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, 1997
                                       OR
         [ ]        TRANSITION REPORT PURSUANT TO SECTION 13 OR
                   15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

                    For the transition period from       to
                                                   -----    -----

                          Commission file number 1-3382
                                                 ------

                         CAROLINA POWER & LIGHT COMPANY
                         ------------------------------
             (Exact name of registrant as specified in its charter)

                                            411 Fayetteville Street
North Carolina             56-0165465       Raleigh, North Carolina     27601
----------------           ----------       -----------------------     -----
(State or other         (I.R.S. Employer     (Address of principal    (Zip Code)
jurisdiction of         Identification No.)    executive offices)
incorporation or                              
organization) 
                               
                                    919-546-6111
                                    ------------
              (Registrant's telephone number, including area code)

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

Title of each class                    Name of each exchange on which registered
-------------------                    -----------------------------------------
Common Stock (Without Par Value)       New York Stock Exchange
                                       Pacific Stock Exchange
Quarterly Income Capital Securities    New York Stock Exchange

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

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

Indicate by check mark if disclosure of delinquent  filers  pursuant to  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. [ ]

The  aggregate  market value of the voting and  non-voting  common stock held by
non-affiliates at February 27, 1998, was $6,318,461,450.

Shares of Common  Stock  (Without Par Value)  outstanding  at February 27, 1998:
151,340,394.

                       DOCUMENTS INCORPORATED BY REFERENCE
                       -----------------------------------
Portions of the Company's 1998 definitive  proxy statement dated March 30, 1998,
are incorporated into Part III, Items 10, 11, 12 and 13 hereof.

<PAGE>
<TABLE>
<CAPTION>
                                                   TABLE OF CONTENTS
                                                                                                             Page
<S>                                                                                                          <C>
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS                                                                     3

                                                        PART I
ITEM 1.      BUSINESS                                                                                          4
                   General                                                                                     4
                   Generating Capability                                                                       5
                   Interconnections with Other Systems                                                         8
                   Competition                                                                                 9
                   Capital Requirements                                                                       12
                   Financing Program                                                                          13
                   Retail Rate Matters                                                                        15
                   Wholesale Rate Matters                                                                     17
                   Environmental Matters                                                                      17
                   Nuclear Matters                                                                            20
                   Fuel                                                                                       24
                   Diversified Businesses                                                                     26
                   Other Matters                                                                              27
                   Operating Statistics                                                                       29

ITEM 2.      PROPERTIES                                                                                       30

ITEM 3.      LEGAL PROCEEDINGS                                                                                31

ITEM 4.      SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                              32

             EXECUTIVE OFFICERS OF THE REGISTRANT                                                             33

                                                        PART II

ITEM 5.      MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS                        35

ITEM 6.      SELECTED CONSOLIDATED FINANCIAL DATA                                                             36

ITEM 7.      MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS            37

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                       47

ITEM 8.      CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA                                         48

ITEM 9.      CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE             70

                                                       PART III

ITEM 10.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT                                               70

ITEM 11.     EXECUTIVE COMPENSATION                                                                           70

ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT                                   70

ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                                                   70

                                                        PART IV

ITEM 14.     EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K                     70


</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  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,  ITEM 1,
"BUSINESS",  include,  but are not limited to,  statements  under the  following
headings:  1) "General" relating to forecasted capacity margins over anticipated
system peak loads; 2) "Generating  Capability"  regarding the forecasted  system
sales growth and planned generation  additions  schedule;  3)  "Interconnections
with Other  Systems"  relating to future  energy  cost  savings  resulting  from
amendments to agreements with Cogentrix and relating to estimated minimum annual
payments for long-term purchase contracts; 4) "Competition" regarding the effect
on  the  Company  of  increased  competition  at the  wholesale  level  and  the
likelihood  of  additional   restructuring-related  bills  being  introduced  in
Congress  in 1998;  5) "Capital  Requirements"  relating  to  estimated  capital
requirements for 1998-2000; 6) "Financing Program" relating to expected external
funding  requirements;  7)  "Environmental  Matters"  relating to future capital
expenditures to meet nitrogen oxide emission  requirements,  emerging regulatory
requirements  and the  materiality  of future  costs  related  to  environmental
matters;  8) "Nuclear  Matters"  relating  to future  capital  expenditures  for
modifications  at the  Company's  nuclear  units,  future  increase in low-level
radioactive waste disposal costs, materiality of various nuclear-related matters
and the date of  replacement  of the Harris  Plant steam  generators;  9) "Fuel"
regarding the percentages of future coal burn requirements from intermediate and
long-term agreements,  effect of amendments to the Clean Air Act on the price of
low sulfur coal,  sufficiency of existing uranium  contracts and regarding total
decontamination  and  decommissioning  fund fees  expected  to be paid;  and 10)
"Diversified Businesses" relating to future services to be provided by Interpath
Communications,  Inc.,  future  investments in affordable  housing and Strategic
Resource  Solutions  Corp.'s  enhanced  ability  to  deliver   energy-management
products.

