measures. Thereafter, each payout percentage is multiplied by the percentage
weight assigned to each such Performance Measure and the results added together.
That aggregate amount is multiplied by the Participant's Target Award
Opportunity for the Noncorporate Award Component for the respective Year and the
result is multiplied by the Participant's Salary.
(iii) Change of Job Status. Participants who change
organizations during a Year will have their Noncorporate Component prorated
based upon the Performance Measures achieved in each organization and the length
of time served in each organization. In the
8
<PAGE>
discretion of the Chief Executive Officer of Sponsor, employees may become
Participants during a Year based on promotions and may receive an Award prorated
based on the length of time served in the qualifying job and the Performance
Measures achieved while in the qualifying job.
4. New Participants. Any Award that is earned during the Year of
selection shall be pro rated based on the length of time served in the
qualifying job.
5. Reduction of Award Amount. In the event of documented performance
deficiencies of a Participant during a Year, the Chief Executive Officer of
Sponsor, in his discretion, may reduce the Award payable to such Participant for
such Year.
6. Example. Attached as Exhibit A and incorporated by reference is an
example of the process by which an Award is granted hereunder. Said exhibit is
intended solely as an example and in no way modifies the provisions of this
Article V.
ARTICLE VI
DISTRIBUTION AND DEFERRAL OF AWARDS
-----------------------------------
1. Distribution of Awards. Unless a Participant elects to defer an
award pursuant to the remaining provisions of this Article VI, awards under the
Plan earned during any Year shall be paid in cash in the succeeding Year,
normally no later than March 15 of such succeeding Year.
2. Deferral Election. A Participant may elect to defer the Plan Award
he or she has earned for any Year by completing and submitting to the Vice
President, Human Resources, a deferral election form by the later of (1)
November 30 of the Year in which the Award is earned or (2) the thirtieth (30th)
day after first becoming eligible to participate in the deferral election
provisions of the Plan; provided, however, that for the 1995 Plan Year, deferral
elections shall be
9
<PAGE>
made by no later than November 30, 1995. Such election shall apply to the
Participant's Award, if any, otherwise to be paid as soon as practicable after
the Year during which it was earned. A Participant's deferral election may apply
to 100%, 75%, 50%, or 25% of the Plan Award; provided, however, that in no event
shall the amount deferred be less than $1,000.
The election to defer shall be irrevocable as to the Award earned
during the particular Year.
3. Period of Deferral. At the time of a Participant's deferral
election, a Participant must also select a distribution date. Subject to Section
6, the distribution date may be: (a) any date that is at least five (5) years
subsequent to the date the Plan Award would otherwise be payable, but not later
than the second anniversary of the Participant's Date of Retirement; or (b) any
date that is within two years following the Participant's Date of Retirement.
Subject to Section 6, a Participant may extend the distribution date for one or
more additional Year(s) by making a new deferral election at least one (1) year
before the previously selected distribution date occurs; provided, however, that
in no event shall the subsequent distribution date be a date that is more than
two years beyond the Participant's Date of Retirement.
4. Performance Units. All Awards which are deferred under the Plan
shall be recorded in the form of Performance Units. Each Performance Unit is
generally equivalent to a share of the Sponsor's Common Stock. In converting the
cash award to Performance Units, the number of Performance Units granted shall
be determined by dividing the amount of the Award by 85% of the average value of
the opening and closing price of a share of the Sponsor's Common Stock on the
last trading day of the month preceding the date of the Award. The Performance
Units attributable to the 15% discount from the average value of the Sponsor's
Common Stock shall be referred to as the "Incentive
10
<PAGE>
Performance Units." The Incentive Performance Units and any adjustments or
earnings attributable to those Performance Units shall be forfeited by the
Participant if he or she terminates employment either voluntarily or
involuntarily other than for death or retirement prior to five years from March
15 of the Year in which payment would have been made if the Award had not been
deferred.
5. Plan Accounts. A Plan Deferral Account will be established on behalf
of each Participant, and the number of Performance Units awarded to a
Participant shall be recorded in each Participant's Plan Deferral Account as of
the first of the month coincident with or next following the month in which a
deferral becomes effective. The number of Performance Units recorded in a
Participant's Plan Deferral Account shall be adjusted to reflect any splits or
other adjustments in the Sponsor's Common Stock, the payment of any cash
dividends paid on the Sponsor's Common Stock and the payment of Awards under
this Plan to the Participant. To the extent that any cash dividends have been
paid on the Sponsor's Common Stock, the number of Performance Units shall be
adjusted to reflect the number of Performance Units that would have been
acquired if the same dividend had been paid on the number of Performance Units
recorded in the Participant's Plan Deferral Account on the dividend record date.
For purposes of determining the number of Performance Units acquired with such
dividend, the average of the opening and closing price of the Sponsor's Common
Stock on the payment date of the Sponsor's Common Stock dividend shall be used.
Each Participant shall receive an annual statement of the balance of
his Plan Deferral Account, which shall include the Incentive Performance Units
and associated earnings and adjustments that are subject to being forfeited as
provided above.
11
<PAGE>
6. Payment of Deferred Plan Awards. Subject to Section 4 related to
forfeiture of Incentive Performance Units, Deferred Plan Awards shall be paid in
cash by each Company beginning no later than the next April 1 following the
distribution date or the deferred distribution date specified by the Participant
in accordance with Section 3. To convert the Performance Units in a
Participant's Plan Deferral Account to a cash payment amount, Performance Units
shall be multiplied by the average of the opening and closing price of the
Sponsor's Common Stock on the last trading day preceding the payment of the
Deferred Plan Award. Except as otherwise provided below, deferred amounts will
be paid either in a single lump-sum payment or in up to five (5) annual
payments.
In the event that a Participant elects to receive the deferred Plan
Award in equal annual payments, the amount of the Award to be received in each
year shall be determined as follows:
(a) To determine the amount of the initial annual payment, the
number of Performance Units in the Participant's Plan Deferral Account will be
divided by the total number of annual payments to be received, and the result
will be multiplied by the average of the opening and closing price of the
Sponsor's Common Stock on the last trading day preceding the due date of the
initial payment.
(b) To determine the amount of each successive annual payment,
the Plan Deferral Account balance will be divided by the number of annual
payments remaining, and the result will be multiplied by the average of the
opening and closing price of the Sponsor's Common Stock on the last trading day
preceding the due date of the annual payment.
7. Termination of Employment/Effect on Deferral Election. If the
employment of a Participant terminates prior to the last day of a Year for which
a Plan Award is determined, then any deferral election made with respect to such
Plan Award for such Year shall not become
12
<PAGE>
effective and any Plan Award to which the Participant is otherwise entitled
shall be paid as soon as practicable after the end of the Year during which it
was earned, in accordance with paragraph 1 of this Article VI.
8. Termination of Employment/Acceleration of Deferral. Notwithstanding
the foregoing, if a Participant terminates employment by reason other than death
or Retirement, full payment of all amounts due to the Participant shall be
accelerated and paid on the first day of the month following the date of
termination. Incentive Performance Units shall be subject to forfeiture as
provided in Section 4.
9. Financial Hardship Payments. In the event of a severe financial
hardship occasioned by an emergency, including, but not limited to, illness,
disability or personal injury sustained by the Participant or a member of the
Participant's immediate family, a Participant may apply to receive a
distribution earlier than initially elected. The Chief Executive Officer of
Sponsor or his designee may, in his sole discretion, either approve or deny the
request. The determination made by the Chief Executive Officer of Sponsor will
be final and binding on all parties. If the request is granted, the payments
will be accelerated only to the extent reasonably necessary to alleviate the
financial hardship. Incentive Performance Units shall not be subject to early
distribution under this Section 9 until five years from March 15 of the Year in
which payment would have been made if the Award had not been deferred.
10. Death of a Participant. If the death of a Participant occurs before
a full distribution of the Participant's Plan Deferral Account is made, payment
shall be made to the beneficiary designated by the Participant to receive such
amounts in accordance with the schedule specified in the Participant's Deferral
Election form. Said payment shall be made as soon as practical following
notification that death has occurred. In the absence of any such designation,
payment
13
<PAGE>
shall be made to the personal representative, executor or administrator of the
Participant's estate.
11. Non-Assignability of Interests. The interests herein and the right
to receive distributions under this Article VI may not be anticipated,
alienated, sold, transferred, assigned, pledged, encumbered, or subjected to any
charge or legal process, and if any attempt is made to do so, or a Participant
becomes bankrupt, the interests of the Participant under this Article VI may be
terminated by the Chief Executive Officer of Sponsor, which, in his sole
discretion, may cause the same to be held or applied for the benefit of one or
more of the dependents of such Participant or make any other disposition of such
interests that he deems appropriate.
12. Unfunded Deferrals. Nothing in this Plan, including this Article
VI, shall be interpreted or construed to require the Sponsor or any Company in
any manner to fund any obligation to the Participants, terminated Participants
or beneficiaries hereunder. Nothing contained in this Plan nor any action taken
hereunder shall create, or be construed to create, a trust of any kind, or a
fiduciary relationship between the Sponsor or any Company and the Participants,
terminated Participants, beneficiaries, or any other persons. Any funds which
may be accumulated in order to meet any obligation under this Plan shall for all
purposes continue to be a part of the general assets of the Sponsor or Company;
provided, however, that the Sponsor or Company may establish a trust to hold
funds intended to provide benefits hereunder to the extent the assets of such
trust become subject to the claims of the general creditors of the Sponsor or
Company in the event of bankruptcy or insolvency of the Sponsor or Company. To
the extent that any Participant, terminated Participant, or beneficiary acquires
a right to receive payments from the Sponsor or Company under this Plan, such
rights shall be no greater than the rights of any unsecured general creditor of
the Sponsor or Company.
14
<PAGE>
ARTICLE VII
-----------
TERMINATION OF EMPLOYMENT
-------------------------
A Participant must be actively employed by a Company on the next
January 1 immediately following the Year for which a Plan Award is earned in
order to be entitled to payment of the full amount of any Award for that Year.
In the event the active employment of a Participant shall terminate or be
terminated for any reason before the next January 1 immediately following the
Year for which a Plan Award is earned, such Participant shall receive his or her
Award for the year, if any, in an amount that the Chief Executive Officer of the
Sponsor deems appropriate.
