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
                         ------------------------------
             (Exact name of registrant as specified in its charter)
<TABLE>
<CAPTION>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
                                                        411 Fayetteville Street
North Carolina                      56-0165465          Raleigh, North Carolina                    27601
--------------                      ----------          -----------------------                    -----
(State or other jurisdiction of   (I.R.S. Employer    (Address of principal executive offices)   (Zip Code)
incorporation or organization)   Identification No.)
</TABLE>

                                  919-546-6111
                                  ------------
              (Registrant's telephone number, including area code)

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
           -----------------------------------------------------------

<TABLE>
<CAPTION>
        Title of each class                                Name of each exchange on which registered
        -------------------                                -----------------------------------------
<S>     <C>    <C>    <C>    <C>    <C>    <C>
        Common Stock (Without Par Value)                   New York Stock Exchange
                                                           Pacific Stock Exchange
        Quarterly Income Capital Securities                New York Stock Exchange
</TABLE>

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
           -----------------------------------------------------------
                 Preferred Stock (Without Par Value, Cumulative)
                                (Title of Class)

Indicate by check mark whether the registrant (1) has filed all reports to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes     X     .  No           .
    ----------      ----------


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in PART III of this Form 10-K or any amendment to this
Form 10-K. [X]


The aggregate market value of the voting and non-voting common stock held by
non-affiliates at February 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.



                                       1
<PAGE>
<TABLE>
<CAPTION>
                                TABLE OF CONTENTS
<S>                                                                                                                  <C>
                                                                                                                   Page
                                                                                                                   ----
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
</TABLE>


                                       2
<PAGE>


SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
------------------------------------------

The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.


Examples of forward-looking statements discussed in this Form 10-K, PART I, ITEM
1, "BUSINESS," include, but are not limited to, statements under the following
headings: 1) "General" relating to 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.


                                       3
<PAGE>


                                     PART I

ITEM 1.    BUSINESS
-------    --------

GENERAL
-------

COMPANY
-------


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
------------------------

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.


                                       4
<PAGE>
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
---------------------

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
-------------------

GENERATING CAPABILITY
---------------------


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.



                                       5
<PAGE>
<TABLE>
<CAPTION>
                                           MAJOR INSTALLED GENERATING FACILITIES
                                           -------------------------------------
                                                    AT DECEMBER 31, 1999
                                                    --------------------


                                                                      Year                             Maximum
                                                                   Commercial                         Dependable
              Plant Location                        Unit No.        Operation     Primary Fuel         Capacity
              --------------                        --------        ---------     ------------         --------
<S>                                                    <C>            <C>                               <C>
              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.
</TABLE>

                                       6
<PAGE>


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

                                       7
<PAGE>

         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
-----------------------------------


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.
         -----------------------------------------------

         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

                                       8
<PAGE>

               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
-----------

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

                                       9
<PAGE>

         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

                                       10
<PAGE>

         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.

                                       43
<PAGE>

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.


                                       47
<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.


                                       48
<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."


                                       49
<PAGE>

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.


                                       50
<PAGE>

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)
                                           =========    =========

                                       71
<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>

                                       80
<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).

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<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