In addition, examples of forward-looking statements discussed in this Form 10-K,
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  and 2) "Other  Matters"  about the  effects  of new  environmental
regulations,  nuclear  decommissioning costs, the effect of deregulation and the
outcome of the Year 2000 compliance.

Any forward-looking statement speaks only as of the date on which such statement
is made, and the Company undertakes no obligation to update any  forward-looking
statement or statements  to reflect  events or  circumstances  after the date on
which such statement is made.

Examples  of  factors   that   should  be   considered   with   respect  to  any
forward-looking  statements made throughout this document  include,  but are not
limited  to,  the  following:   Governmental  policies  and  regulatory  actions
(including those of the Federal Energy Regulatory Commission,  the Environmental
Protection Agency, the Nuclear Regulatory Commission,  the Department of Energy,
the North Carolina  Utilities  Commission and the South Carolina  Public Service
Commission);  general  industry trends;  operation of nuclear power  facilities;
nuclear storage  facilities;  nuclear  decommissioning  costs;  general economic
growth;   weather   conditions   and   catastrophic    weather-related   damage;
deregulation;  market demand for energy;  inflation;  capital market conditions;
unanticipated  changes in operating expenses and capital  expenditures and legal
and  administrative  proceedings.  All such  factors are  difficult  to predict,
contain  uncertainties  that may materially  affect actual  results,  and may be
beyond the control of the Company.  New factors  emerge from time to time and it
is not possible for management to predict all of such factors, nor can it assess
the effect of each such factor on the Company.
 
                                       3
<PAGE>
                                     PART I

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

GENERAL
-------
1.       Company.  Carolina  Power & Light  Company  (the  Company)  is a public
         --------
         service  corporation  formed under the laws of North  Carolina in 1926,
         and is primarily engaged in the generation, transmission,  distribution
         and sale of  electricity in portions of North and South  Carolina.  The
         Company had  approximately  6,900  employees at December 31, 1997.  The
         principal   executive  offices  of  the  Company  are  located  at  411
         Fayetteville Street,  Raleigh,  North Carolina 27601, telephone number:
         919-546-6111.

2.       Franchises.  The  Company  is a  regulated  public  utility  and  holds
         -----------
         franchises to the extent necessary to operate in the municipalities and
         other areas it serves.

3.       Service.
         --------

         a)       The territory served,  an area of approximately  30,000 square
                  miles,  includes a substantial portion of the coastal plain of
                  North  Carolina  extending to the Atlantic  coast  between the
                  Pamlico  River  and  the  South  Carolina  border,  the  lower
                  Piedmont  section of North  Carolina,  an area in northeastern
                  South  Carolina and an area in western  North  Carolina in and
                  around the City of Asheville.  The estimated total  population
                  of the territory served is approximately 3.8 million.

         b)       The  Company   provides   retail   electricity   in  over  200
                  communities,  each having an  estimated  population  of 500 or
                  more,  and at wholesale to North  Carolina  Eastern  Municiple
                  Power  Agency  consisting  of 32  members,  3  municipalities,
                  French  Broad  Electric   Membership   Corporation  and  North
                  Carolina  Electric  Membership  Corporation  consisting  of 27
                  members (17 of which are served by the Company's  system).  At
                  December 31, 1997, the Company was furnishing electric service
                  to approximately 1,153,000 customers.