ARTICLE VIII
------------
MISCELLANEOUS
-------------
1. Assignments and Transfers. The rights and interests of a
Participant under the Plan may not be assigned, encumbered or transferred
except, in the event of the death of a Participant, by will or the laws of
descent and distribution.
2. Employee Rights Under the Plan. No Company employee or other person
shall have any claim or right to be granted an Award under the Plan or any other
incentive bonus or similar plan of the Sponsor or any Company. Neither the Plan,
participation in the Plan nor any action taken thereunder shall be construed as
giving any employee any right to be retained in the employ of the Sponsor or any
Company.
15
<PAGE>
3. Withholding. The Sponsor or Company (as applicable) shall
have the right to deduct from all amounts paid in cash any taxes required by law
to be withheld with respect to such cash payments.
4. Amendment or Termination. The Compensation Committee may in
its sole discretion amend suspend or terminate the Plan or any portion thereof
at any time.
5. Governing Law. This Plan shall be construed and governed in
accordance with the laws of the state of North Carolina.
6. Effective Date. This Plan, as amended, shall be effective as
of January 1, 1999.
7. Entire Agreement. This document (including the exhibit
attached hereto and any future amendments to said exhibit that may be made by
the Chief Executive Officer of the Sponsor) sets forth the entire Plan.
16
<PAGE>
EXHIBIT A
(to be supplied)
17
<PAGE>
EXHIBIT B
North Carolina Natural Gas Company
18
<PAGE>
DESIGNATION OF BENEFICIARY
MANAGEMENT INCENTIVE COMPENSATION PLAN
OF
CAROLINA POWER & LIGHT COMPANY
As provided in the MANAGEMENT INCENTIVE COMPENSATION PLAN of Carolina
Power & Light Company, I hereby designate the following person as my beneficiary
in the event of my death before a full distribution of my Deferral Account is
made.
PRIMARY BENEFICIARY:
-------------------------------
-------------------------------
-------------------------------
CONTINGENT BENEFICIARY:
-------------------------------
-------------------------------
-------------------------------
Any and all prior designations of one or more beneficiaries by me under the
MANAGEMENT INCENTIVE COMPENSATION PLAN of Carolina Power & Light Company are
hereby revoked and superseded by this designation. I understand that the primary
and contingent beneficiaries named above may be changed or revoked by me at any
time by filing a new designation in writing with the Sponsor's Human Resources
Department.
DATE:__________________
SIGNATURE OF PARTICIPANT:_________________________________
The Participant named above executed this document in our presence on the date
set forth above
WITNESS: WITNESS:
------------------------ --------------------------
19
EXHIBIT 10B(24)
AMENDED AND RESTATED
SUPPLEMENTAL SENIOR EXECUTIVE RETIREMENT PLAN
OF
CAROLINA POWER & LIGHT COMPANY
Effective January 1, 1984
(As last amended effective March 15, 2000)
<PAGE>
TABLE OF CONTENTS
ARTICLE I - STATEMENT OF PURPOSE
ARTICLE II - DEFINITIONS
Terms 2.01
Affiliated Companies 2.02
Assumed Deferred Vested Pension Benefit 2.03
Assumed Early Retirement Pension Benefit 2.04
Assumed Normal Retirement Pension Benefit 2.05
Board 2.06
Committee 2.07
Company 2.08
Designated Beneficiary 2.09
Early Retirement Date 2.10
Eligible Spouse 2.11
Final Average Salary 2.12
Normal Retirement Date 2.13
Participant 2.14
Pension 2.15
Plan 2.16
Retirement Plan 2.17
Salary 2.18
Service 2.19
Severance Date 2.20
Social Security Benefit 2.21
Spouse's Pension 2.22
Target Early Retirement Benefit 2.23
Target Normal Retirement Benefit 2.24
Target Pre-Retirement Death Benefit 2.25
Target Severance Benefit 2.26
ARTICLE III - ELIGIBILITY AND PARTICIPATION
Eligibility 3.01
Date of Participation 3.02
Duration of Participation 3.03
ARTICLE IV - RETIREMENT BENEFITS
Normal Retirement Benefit 4.01
Early Retirement Benefit 4.02
Surviving Spouse Benefit 4.03
Re-employment of Retired Participant 4.04
<PAGE>
ARTICLE V - PRE-RETIREMENT DEATH BENEFITS
Eligibility 5.01
Amount 5.02
Alternative Benefit 5.03
Commencement and Duration 5.04
ARTICLE VI - SEVERANCE BENEFITS
Eligibility 6.01
Amount 6.02
Commencement and Duration 6.03
Surviving Spouse Benefit 6.04
ARTICLE VII - ADMINISTRATION
Committee 7.01
Voting 7.02
Records 7.03
Liability 7.04
Expenses 7.05
ARTICLE VIII - AMENDMENT AND TERMINATION
ARTICLE IX - MISCELLANEOUS
Non-Alienation of Benefits 9.01
No Trust Created 9.02
No Employment Agreement 9.03
Binding Effect 9.04
Suicide 9.05
Claims for Benefits 9.06
Entire Plan 9.07
ARTICLE X - CONSTRUCTION
Governing Law 10.01
Gender 10.02
Headings, etc. 10.03
Action 10.04
<PAGE>
ARTICLE I
----------
STATEMENT OF PURPOSE
--------------------
This Plan is designed and implemented for the purpose of enhancing the
earnings and growth of Carolina Power & Light Company (the "Sponsor") by
providing to the limited group of senior management employees largely
responsible for such earnings and long-term growth deferred compensation in the
form of supplemental retirement income benefits, thereby increasing the
incentive of such key senior management employees to make the Sponsor and its
Affiliated Companies more profitable. The benefits are normally payable to
Participants upon retirement or death. The terms of the benefits operate in
conjunction with the Participant's benefits payable under the Sponsor's
Supplemental Retirement Plan and are designed to supplement such Supplemental
Retirement Plan benefits and provide the Participant with additional financial
security upon retirement or death.
The Plan is intended to constitute an unfunded retirement plan for a
select group of management or highly compensated employees within the meaning of
Title I of the Employee Retirement Income Security Act of 1974, as amended.
The Sponsor hereby restates and amends the Plan effective March 15, 2000.
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ARTICLE II
----------
DEFINITIONS
-----------
2.01 Terms - Unless otherwise clearly required by the context, the terms
used herein shall have the following meaning. Capitalized terms that
are not defined below shall have the meaning ascribed to them in the
Retirement Plan.
2.02 Affiliated Company shall mean any corporation or other entity that is
required to be aggregated with the Sponsor pursuant to Section 414(b),
(c), (m), or (o) of the Internal Revenue Code of 1996, as amended (the
"Code"), but only to the extent required.
2.03 Assumed Deferred Vested Pension Benefit shall mean the monthly benefit
of the deferred vested Pension to commence on his Normal Retirement
Date payable in the form of an annuity to which a separated Participant
would be entitled under the Retirement Plan, calculated with the
following assumptions based on such Participant's marital status at the
time benefits hereunder commence:
(a) In the case of a Participant with an Eligible Spouse, in the
form of a 50% Qualified Joint and Survivor Annuity as provided
in the Retirement Plan.
(b) In the case of a Participant without an Eligible Spouse, in the
form of a Single Life Annuity as provided in the Retirement
Plan.
(c) Without regard to any other benefit payment option under the
Retirement Plan.
2.04 Assumed Early Retirement Pension Benefit shall mean the monthly benefit
of the normal retirement Pension payable in the form of an annuity to
which a Participant would be entitled under the Retirement Plan at his
Normal Retirement Date, based upon his projected years of Service at
his Normal Retirement Date and upon his Final Average Salary as of his
Early Retirement Date, and calculated with the following assumptions
based upon his marital status at the time benefits hereunder commence:
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(a) In the case of a Participant with an Eligible Spouse, in the
form of a 50% Qualified Joint and Survivor Annuity as provided
in the Retirement Plan.
(b) In the case of a Participant without an Eligible Spouse, in the
form of a Single Life Annuity as provided in the Retirement
Plan.
(c) Without regard to any other benefit payment option under the
Retirement Plan.
2.05 Assumed Normal Retirement Pension Benefit shall mean the monthly
benefit of the normal retirement Pension payable in the form of an
annuity to which a Participant would be entitled under the Retirement
Plan if he retired at his Normal Retirement Date, calculated with the
following assumptions based on his marital status at the time benefits
hereunder commence:
(a) In the case of a Participant with an Eligible Spouse, in the
form of a 50% Qualified Joint and Survivor Annuity as provided
in the Retirement Plan.
(b) In the case of a Participant without an Eligible Spouse, in the
form of a Single Life Annuity as provided in the Retirement
Plan.
(c) Without regard to any other benefit payment option under the
Retirement Plan.
2.06 Board shall mean the Board of Directors of Sponsor.
2.07 Committee shall mean the Committee on Organization and Compensation of
the Board.
2.08 Company shall mean Carolina Power & Light Company or any successor to
it in the ownership of substantially all of its assets, and each
Affiliated Company that, with the consent of the Board adopts the Plan
and is included in Appendix A, as in effect from time to time. Appendix
A shall set forth any limitations imposed on employees of Affiliated
Companies that adopt the Plan, including limitations on "Service,"
notwithstanding any provision of the Plan to the contrary.
2.09 Designated Beneficiary shall mean one or more beneficiaries as
designated by a Participant in writing delivered to the Committee. In
the event no such written designation is made by a Participant or if
such beneficiary shall not be living or in existence at the time for
commencement of payment to any Designated Beneficiary under the Plan,
the Participant shall be deemed to have designated his estate as such
beneficiary.
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2.10 Early Retirement Date shall mean the date on which a Participant who
qualifies for the early retirement benefit of Section 4.02 hereof
retires from the employ of the Company and its affiliated entities.
2.11 Eligible Spouse shall mean the spouse of a Participant who, under the
laws of the State where the marriage was contracted, is deemed married
to that Participant on the date on which the payments from this Plan
are to begin to the Participant, except that for purposes of Articles V
and VI hereof, Eligible Spouse shall mean a person who is married to a
Participant for a period of at least one year prior to his death.
2.12 Final Average Salary shall mean a Participant's average monthly Salary
(as defined in Section 2.18 hereof) during the 36 completed calendar
months of highest compensation within the 120-month period immediately
preceding the earliest to occur of the Participant's death, Severance
Date, Early Retirement Date, or Normal Retirement Date, whichever is
applicable. Provided, however, if a Participant becomes entitled to a
benefit hereunder while under a period of long-term disability under
the Sponsor's Group Insurance Plan, Final Average Salary shall be
determined for the 12 calendar months immediately preceding the
commencement of such period of long-term disability. Provided, further,
in determining average monthly Salary (i) annual bonuses and other
similar payments shall be deemed received in twelve (12) equal payments
beginning with the eleventh preceding month and ending with the month
in which actual payment is made, and (ii) amounts of compensation
deferred under any deferred compensation plan or arrangement shall be
deemed received in the months such payments would have been received
assuming no deferral had occurred. For years of Service granted under
the terms of a written employment agreement as provided under Section
2.19, Salary during each such month is deemed to be zero dollars
($0.00) for purposes of calculating Final Average Salary.
2.13 Normal Retirement Date shall mean the first day of the calendar month
coinciding with or next following the Participant's 65th birthday.
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2.14 Participant shall mean an employee of the Company who is eligible and
is participating in this Plan in accordance with Article III hereof.
2.15 Pension shall mean a level monthly annuity which is payable under the
Retirement Plan as of the Benefit Commencement Date if the Participant
elected an annuity form of benefit.
2.16 Plan shall mean the "Supplemental Senior Executive Retirement Plan of
Carolina Power & Light Company" as contained herein and as it may be
amended from time to time hereafter.
2.17 Retirement Plan shall mean the "Supplemental Retirement Plan of
Carolina Power & Light Company" (as amended effective January 1, 1999)
as it may be amended from time to time hereafter.
2.18 Salary shall mean the sum of:
(1) The annual base compensation paid by the Company to a
Participant, and
(2) annual cash awards made under incentive compensation programs
excluding, however, any payment made under the Sponsor's
Long-Term Compensation Program or the Sponsor's 1997 Equity
Incentive Plan, and
(3) amounts of annual compensation deferred under any deferred
compensation plan or arrangement (including, without limitation,
the "Executive Deferred Compensation Plan," the "Deferred
Compensation Plan for Key Management Employees of Carolina Power
& Light Company," the "Carolina Power & Light Company Management
Deferred Compensation Plan" effective January 1, 2000, and the
"Stock Purchase - Savings Plan of Carolina Power & Light
Company") and which, but for the deferral, would have been
reflected in Internal Revenue Service Form W-2.
2.19 Service shall have the same meaning as "Eligibility Service,"
determined as provided in Sections 2.02 and 3.01 of the Retirement
Plan, plus any additional years of service that may be granted to the
Participant in connection with this Plan under the terms of a written
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employment agreement (or any amendment thereto) entered into between
the Company and the Participant .
2.20 Severance Date shall mean the earlier of:
(a) The date a Participant leaves the employ of the Company and
all affiliated entities other than on account of his death, a
period of long-term disability under the Company's Group
Insurance Plan, or retirement at either his Early Retirement
Date or upon or after his Normal Retirement Date, or
(b) The first anniversary of the date on which a Participant is
first absent from the service of the Sponsor and all
Affiliated Companies, with or without pay, other than on
account of his death, a period of long-term disability under
the Company's Group Insurance Plan, or his retirement at
either his Early Retirement Date or upon or after his Normal
Retirement Date.
If a Participant shall leave the employ of the Company and all
Affiliated Companies under circumstances described in (b) and shall
during such absence (and before the first anniversary of commencement
of said absence) quit or be discharged, his Severance Date shall be the
date he quits or is discharged.
2.21 Social Security Benefit means the monthly amount of benefit which a
Participant is or would be entitled to receive at age 65 as a primary
insurance amount under the federal Social Security Act, as amended,
whether or not he applies for such benefit, and even though he may lose
part or all of such benefit through delay in applying for it, by making
application prior to age 65 for a reduced benefit, by entering into
covered employment, or for any other reason. The amount of such Social
Security Benefit to which the Participant is or would be entitled shall
be estimated by the Committee for the purposes of this Plan as of the
January 1 of the year in which his Severance Date or retirement occurs
on the following basis:
(a) For a Participant entitled to a normal retirement benefit, on
the basis of the federal Social Security Act as in effect on
the January 1 coincident with or next preceding
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his Normal Retirement Date (regardless of any retroactive
changes made by legislation enacted after said January 1);
(b) For a Participant entitled to an early retirement benefit, on
the basis of the federal Social Security Act as in effect on
the January 1 coincident with or next preceding his Early
Retirement Date (regardless of any retroactive change made by
legislation enacted after said January 1), assuming that his
employment, and Salary in effect at his Early Retirement Date,
continued to age 65; or
(c) For a Participant entitled to a severance benefit, on the
basis of the federal Social Security Act as in effect on the
January 1 coincident with or next preceding his Severance Date
(regardless of any retroactive change made by legislation
enacted after said January 1), assuming that his employment,
and Salary in effect at his Severance Date, continued to age
65.
For purposes of the calculations required under paragraphs (a) and (b)
above, if a Participant is disabled under a period of long-term
disability under the Company's Group Insurance Plan, said Social
Security Benefit shall be calculated as if his Salary in effect at the
commencement of such period of long-term disability continued to age
65.
2.22 Spouse's Pension shall mean the actual monthly benefit payable to an
Eligible Spouse under the Retirement Plan, assuming the Eligible Spouse
elected a 50% Joint and Survivor Annuity form of benefit.
2.23 Target Early Retirement Benefit shall mean an amount equal to a
Participant's Final Average Salary determined at his Early Retirement
Date multiplied by four percent (4%) for each projected year of Service
at his Normal Retirement Date up to a maximum of sixty-two percent
(62%).
2.24 Target Normal Retirement Benefit shall mean an amount equal to a
Participant's Final Average Salary determined at his Normal Retirement
Date multiplied by four percent (4%) for each projected year of Service
at his Normal Retirement Date up to a maximum of sixty-two percent
(62%).
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2.25 Target Pre-Retirement Death Benefit shall mean an amount equal to a
deceased Participant's Final Average Salary determined at his death
multiplied by four percent (4%) for each year of Service at his death
up to a maximum of sixty-two percent (62%).
2.26 Target Severance Benefit shall mean an amount equal to a Participant's
Final Average Salary determined at his Severance Date multiplied by
four percent (4%) for each year of Service at his Severance Date up to
a maximum of sixty-two percent (62%).
8
<PAGE>
ARTICLE III
-----------
ELIGIBILITY AND PARTICIPATION
-----------------------------
3.01 Eligibility. Any executive employee of a Company who has served on the
Senior Management Committee of the Sponsor and who has been a Senior
Vice President or above for a minimum period of three (3) years and who
has at least ten (10) years of Service shall be eligible to participate
in this Plan.
3.02 Date of Participation. Each executive who is eligible to become a
Participant under Section 3.01 shall become a Participant on the first
day of the month following the month in which he is first eligible to
participate.
3.03 Duration of Participation. Each executive who becomes a Participant
shall continue to be a Participant until the termination of his
employment with the Company or, if later, the date he is no longer
entitled to benefits under this Plan.
9
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ARTICLE IV
----------
RETIREMENT BENEFITS
-------------------
4.01 Normal Retirement Benefit.
(a) Eligibility. A Participant whose employment with the Company
terminates on or after his Normal Retirement Date shall be
eligible for the normal retirement benefit described in this
Section 4.01.
(b) Amount and Form. The monthly payment hereunder shall be in the
form of a Single Life Annuity if the Participant has no
Eligible Spouse and in the form of a 50% Qualified Joint and
Survivor Annuity if the Participant has an Eligible Spouse.
The eligible Participant's normal retirement benefit shall be
a monthly amount equal to his Target Normal Retirement Benefit
reduced by the sum of (1) his Assumed Normal Retirement
Pension Benefit and (2) his Social Security Benefit.
(c) Commencement and Duration. Monthly normal retirement benefit
payments shall commence at the same time as the eligible
Participant's normal retirement Pension payable from the
Retirement Plan and shall continue in monthly installments
thereafter ending with a payment for the month in which such
eligible Participant's death occurs, unless the benefit is
being paid in the form of a Qualified Joint and Survivor
Annuity, in which case the survivor benefit shall be paid to
the Eligible Spouse, if living, for his or her life. If at the
time of commencement of payment such eligible Participant does
not have an Eligible Spouse the monthly benefit payments shall
be guaranteed for one hundred twenty (120) monthly payments
with any such guaranteed payments remaining at such
Participant's death payable to his Designated Beneficiary.
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4.02 Early Retirement Benefit.
(a) Eligibility. Upon recommendation of the Chief Executive
Officer of the Company and approval of the Committee, a
Participant whose employment with the Company terminates upon
or after his attainment of age fifty-five (55) with at least
fifteen (15) years of Service (except for purposes of
calculating benefits payable under Article V. PRE-RETIREMENT
DEATH BENEFITS and Article VI. SEVERANCE BENEFITS, as
applicable) but prior to his Normal Retirement Date, shall be
eligible for the early retirement benefit described in this
Section 4.02.
(b) Amount and Form. The monthly payment hereunder shall be in the
form of a Single Life Annuity if the Participant has no
Eligible Spouse and in the form of a 50% Qualified Joint and
Survivor Annuity if the Participant has an Eligible Spouse.
The eligible Participant's early retirement benefit shall be a
monthly amount equal to his Target Early Retirement Benefit
reduced by the sum of (1) his Assumed Early Retirement Pension
Benefit and (2) his Social Security Benefit; provided,
however, such benefit will be reduced, where applicable, by
the following:
(i) The amount of 2.5% for each year that such benefit is
received prior to his Normal Retirement Date, and
(ii) If such eligible Participant's projected years of
Service at his Normal Retirement Date are less than
fifteen (15), his Target Early Retirement Benefit and
his Assumed Early Retirement Pension Benefit shall be
calculated based upon his actual years of Service at his
Early Retirement Date rather than upon his projected
years of Service at his Normal Retirement Date.
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<PAGE>
(c) Commencement and Duration. Monthly early retirement benefit
payments shall commence on the first day of the month
following the Participant's attainment of age 65, provided,
such Participant may make written application to the Committee
to have payments commence on the first day of any month
following his Early Retirement Date and the decision of the
Committee, based upon its sole and absolute discretion, to
allow such early commencement of payment shall be final. After
commencement of payment, said early retirement benefit
payments shall continue in monthly installments thereafter
ending with a payment for the month in which such eligible
Participant's death occurs, unless the benefit is being paid
in the form of a Qualified Joint and Survivor Annuity, in
which case the survivor benefit shall be paid to the Eligible
Spouse, if living, for his or her life. If at the time of
commencement of payment such eligible Participant does not
have an Eligible Spouse, the monthly benefit payments shall be
guaranteed for one hundred twenty (120) monthly payments with
any such guaranteed payments remaining at such Participant's
death payable to his Designated Beneficiary.
4.03 Surviving Spouse Benefit. The surviving Eligible Spouse of a
Participant who is receiving a Qualified Joint and Survivor Benefit as
a normal retirement benefit or as an early retirement benefit shall be
eligible for the surviving spouse benefit upon the death of the
Participant for the duration of the Eligible Spouse's life.
4.04 Re-employment of Retired Participant. A retired Participant receiving
or eligible to receive the retirement benefits described in Sections
4.01 and 4.02 hereof who is re-employed by a Company shall be
ineligible to again participate in this Plan.
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ARTICLE V
PRE-RETIREMENT DEATH BENEFITS
5.01 Eligibility. A Participant's surviving Eligible Spouse shall be
eligible for the pre-retirement death benefit as described in this
Article V if such Participant dies while in the employ of the Company
with 10 or more years of Service.
5.02 Amount. Such surviving Eligible Spouse shall be entitled to a monthly
pre-retirement death benefit payable in the form of an annuity in an
amount equal to the difference, if any, between (a) forty percent (40%)
of the Target Pre-Retirement Death Benefit and (b) the Spouse's
Pension.
5.03 Alternative Benefit. If greater than the monthly benefit of Section
5.02 hereof, the surviving Eligible Spouse of a Participant who dies
while in the employ of the Company after attaining age fifty-five (55)
with ten (10) years of Service shall be entitled to a monthly
pre-retirement death benefit equal to fifty percent (50%) of the early
retirement benefit the Participant would have been entitled to receive
under Section 4.02 hereof (calculated using both reductions, where
applicable, in subsections 4.02(b)(i) and 4.02(b)(ii)) as if he had
retired immediately prior to his death with the recommendation of the
Chief Executive Officer and approval of the Committee.
5.04 Commencement and Duration. The surviving Eligible Spouse's monthly
pre-retirement death benefit payments shall commence in the month
following the Participant's death and shall be paid in monthly
installments thereafter ending with a payment for the month in which
such surviving Eligible Spouse's death occurs.
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ARTICLE VI
SEVERANCE BENEFITS
6.01 Eligibility. Upon his termination of employment with the Company at his
Severance Date, a Participant who has completed ten (10) or more years
of Service shall be eligible for one of the severance benefits
described in this Article VI.
6.02 Amount.
(a) If at his Severance Date such eligible Participant is not
entitled to a deferred vested Pension pursuant to Section 5.03
of the Retirement Plan or an early retirement Pension pursuant
to Section 5.02 of the Retirement Plan, his severance benefit
shall be a monthly amount equal to his Target Severance
Benefit reduced by his Social Security Benefit.
(b) If at his Severance Date such eligible Participant is entitled
to a deferred vested Pension pursuant to Section 5.03 of the
Retirement Plan, his severance benefit shall be a monthly
amount equal to his Target Severance Benefit reduced by the
sum of (1) his Assumed Deferred Vested Pension Benefit and (2)
his Social Security Benefit.
(c) If at his Severance Date such eligible Participant is entitled
to an early retirement Pension pursuant to Section 5.02 of the
Retirement Plan, his severance benefit shall be a monthly
amount equal to his Target Severance Benefit reduced by the
sum of (1) his Assumed Early Retirement Pension Benefit and
(2) his Social Security Benefit; provided, however, such
Assumed Early Retirement Pension Benefit shall be calculated
based upon his actual years of Service at his Severance Date
rather than upon his projected years of Service at his Normal
Retirement Date.
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6.03 Commencement and Duration. Monthly severance benefit payments shall
commence on the eligible Participant's Normal Retirement Date and shall
continue in monthly installments thereafter ending with a payment for
the month in which such eligible Participant's death occurs.
6.04 Surviving Spouse Benefit.
(a) Eligibility. The surviving Eligible Spouse of a Participant
who is receiving or who dies after attaining age fifty-five
(55) entitled to receive a severance benefit hereunder shall
be eligible for the surviving spouse benefit described in this
Section 6.04.
(b) Amount. Such surviving Eligible Spouse shall be entitled to a
monthly surviving spouse benefit in an amount equal to fifty
percent (50%) of the severance benefit which the deceased
Participant was receiving or entitled to receive at his Normal
Retirement Date under either Section 6.02(a) or 6.02(b) hereof
on the day before his death.
(c) Commencement and Duration. The monthly surviving spouse
benefit payment shall commence in the month following the
Participant's death and shall be paid in monthly installments
thereafter ending with a payment for the month in which such
surviving Eligible Spouse's death occurs.
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ARTICLE VII
------------
ADMINISTRATION
--------------
7.01 Committee. This Plan shall be administered by the Committee. The
Committee shall have all powers necessary to enable it to carry out its
duties in the administration of the Plan. Not in limitation, but in
application of the foregoing, the Committee shall have the duty and
power to determine all questions that may arise hereunder as to the
status and rights of Participants in the Plan.
7.02 Voting. The Committee shall act by a majority of the number then
constituting the Committee, and such action may be taken either by vote
at a meeting or in writing without a meeting.
7.03 Records. The Committee shall keep a complete record of all its
proceedings and all data relating to the administration of the Plan.
The Committee shall select one of its members as a Chairman. The
Committee shall appoint a Secretary to keep minutes of its meetings and
the Secretary may or may not be a member of the Committee. The
Committee shall make such rules and regulations for the conduct of its
business as it shall deem advisable.
7.04 Liability. To the extent permitted by law, no member of the Committee
shall be liable to any person for any action taken or omitted in
connection with the interpretation and administration of this Plan
unless attributable to his own gross negligence or willful misconduct.
The Sponsor shall indemnify the members of the Committee against any
and all claims, losses, damages, expenses, including counsel fees,
incurred by them, and any liability, including any amounts paid in
settlement with their approval, arising from their action or failure to
act, except when the same is judicially determined to be attributable
to their gross negligence or willful misconduct.
7.05 Expenses. The cost of payments from this Plan and the expenses of
administering the Plan shall be borne by each Company with respect to
its own employees.
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ARTICLE VIII
------------
AMENDMENT AND TERMINATION
-------------------------
The Sponsor reserves the right, at any time or from time to time, by action of
its Board , to modify or amend in whole or in part any or all provisions of the
Plan. In addition, the Sponsor reserves the right by action of its Board to
terminate the Plan in whole or in part. Provided, however, any such
modification, amendment or termination shall not reduce benefits accrued at such
time nor increase vesting requirements with respect to such accrued benefits.
17
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ARTICLE IX
----------
MISCELLANEOUS
-------------
9.01 Non-Alienation of Benefits. No right or benefit under the Plan shall be
subject to anticipation, alienation, sale, assignment, pledge,
encumbrance, or charge, and any attempt to anticipate, alienate, sell,
assign, pledge, encumber, or charge any right or benefit under the Plan
shall be void. No right or benefit hereunder shall in any manner be
liable for or subject to the debts, contracts, liabilities or torts of
the person entitled to such benefits. If the Participant or Eligible
Spouse shall become bankrupt, or attempt to anticipate, alienate, sell,
assign, pledge, encumber, or charge any right hereunder, then such
right or benefit shall, in the discretion of the Committee, cease and
terminate, and in such event, the Committee may hold or apply the same
or any part thereof for the benefit of the Participant or his spouse,
children, or other dependents, or any of them, in such manner and in
such amounts and proportions as the Committee may deem proper.
9.02 No Trust Created. The obligations of the Sponsor and each Company to
make payments hereunder shall constitute a liability of the Sponsor and
each Company, as the case may be, to a Participant. Such payments shall
be made from the general funds of the Sponsor or a Company, and the
Sponsor or a Company shall not be required to establish or maintain any
special or separate fund, or purchase or acquire life insurance on a
Participant's life, or otherwise to segregate assets to assure that
such payment shall be made, and neither a Participant nor Eligible
Spouse shall have any interest in any particular asset of the Sponsor
or a Company by reason of its obligations hereunder. Nothing contained
in the Plan shall create or be construed as creating a trust of any
kind or any other fiduciary relationship between the Sponsor, a Company
and a Participant or any other person.
9.03 No Employment Agreement. Neither the execution of this Plan nor any
action taken by the Sponsor or a Company pursuant to this Plan shall be
held or construed to confer on a Participant any legal right to be
continued as an employee of the Sponsor or a Company
18
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in an executive position or in any other capacity whatsoever. This Plan
shall not be deemed to constitute a contract of employment between the
Sponsor or a Company and a Participant, nor shall any provision herein
restrict the right of any Participant to terminate his employment with
the Sponsor or a Company.
9.04 Binding Effect. Obligations incurred by the Sponsor or a Company
pursuant to this Plan shall be binding upon and inure to the benefit of
the Sponsor or a Company, its successors and assigns, and the
Participant or his Eligible Spouse.
9.05 Suicide. No benefit shall be payable under the Plan to a Participant or
Eligible Spouse where such Participant dies as a result of suicide
within two (2) years of his commencement of participation herein.
9.06 Claims for Benefits. Each Participant or Eligible Spouse must claim any
benefit to which he is entitled under this Plan by a written
notification to the Committee. If a claim is denied, it must be denied
within a reasonable period of time, and be contained in a written
notice stating the following:
A. The specific reason for the denial.
B. Specific reference to the Plan provision on which the denial
is based.
C. Description of additional information necessary for the
claimant to present his claim, if any, and an explanation of
why such material is necessary.
D. An explanation of the Plan's claims review procedure.
The claimant will have 60 days to request a review of the denial by the
Committee, which will provide a full and fair review. The request for
review must be in writing delivered to the Committee. The claimant may
review pertinent documents, and he may submit issues and comments in
writing.
The decision by the Committee with respect to the review must be given
within 60 days after receipt of the request, unless special
circumstances require an extension (such as for a hearing). In no event
shall the decision be delayed beyond 120 days after receipt of the
19
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request for review. The decision shall be written in a manner
calculated to be understood by the claimant, and it shall include
specific reasons and refer to specific Plan provisions as to its
effect.
9.07 Entire Plan. This document and any amendments contain all the terms and
provisions of the Plan and shall constitute the entire Plan, any other
alleged terms or provisions being of no effect.
20
<PAGE>
ARTICLE X
----------
CONSTRUCTION
------------
10.01 Governing Law. This Plan shall be construed and governed in
accordance with the laws of the State of North Carolina, to the
extent not preempted by Federal Law.
10.02 Gender. The masculine gender, where appearing in the Plan, shall be
deemed to include the feminine gender, and the singular may include
the plural, unless the context clearly indicates to the contrary.
10.03 Headings, etc. The cover page of this Plan, the Table of Contents and
all headings used in this Plan are for convenience of reference only
and are not part of the substance of this Plan.
10.04 Action. Any action under this Plan required or permitted by the
Sponsor shall be by action of its Board or its duly authorized
designee.
21
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APPENDIX A
----------
North Carolina Natural Gas Company ("NCNG"); provided that for all
purposes of the Plan, Service for an employee of NCNG on December 31, 1999 (as
defined in Section 2.19) shall include employment only with NCNG (or another
adopting Company) on or after January 1, 2000; and further provided that the
accrued benefit calculated under Sections 2.03, 2.04 and 2.05 shall not include
the "Accrued Benefit" under Supplement A, Paragraph A-2 of the Retirement Plan,
attributable to the NCNG Employees Pension Plan.
22
EXHIBIT 10B(32)
April 27, 1999
Mr. Sherwood H. Smith, Jr.
408 Drummond Drive
Raleigh, NC 27609
Dear Sherwood:
This letter will confirm the discussion we have recently had concerning your
upcoming retirement as Chairman of the Board of Directors of Carolina Power &
Light Company. Your current Agreement with the Company anticipates that you will
not serve as Chairman after the May 1999 Annual Meeting, and your current term
as a Director expires at that meeting. We have agreed that you will accept a
nomination at the May 1999 meeting to be a Director in Class II and to serve a
one-year term expiring in 2000. We also anticipate that at the Board meeting in
May you will be elected to the honorary position of Chairman Emeritus.
The Agreement states that you will continue to provide various services to the
Company through September 30, 1999. We also appreciate your commitment to be
available to continue to provide these types of services to the Company after
September 30, 1999. These additional services will be as requested by, and
performed under the general direction of, CP&L's Chief Executive Officer, as
agreed to by you. The compensation for such services will be as approved by the
Chief Executive Officer. In addition, you will receive the standard compensation
for service as an outside Director after September 30, 1999, until your term as
Director expires. (The non-compete provisions of your Agreement will, of course,
continue.)
The Company will continue to provide the services and benefits described in your
Agreement, including a home alarm and security service, a company network
telephone, and facsimile equipment at your residence, and a car telephone. The
Company will also provide you with its standard car allowance for three years
following the expiration of the Agreement (through September 30, 2002). Finally,
as noted in the Agreement, the Company will also continue to provide office and
secretarial support. We are currently arranging accommodations in One Hannover
Square with the intent of relocating your office in June. These services and
appropriate office accommodations will be supplied until you attain the age of
80. After such time, if services or accommodations of any kind might be
appropriate, the matter will be determined at that time by the Chief Executive
Officer.
I look forward to having you continue on the Board of Directors for another
year.
Very truly yours,
/s/William Cavanaugh III
William Cavanaugh III
Agreed: /s/Sherwood H. Smith, Jr.
-------------------------
Sherwood H. Smith, Jr.
EXHIBIT 10B(33)
EMPLOYMENT AGREEMENT
BETWEEN
NORTH CAROLINA NATURAL GAS CORPORATION
AND
CALVIN B. WELLS
JULY 15, 1999
<PAGE>
EMPLOYMENT AGREEMENT
--------------------
EMPLOYMENT AGREEMENT ("Agreement"), dated as of the July 15, 1999,
between North Carolina Natural Gas Corporation ("NCNG" or "Company"), a Delaware
Corporation headquartered in Fayetteville, North Carolina and a subsidiary of
Carolina Power & Light Company ("CP&L"), and Calvin B. Wells ("Wells").
RECITALS
---------
1. On or around July 15, 1999 ("Closing Date"), North Carolina Natural
Gas Corporation will, through a merger transaction, become a wholly owned
subsidiary of Carolina Power & Light ("CP&L"). NCNG, as it existed prior to this
merger, will be referred to herein as "Pre-Merger NCNG."
2. Wells was employed as Chief Executive Officer of Pre-Merger NCNG and
entered into an Employment Agreement with Pre-Merger NCNG on September 11, 1985
("Prior Agreement").
3. NCNG and Wells wish to enter into an employment relationship whereby
Wells will be employed as Chief Executive Officer of NCNG after the Closing
Date.
4. NCNG and Wells wish to rescind his Prior Agreement and enter into
this new Employment Agreement which will supersede all prior agreements on the
subject matter.
5. The parties wish to enter into this Agreement to set forth certain
terms related to that relationship.
PROVISIONS
NOW, THEREFORE, in consideration of the mutual covenants and promises
contained herein and for other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged and accepted, the parties hereto
hereby agree as follows:
1. TERM OF EMPLOYMENT.
------------------
(a). Employment. The Company hereby agrees to employ Wells,
and Wells hereby accepts employment with NCNG, for the Employment Term stated
herein, subject to the terms and conditions hereof.
(b). Employment Term. Unless sooner terminated in accordance
with the provisions of Section 6, Wells' term of employment with NCNG under this
Agreement (the "Employment Term") shall commence on the Closing Date
("Employment Date"), and shall
1
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continue until July 15, 2002. Should Wells' employment with NCNG continue past
July 15, 2002, then such employment shall not be subject to this Employment
Agreement.
2. RESPONSIBILITIES; OTHER ACTIVITIES.
----------------------------------
Wells shall occupy the position of Chief Executive Officer of
NCNG and shall undertake the general responsibilities and duties of such
position as directed by NCNG's Board of Directors. During the Employment Term,
Wells shall perform faithfully the duties of Wells' position, devote all of
Wells' working time and energies to the business and affairs of NCNG and shall
use Wells' best efforts, skills and abilities to promote NCNG.
3. SALARY.
------
As compensation for the services to be performed hereunder:
Wells will be paid a salary at the annual rate of Two Hundred Sixty Seven
Thousand Three Hundred Dollars ($267,300) (less applicable withholdings)
beginning on the Employment Date. Annual salary for each subsequent year of the
Employment Term shall be subject to adjustment by the NCNG Board of Directors at
its discretion, provided that Wells' annual salary shall not be less than
$267,300.00. Annual salary shall be deemed earned proportionally as Wells
performs services over the course of the Salary Year. Payments of annual salary
shall be made, except as otherwise provided herein, in accordance with NCNG's
standard payroll policies and procedures.
4. PRIOR AGREEMENT.
----------------
The parties agree that the Prior Agreement between Pre-Merger
NCNG and Wells dated September 11, 1985 is no longer in effect and that this
Employment Agreement supersedes Wells' Prior Agreement with Pre-Merger NCNG.
5. BENEFITS.
--------
During the Employment Term, Wells shall be entitled to
participate in all Company sponsored benefit programs as NCNG or CP&L may have
in effect in accordance with their terms. Provided, however, that nothing
contained in this Agreement shall require NCNG or CP&L to continue to offer such
benefits or programs or to limit NCNG's or CP&L's absolute right to modify or
eliminate these benefits.
(a). Existing Pre-Merger NCNG Plans. Wells will continue
participating in the following existing Pre-Merger NCNG Plans until December 31,
1999, in accordance with their terms: North Carolina Natural Gas Executive
Pension Restoration Plan, North Carolina Natural Gas Employees' Pension Plan,
North Carolina Natural Gas 401(k) Plan, and all other health and welfare plans
as described in the existing Pre-Merger NCNG Handbook, in which Wells is
eligible to participate. Wells' rights to benefits under these Plans will be
based upon the terms of these Plans.
2
<PAGE>
(b). Terminating Pre-Merger NCNG Plans. The parties
acknowledge that the following Pre-Merger North Carolina Natural Gas plans will
terminate, in accordance with their terms, on or around the Closing Date: the
NCNG Long Term Incentive Plan; the NCNG Annual Incentive Plan; the NCNG Employee
Stock Purchase Plan; and the NCNG Key Employee Stock Option Plan. Wells' rights
to benefits in those plans will be based upon the terms of those plans.
(c). CP&L Plans and Post-Merger NCNG Plans. Wells will be
eligible to participate in the following benefit plans subject to their terms:
(i). Management Incentive Compensation Program. Wells
will be eligible to participate in the CP&L Management Incentive Compensation
Program (MICP) beginning in 2000, for which payment will be made on or before
March 31, 2001, in accordance with the terms of the plan. Pursuant to the terms
of the MICP, Wells' target compensation under such program will be approximately
35% of base salary earnings. Wells will be entitled to a 1999 Bonus for the
remainder of 1999 to be calculated under the terms of the CP&L MICP and prorated
accordingly.
(ii). Long Term Incentives. Wells will be eligible to
participate in the CP&L Performance Share Sub-Plan under the 1997 Equity
Incentive Plan in accordance with the terms of the plan. Wells' participation in
this plan shall begin January 1, 2000.
(iii). Restricted Stock Agreement. NCNG and Wells
have entered into a Restricted Stock Agreement effective July 15, 1999.
(iv). Management Deferred Compensation Plan. Wells
will be eligible to participate in CP&L's management Deferred Compensation Plan
in accordance with the terms of the plan. Wells' participation in this plan
shall begin January 1, 2000.
(v). Supplemental Retirement Plan. Wells will be
eligible for participation in CP&L's Supplemental Retirement Plan (SRP), subject
to its terms. Wells' participation in this plan shall begin January 1, 2000.
Wells will also be eligible to participate in the CP&L Restoration Retirement
Plan on January 1, 2000, subject to its terms.
(vi). Executive Permanent Life Insurance Program.
Wells shall be eligible to participate in CP&L's Executive Permanent Life
Insurance Program, subject to its terms. Wells' participation in this plan shall
begin January 1, 2000.
(vii). Personal Accident Insurance Program. Wells
shall be eligible to participate in CP&L's Personal Accident Insurance Program,
subject to its terms. Wells' participation in this plan shall begin January 1,
2000.
(viii). Stock Purchase Savings Plan. Wells shall be
eligible to participate in CP&L's Stock Purchase Savings Plan, subject to its
terms. Wells' participation in this plan shall begin January 1, 2000.
3
<PAGE>
(ix). Financial/ Estate Planning. Consistent with
CP&L's practice with respect to other senior executives, Wells will be
reimbursed for financial and estate planning including financial planning and
tax preparation. Wells shall be immediately eligible for this benefit.
(x). Choice Benefits Program. Wells shall be eligible
to participate in CP&L's Choice Benefits Program, subject to its terms. Wells'
participation in this program shall begin January 1, 2000.
(xi). Vacation. Wells shall be entitled to five (5)
weeks of paid vacation days beginning January 1, 2000.
(xii). Holiday. Wells will be eligible for ten (10)
paid holidays in each calendar year as provided in the NCNG Handbook.
(xiii). Automobile Allowance. Wells will be eligible
to receive an automobile allowance of $1350 per month (less withholdings)
subject to the terms of NCNG's policies. Wells will also be eligible for a
cellular phone and reserved parking at NCNG's expense. Wells shall be eligible
for his automobile allowance at the expiration of his current automobile lease.
(xiv). Annual Physical. NCNG will pay for an annual
physical examination by a physician of Wells' choice beginning January 1, 2000.
(xv). Capital City Club. NCNG will pay an initiation
fee and monthly dues for a membership at the Capital City Club for Wells. Wells
shall be immediately eligible for this benefit.
(xvi). Airline Club Membership. NCNG will provide
airline club membership in accordance with NCNG policy. Wells shall be
immediately eligible for this benefit.
(xvii). Country Club Membership. At Wells' option, if
joined, NCNG will pay an initiation fee and monthly dues for a membership for
Wells at a country club approved by the NCNG Board of Directors. Business
related expenses will be reimbursed consistent with NCNG's expense account
guidelines. Wells shall be immediately eligible for this benefit.
(xviii). Personal Computer. NCNG will provide a
personal computer to Wells to be used at his personal residence. Wells shall be
immediately eligible for this benefit.
4
<PAGE>
(d). Funding of Benefits under NCNG Executive Pension
Restoration Plan.
(i). Under the NCNG Restoration Pension Plan as
referenced in Section 5(a), Wells shall be entitled to benefits that shall have
accrued thereunder through December 31, 1999. As further provided in the Plan,
such benefits are payable from the general assets of NCNG.
(ii). Conditions for Trust. NCNG agrees to establish
a trust, as described in Section 5(d)(iii) below, to fund the payment of
benefits to Wells under NCNG's Executive Pension Restoration Plan in the event
that:
(aa). A change-in-control of NCNG or CP&L
occurs; or
(bb). Wells retires under the NCNG
Employee's Pension Plan or CP&L's Supplemental Retirement Plan (as applicable).
Retirement by Wells shall be deemed to have occurred in the event that his
employment is terminated with NCNG and he becomes eligible to begin receiving
benefits under the NCNG Executive Pension Restoration Plan.
(iii). Trust. Should the conditions specified in
Section 5(d)(ii) transpire, and should NCNG thereby be required to establish a
trust as provided therein, such trust shall be:
(aa). A trust of which NCNG is the grantor,
within the meaning of subpart E, Part I, subchapter J, chapter 1, subtitle A of
the Internal Revenue Code;
(bb). A trust under which Wells is a
beneficiary as of his retirement date or as of the change-in-control date (as
applicable); and
(cc). A trust the assets of which shall be
subject to the claims of NCNG's general creditors in accordance with Internal
Revenue Service Revenue Procedure 92-64.
(iv). Further Modifications. Nothing in this
Agreement shall in any way limit or prohibit NCNG from amending or terminating
NCNG's Employee's Pension Plan, CP&L's Supplemental Retirement Plan, NCNG's
Executive Pension Restoration Plan, or any other benefit plan of NCNG or CP&L.
(v). Change-in-Control.
(aa). Defined. A Change-in-Control of NCNG
or CP&L shall be deemed to have occurred only in the event that any one of the
following circumstances or conditions transpires:
(i). The acquisition by any person
(including a group, within the meaning of Section 13(d) or 14(d)(2) of the
Securities Exchange Act of 1934, as amended) of beneficial ownership of 15
percent or more of the NCNG's or CP&L's then outstanding voting securities;
5
<PAGE>
(ii). A tender offer is made and consummated
for the ownership of 51 percent or more of NCNG's or CP&L's then outstanding
voting securities;
(iii). The first day on which less than 66
2/3 percent of the total membership of the Board of Directors of NCNG or CP&L
are Continuing Directors of either NCNG or CP&L ("Continuing Directors" being
members of such Board as of the effective date of this Agreement), provided,
however, that any person becoming a director subsequent to such date whose
election or nomination for election was supported by 75 percent or more of the
directors who then comprised Continuing Directors shall be considered to be a
Continuing Director); or
(iv). Approval by the stockholders of the
NCNG or CP&L of a merger, consolidation, liquidation or dissolution of the NCNG
or CP&L, or of the sale of all or substantially all of the assets of NCNG or
CP&L;
(bb). Holding Company or Structural
Reorganization. Movement of NCNG or CP&L to a holding company structure,
issuance of stock to the shareholders of CP&L or any holding company, or any
other corporate reorganization among affiliated companies whereby the ultimate
ownership of NCNG does not materially change as a result of a the transaction
shall not be deemed to be a Change-in-Control.
(cc). Effective Date for Change-in-Control.
A Change-in-Control shall not be deemed to have occurred until Wells receives
written certification from CP&L's President and Chief Executive Officer or, in
the event of his or her inability to act, CP&L's Chief Financial Officer, or any
Executive or Senior Vice President of the CP&L that one of the events set forth
in Section 5(d)(v)(aa) above has occurred. The officers referred to in the
previous sentence shall be those officers in office immediately prior to the
occurrence of one of the events set forth above in Section 5(d)(v)(aa). Any
determination that such an event has occurred shall, if made in good faith on
the basis of information available at that time, be conclusive and binding on
NCNG and Wells and Wells' beneficiaries for all purposes of this Agreement.
6. TERMINATION OF EMPLOYMENT.
-------------------------
(a). The employment relationship between Wells and NCNG may be
terminated by either NCNG or Wells with or without advance notice and may be
terminated with or without cause as defined below.
(b). Termination Without Cause or Change in Control. If Wells'
employment is terminated before the end of the Employment Term Without Cause or
as a result of a Change in Control (as defined in Section 5(d)) of NCNG, then
Wells will be provided with severance benefits as described below, subject to
paragraph 6(h).
6
<PAGE>
(i). Severance Benefits. In accordance with a
termination under this paragraph 6(b), and subject to paragraph 6(h), Wells
shall be entitled to the benefits described below. All payments shall be subject
to required payroll withholdings, including any withholdings for excise taxes
for parachute payments. In addition, Wells acknowledges that he is liable for
all federal and state income and excise taxes due on these severance or other
payments from NCNG.
(aa). Salary. Wells shall be entitled to
continuation of his then current base annual salary for two (2) years and eleven
(11) months following such termination, paid on a semi-monthly basis. Provided,
however, that if Wells is re-employed before the expiration of the two (2) years
and eleven (11) months period following termination, remaining severance shall
be reduced to the difference, if any, between the salary continued hereunder and
the salary in the new position.
(bb). Welfare Benefit Plans and 401(k) Plan.
NCNG shall pay Wells a monthly sum to compensate Wells for the employer-paid
portion of medical, life, AD&D and disability coverage and for the loss of the
company match under the 401(k) plan. Such sum shall be grossed up to cover state
and federal income taxes, but not any excise taxes due for parachute payments
which may apply. Provided, however, that these payments shall cease sixty (60)
days following Wells' re-employment before the end of the two (2) year and
eleven (11) month period following termination. Upon re-employment, NCNG shall
have no further obligation to Wells under this paragraph 6(b)(i)(bb).
(cc). Retirement Plan. In order to
compensate Wells for loss of pension benefits, NCNG shall calculate a "make up"
pension benefit. This "make up" pension benefit shall equal the value which
would have been added to Wells' pension benefit, under the retirement plan in
which he is participating at the time of termination, had his employment been
continued for two (2) years and eleven (11) months beyond the termination date,
or to the date sixty (60) days following Wells' re-employment, whichever is
earlier. The "make up" pension benefit shall be calculated within a reasonable
period of time following such date. The net present value of the "make up"
pension benefit (less applicable withholdings) shall be payable, in semi-monthly
payments, over a five (5) year period beginning on the first of the month
following such calculation.
(i). Calculation. If Wells' employment is
terminated under this paragraph on or before December 31, 1999, then the "make
up" pension benefits will be calculated based upon the final average pay as it
would have been determined under the NCNG Employees' Pension Plan and the North
Carolina Natural Gas Executive Pension Plan as of the date of termination. If
Wells' employment is terminated on or after January 1, 2000, then this "make up"
pension benefit shall be calculated based upon the base salary as determined
under the CP&L Supplemental Retirement Plan and the CP&L Restoration Retirement
Plan as of the date of termination.
(dd). Re-employment. Wells acknowledges that
benefits under paragraph 6(b) are affected by his re-employment before the
expiration of two (2) years and
7
<PAGE>
eleven (11) months from the date of termination. Wells agrees that he shall
provide written notice to NCNG of any such re-employment within fourteen (14)
days of the date re-employment commences. Such notice shall include the terms of
employment, including start date, salary, benefit availability, and other
information as may be requested by the NCNG Board of Directors. Such notice
shall be delivered to: Vice President, Human Resources, Carolina Power & Light
Company, P. O. Box 1551, Raleigh, North Carolina, 27602. For purposes of this
Agreement, re-employment shall include, but not be limited to, work as an
employee, agent, consultant, independent contractor, or in any other capacity,
for an employer, firm, or other entity, or for one's own business.
(c). Constructive Termination. If Wells is reassigned to
another position with significantly and materially reduced responsibilities, or
his annual salary is reduced by 15% or more, then, at Wells' option, Wells may
deem such action to be a Constructive Termination. Should Wells wish to deem
such action a Constructive Termination, then Wells must notify, in writing, the
NCNG Board of Directors within 30 days of the date Wells received notification
of the change in his duties or salary. Should Wells declare such action to be a
Constructive Termination, then he shall be entitled to the benefits described in
paragraph 6(b), subject to paragraph 6(h).
(d). Voluntary Termination - If Wells terminates his
employment voluntarily for any reason at any time, then he shall be eligible to
retain all benefits under existing benefit programs which have vested pursuant
to the terms of those programs, but he shall not be entitled to any form of
salary continuance or any form of severance benefit.
(e). Termination for Cause - The Company may elect at any time
to terminate Wells' employment immediately hereunder and remove Wells from
employment for Cause. For purposes of this paragraph 6, cause for the
termination of employment shall be defined as: (i) the willful and continued
failure by him substantially to perform his duties with the Company (other than
any such failure resulting from his incapacity due to physical or mental
illness), or (ii) the willful engaging by him in misconduct which is materially
injurious to the Company, monetarily or otherwise. Upon the termination of
Wells' employment for Cause, NCNG shall have no further obligation to Wells
under this Agreement except as specifically provided in this Agreement. Upon
such termination, Wells shall be entitled to all earned but unpaid salary
accrued to the date of termination. Any continued rights and benefits Wells, or
Wells' legal representatives, may have under employee benefit plans and programs
of NCNG upon Wells' termination for cause, if any, shall be determined in
accordance with the terms and provisions of such plans and programs.
(f). Termination Due to Death. In the event of the death of
Wells at any time during the Employment Term, Wells' employment hereunder shall
terminate and NCNG shall have no further obligation to Wells under this
Agreement except as specifically provided in this Agreement. Wells' estate shall
be entitled to receive all earned but unpaid salary accrued to the date of
termination. Any rights and benefits Wells, or Wells' estate or other legal
representatives, may have under employee benefit plans and programs of NCNG upon
Wells'
8
<PAGE>
death during the Employment Term, if any, shall be determined in accordance with
the terms and provisions of such plans and programs.
(g). Termination Due to Medical Condition.
(i). At any time NCNG may terminate Wells' employment
hereunder, subject to the Americans With Disabilities Act or other applicable
law, due to medical condition if (i) for a period of 180 consecutive days during
the Employment Term, Wells is totally and permanently disabled as determined in
accordance with the Company's long-term disability plan, if any, as in effect
during such time or (ii) at any time during which no such plan is in effect,
Wells is substantially unable to perform Wells' duties hereunder because of a
medical condition for a period of 180 consecutive days during the Employment
Term.
(ii). Upon the termination of Wells' employment due
to medical condition, NCNG shall have no further obligation to Wells under this
Agreement except as specifically provided in this Agreement. Upon such
termination, Wells shall be entitled to all earned but unpaid salary accrued to
the date of termination. Any continued rights and benefits Wells, or Wells'
legal representatives, may have under employee benefit plans and programs of
NCNG upon Wells' termination due to medical condition, if any, shall be
determined in accordance with the terms and provisions of such plans and
programs.
(h). Release of Claims - In order to receive continuation of
salary and benefits under this paragraph 6, Wells agrees to execute a written
release of all claims against NCNG, and its employees, officers, directors,
subsidiaries and affiliates, on a form acceptable to NCNG.
7. ASSIGNABILITY.
-------------
No rights or obligations of Wells under this Agreement may be
assigned or transferred by Wells, except that (a) Wells' rights to compensation
and benefits hereunder may be transferred by will or laws of intestacy to the
extent specified herein and (b) Wells' rights under employee benefit plans or
programs described in Section 5 may be assigned or transferred in accordance
with the terms of such plans or programs, or regular practices thereunder. NCNG
may assign or transfer its rights and obligations under this Agreement.
8. CONFIDENTIALITY. Wells will not disclose the terms of this Agreement
except (i) to financial and legal advisors under an obligation to maintain
confidentiality, or (ii) as required by law, including but not limited to, a
valid court order or subpoena (and in such event will use Wells' best efforts to
obtain a protective order requiring that all disclosure be kept under court
seal) and will notify NCNG promptly upon receipt of such order or subpoena.
9. MISCELLANEOUS.
-------------
9
<PAGE>
(a). Governing Law. This Agreement shall be governed by, and
construed in accordance with, the laws of the State of North Carolina without
reference to laws governing conflicts of law.
(b). Entire Agreement. This Agreement contains all of the
understandings and representations between the parties hereto pertaining to the
subject matter hereof and supersedes all undertakings and agreements, including
specifically the Prior Agreement entered into on September 11, 1985, whether
oral or in writing, previously entered into by them with respect thereto.
(c). Amendment or Modification; Waiver. No provision in this
Agreement may be amended or waived unless such amendment or waiver is agreed to
in writing, signed by Wells and by an officer of NCNG thereunto duly authorized
to do so. Except as otherwise specifically provided in the Agreement, no waiver
by a party hereto of any breach by the other party hereto of any condition or
provision of the Agreement to be performed by such other party shall be deemed a
waiver of a similar or dissimilar provision or condition at the same or any
prior or subsequent time.
(d). Notice. Any notice (with the exception of notice of
termination by NCNG, which may be given by any means and need not be in writing)
or other document or communication required or permitted to be given or
delivered hereunder shall be in writing and shall be deemed to have been duly
given or delivered if (i) mailed by United States mail, certified, return
receipt requested, with proper postage prepaid, or (ii) otherwise delivered by
hand or by overnight delivery, against written receipt, by a common carrier or
commercial courier or delivery service, to the party to whom it is to be given
at the address of such party as set forth below (or to such other address as a
party shall have designated by notice to the other parties given pursuant
hereto):
If to Wells:
Calvin B. Wells
North Carolina Natural Gas
150 Rowan Street
Fayetteville, NC 28301
If to NCNG:
Carolina Power & Light Company
411 Fayetteville Street
Raleigh, North Carolina 27602
Attention: Vice President-Human Resources
Any such notice, request, demand, advice, schedule, report, certificate,
direction, instruction or other document or communication so mailed or sent
shall be deemed to have been duly given, if
10
<PAGE>
sent by mail, on the third business day following the date on which it was
deposited at a United States post office, and if delivered by hand, at the time
of delivery by such commercial courier or delivery service, and, if delivered by
overnight delivery service, on the first business day following the date on
which it was delivered to the custody of such common carrier or commercial
courier or delivery service, as all such dates are evidenced by the applicable
delivery receipt, airbill or other shipping or mailing document.
(e). Severability. In the event that any provision or portion
of this Agreement shall be determined to be invalid or unenforceable for any
reason, the remaining provisions or portions of this Agreement shall be
unaffected thereby and shall remain in full force and effect to the fullest
extent permitted by law.
(f). References. In the event of Wells' death or a judicial
determination of Wells' incompetence, reference in this Agreement to Wells shall
be deemed, where appropriate, to refer to Wells' legal representative, or, where
appropriate, to Wells' beneficiary or beneficiaries.
(g). Headings. Headings contained herein are for convenient
reference only and shall not in any way affect the meaning or interpretation of
this Agreement.
(h). Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed to be an original, but all of which
together shall constitute one and the same instrument.
(i). Rules of Construction. The following rules shall apply to
the construction and interpretation of this Agreement:
(i). Singular words shall connote the plural number
as well as the singular and vice versa, and the masculine shall include the
feminine and the neuter.
(ii). All references herein to particular articles,
paragraphs, sections, subsections, clauses, Schedules or Exhibits are references
to articles, paragraphs, sections, subsections, clauses, Schedules or Exhibits
of this Agreement.
(iii). Each party and its counsel have reviewed and
revised (or requested revisions of) this Agreement, and therefore any rule of
construction requiring that ambiguities are to be resolved against a particular
party shall not be applicable in the construction and interpretation of this
Agreement or any exhibits hereto or amendments hereof.
(iv). As used in this Agreement, "including" is
illustrative, and means "including but not limited to."
(j). Remedies. Remedies specified in this Agreement are in
addition to any others available at law or in equity.
11
<PAGE>
(k). Withholding Taxes. All payments under this Agreement
shall be subject to applicable income, excise and employment tax withholding
requirements.
IN WITNESS WHEREOF, the parties hereto have executed, or have caused
this Agreement to be executed by their duly authorized officer, as the case may
be, all as of the day and year written below.
By: _______________________________ Date: ___________________
Calvin B. Wells
By: _______________________________ Date: ___________________
North Carolina Natural Gas Corporation
Title: _______________________________
12
EXHIBIT 10B(34)
August 2, 1999
Mr. Larry M. Smith
205 South 26th Street
West Des Moines, Iowa 50265
Dear Larry:
I am pleased to confirm the offer of employment with Carolina Power & Light
Company as the Vice President & Controller at an annual salary of $168,000. The
offer is contingent on approval from the Board of Directors, satisfactory
completion of an employment background investigation, and eligibility to be
employed in the United States.
We ask that you kindly inform of your decision to accept our offer by August 9,
1999. Please return one copy of this letter with your signature to indicate your
acceptance of our offer. Also, please read, sign, and return the Fair Credit
Reporting Act Disclosure and Authorization Statement which describes your
federal rights related to any employment background check.
We are looking forward to having you join us as a vital member of the team and
feel that you can make a significant contribution to CP&L in our Financial
Services Group. If I can answer any questions about the offer or provide any
additional information, please call me at 919-546-5533.
Sincerely,
/s/Glenn E. Harder
Glenn E. Harder
Chief Financial Officer
Attachment
ACCEPTED:
/s/Larry M. Smith 8/5/99
- ---------------------------------
Signature/Date
c: Randy Mizelle
Glenn E. Harris
[] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] [] []
TO BE COMPLETED ONLY IF OFFER IS ACCEPTED:
Birthdate: 2/26/56
-------
<PAGE>
VP & CONTROLLER
COMPENSATION/BENEFITS/PERQUISITES
BASE SALARY $168,000 annually, subject to periodic
- ----------- review and normally adjusted in March,
at the time other department head
salaries are reviewed.
SHORT-TERM Participation in Management Incentive
INCENTIVE Compensation Program with an annual
- ---------- target of 25% of actual base salary
earnings.
LONG-TERM Participation in the Performance Share
INCENTIVE Sub-Plan which provides for an annual
- --------- award of 25% of base salary awarded in
performance shares equivalent in value
to the market price of the Company's
common stock at the time of the granting
of the award, earned over a three-year
period and adjusted based on
performance.
SPLIT-DOLLAR LIFE Participant in a permanent life
INSURANCE PLAN insurance program with a target benefit
- ----------------- of 3 times projected base salary
assuming a salary growth of 5%.
Participation in this "split dollar"
program is conditional upon passing
underwriting and waiving all but $50,000
coverage in the group term plan within
Choice Benefits.
AUTOMOBILE Car Allowance of $1200 per month with
- ---------- cellular telephone.
LUNCHEON CLUB Initiation fees and dues provided to the
- ------------- Capital City Club.
ANNUAL PHYSICAL One annual physical examination covered,
- ---------------- to be provided by a physician of
employee's choice.
BENEFITS Choice Benefits Program including
- -------- options for medical, dental, employee
and dependent life, and AD&D insurance.
PENSION PLAN Participation in Company funded
- ------------ retirement plan that provides lump sum
and/or lifetime benefits for you and
your surviving spouse upon completion of
5 years of employment.
STOCK PURCHASE Provides for $.50 match per dollar up to
SAVINGS PLAN six percent (6%) of base salary.
- -------------- Additional contributions are
<PAGE>
possible for another $.50 based upon
meeting Company performance goals.
DISABILITY INCOME Coverage under plan that provides for
- ----------------- 60% of salary (or 70% of base salary
including Family Social Security
benefits).
VACATION One week during the balance of 1999.
- -------- Four weeks beginning January 2000. Per
company policy thereafter.
HOLIDAYS Current company policy is 10 days.
- --------
TERMINATION Employment may be terminated at will by
- ----------- the Company or by you without notice.
If, following a Change-of-Control and
within 2 years of employment, employment
is terminated other than for good cause
by the Company, you will be provided one
year's base salary over the following 12
months, paid on a semi-monthly basis,
subject to signing a release agreement.
A Change-of-Control will be deemed to
occur if there is a change in the form
of ownership of CP&L (e.g., CP&L is
acquired or otherwise changes form of
ownership). Change in CP&L's corporate
structure such as reorganization under
or into a holding company, shall not be
considered the basis for constructive
termination.
Good cause for the termination of
employment shall be defined as: (i) any
act of Mr. Smith's including, but not
limited to, misconduct, negligence,
unlawfulness, dishonesty or inattention
to the business, which is detrimental to
CP&L's interests; or (ii) Mr. Smith's
unsatisfactory job performance or
failure to comply with CP&L's direction,
policies, rules or regulations.
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
--------------------------------------------------------------------
Years Ended December 31,
--------------------------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
(Thousands of Dollars)
Earnings, as defined:
Net income $ 382,255 399,238 $ 388,317 $ 391,277 $ 372,604
Fixed charges, as below 202,491 191,832 193,632 204,593 226,833
Income taxes, as below 250,272 249,180 225,491 247,691 232,343
------------------------- ------------ ------------- -------------
Total earnings, as defined $ 835,018 840,250 $ 807,440 $ 843,561 $ 831,780
========================= ============ ============= =============
Fixed Charges, as defined:
Interest on long-term debt $ 180,676 169,901 $ 163,468 $ 172,622 $ 187,397
Other interest 10,298 11,156 18,743 19,155 25,896
Imputed interest factor in rentals-charged
Principally to operating expenses 11,517 10,775 11,421 12,816 13,540
------------------------- ------------ ------------- -------------
Total fixed charges, as defined $ 202,491 191,832 $ 193,632 $ 204,593 $ 226,833
========================= ============ ============= =============
Earnings Before Income Taxes $ 632,527 648,418 $ 613,808 $ 638,968 $ 604,947
========================= ============ ============= =============
Ratio of Earnings Before Income Taxes to Net Income 1.66 1.62 1.58 1.63 1.62
Income Taxes:
Income tax expense 258,421 257,494 233,716 255,916 240,683
Included in AFUDC - deferred taxes in
book depreciation (8,149) (8,314) (8,225) (8,225) (8,340)
------------------------- ------------ ------------- -------------
Total income taxes $ 250,272 249,180 $ 225,491 $ 247,691 $ 232,343
========================= ============ ============= =============
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements $ 2,967 2,967 $ 6,052 $ 9,609 $ 9,609
Portion deductible for income tax purposes (312) (312) (312) (312) (312)
------------------------- ------------ ------------- -------------
Preferred dividend requirements not deductible $ 2,655 2,655 $ 5,740 $ 9,297 $ 9,297
========================= ============ ============= =============
Preferred dividend factor:
Preferred dividends not deductible times ratio of
Earnings before income taxes to net income $ 4,407 4,301 $ 9,069 $ 15,154 $ 15,061
Preferred dividends deductible for income taxes 312 312 312 312 312
Fixed charges, as above 202,491 191,832 193,632 204,593 226,833
------------------------- ------------ ------------- -------------
Total fixed charges and preferred dividends combined $ 207,210 196,445 $ 203,013 $ 220,059 $ 242,206
========================= ============ ============= =============
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined 4.03 4.28 3.98 3.83 3.43
Ratio of Earnings to Fixed Charges 4.12 4.38 4.17 4.12 3.67
</TABLE>
EXHIBIT 21
SUBSIDIARIES OF CAROLINA POWER & LIGHT COMPANY
AT DECEMBER 31, 1999
The following is a list of certain subsidiaries of Carolina Power & Light
Company and their respective states of incorporation:
Interpath Communications, Inc. North Carolina
Virginia
North Carolina Natural Gas Corporation Delaware
Cape Fear Energy Corporation (1) North Carolina
NCNG Cardinal Pipeline Investment Corporation (1) North Carolina
NCNG Energy Corporation (1) North Carolina
NCNG Pine Needle Investment Corporation (1) North Carolina
Strategic Resource Solutions Corp. North Carolina
ACT Controls, Inc. (2) North Carolina
Applied Computer Technologies Corp. (2) Delaware
Spectrum Controls, Inc. (2) North Carolina
SRS Engineering Corp. (2) North Carolina
(1) Subsidiary of North Carolina Natural Gas Corporation.
(2) Subsidiary of Strategic Resource Solutions Corp.
EXHIBIT NO. 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-33520 on Form S-8, Registration Statement No. 33-5134 on Form S-3,
Post-Effective Amendment No. 1 to Registration Statement No. 33-38349 on Form
S-3, Registration Statement No. 333-69237 on Form S-3, Registration Statement
No. 333-70679 on Form S-8 and Registration Statement No. 333-89685 on Form S-8
of Carolina Power & Light Company, of our report dated February 8, 2000, except
for Note 2, as to which the date is March 3, 2000 appearing in this Annual
Report on Form 10-K of Carolina Power & Light Company for the year ended
December 31, 1999.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
March 21, 2000
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
(CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 1999) AND IS QUALIFIED IN
ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> $6,764,813
<OTHER-PROPERTY-AND-INVEST> $492,436
<TOTAL-CURRENT-ASSETS> $1,079,333
<TOTAL-DEFERRED-CHARGES> $297,749
<OTHER-ASSETS> $859,688
<TOTAL-ASSETS> $9,494,019
<COMMON> $1,606,096
<CAPITAL-SURPLUS-PAID-IN> $(794)
<RETAINED-EARNINGS> $1,807,345
<TOTAL-COMMON-STOCKHOLDERS-EQ> $3,412,647
$0
$59,376
<LONG-TERM-DEBT-NET> $3,028,561
<SHORT-TERM-NOTES> $168,240
<LONG-TERM-NOTES-PAYABLE> $0
<COMMERCIAL-PAPER-OBLIGATIONS> $0
<LONG-TERM-DEBT-CURRENT-PORT> $197,250
$0
<CAPITAL-LEASE-OBLIGATIONS> $0
<LEASES-CURRENT> $0
<OTHER-ITEMS-CAPITAL-AND-LIAB> $2,627,945
<TOT-CAPITALIZATION-AND-LIAB> $9,494,019
<GROSS-OPERATING-REVENUE> $3,357,615
<INCOME-TAX-EXPENSE> $258,421
<OTHER-OPERATING-EXPENSES> $2,517,072
<TOTAL-OPERATING-EXPENSES> $2,775,493
<OPERATING-INCOME-LOSS> $582,122
<OTHER-INCOME-NET> $(20,403)
<INCOME-BEFORE-INTEREST-EXPEN> $561,719
<TOTAL-INTEREST-EXPENSE> $179,464
<NET-INCOME> $382,255
$(2,967)
<EARNINGS-AVAILABLE-FOR-COMM> $379,288
<COMMON-STOCK-DIVIDENDS> $300,244
<TOTAL-INTEREST-ON-BONDS> $137,067
<CASH-FLOW-OPERATIONS> $832,120
<EPS-BASIC> 2.56
<EPS-DILUTED> 2.55
</TABLE>