4.       Sales.  During  1997,  33% of  operating  revenues  were  derived  from
         ------
         residential  sales,  21% from  commercial  sales,  24% from  industrial
         sales,  13% from  wholesale  sales and 9% from other  sources.  Of such
         operating revenues,  approximately 68% were derived from North Carolina
         retail customers,  13% from South Carolina retail  customers,  13% from
         North Carolina  wholesale  customers,  less than 1% from South Carolina
         wholesale  customers  and 6% from  sales to other  utilities  and other
         sources.

5.       Peak Demand.
         ------------

         a)       A 60-minute system peak demand record of 10,156 megawatts (MW)
                  was  reached  on  August  14,  1995.  At the time of this peak
                  demand,  the  Company's  capacity  margin,  based on installed
                  capacity  (less  unavailable   capacity)  and  scheduled  firm
                  purchases and sales, was approximately 7.0%.

         b)       Total system peak demand for 1995  increased by .12%, for 1996
                  decreased by 3.4%, and for 1997 increased by 2.2%, as compared
                  with the preceding year. The Company  currently  projects that
                  system peak demand will  increase at an average  annual growth
                  rate of  approximately  2.6%  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  

                                       4
<PAGE>

                  factors,  expressed as the ratio of the average load  supplied
                  to the peak load demand,  for the years  1995-1997 were 59.2%,
                  60.8% and 60.6%, respectively.  The Company forecasts capacity
                  margins of 9.6% over anticipated system peak load for 1998 and
                  9.6% for 1999. This forecast assumes normal weather conditions
                  in each year  consistent  with  long-term  experience,  and is
                  based upon the rated Maximum Dependable Capacity of generating
                  units in commercial  operation and scheduled firm purchases of
                  power.  See  PART  I,  ITEM  1,  "Generating  Capability"  and
                  "Interconnections  With Other Systems".  However,  some of the
                  generating  units  included  in  arriving  at  these  capacity
                  margins may be unavailable  as a result of scheduled  outages,
                  environmental  modifications or unplanned outages. See PART I,
                  ITEM 1,  "Environmental  Matters" and "Nuclear  Matters".  The
                  data  contained  in this  paragraph  includes  North  Carolina
                  Eastern   Municipal   Power   Agency's   (Power  Agency)  load
                  requirements  and capability  from its ownership  interests in
                  certain of the Company's  generating  facilities.  See PART I,
                  ITEM 1, "Generating Capability", paragraph 1.

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

1.       Facilities.  At December  31,  1997,  the  Company  had a total  system
         -----------
         installed  generating  capability  (including  Power Agency's share) of
         9,853  MW,  with  generating   capacity  provided  primarily  from  the
         installed generating  facilities listed in the table below. The Maximum
         Dependable  Capacity  of the  Company's  Brunswick  Nuclear  Plant  was
         increased by 110 MW  effective  January 1, 1998.  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,  which is comprised of former North  Carolina  municipal
         wholesale  customers  of the Company and  Virginia  Electric  and Power
         Company (Virginia Power), 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  (collectively,  the
         Joint Facilities).  Of the total system installed generating capability
         of 9,853 MW, 54% is coal, 31% is nuclear,  2% is hydro and 13% is fired
         by other fuels including No. 2 oil, natural gas and propane.

<TABLE>
                      MAJOR INSTALLED GENERATING FACILITIES
                              AT DECEMBER 31, 1997
<CAPTION>
                                        Year                         Maximum
                                     Commercial                    Dependable
Plant Location           Unit No.    Operation      Primary Fuel    Capacity
--------------           --------    ----------     ------------  ------------
<S>                      <C>         <C>            <C>           <C> 
Asheville                   1           1964            Coal       198 MW
(Skyland,N.C.)              2           1971            Coal       194 MW

Cape Fear                   5           1956            Coal        143MW
(Moncure, N.C.)             6           1958            Coal        173MW

Darlington County Plant     12          1997           Gas/Oil      120MW
(Hartsville, S.C.)          13          1997           Gas/Oil      120MW

H.F. Lee                    1           1952            Coal         79MW
(Goldsboro, N.C.)           2           1951            Coal         76MW
                            3           1962            Coal        252MW
 
                                      5
<PAGE>

H.B. Robinson               1           1960            Coal        174MW
(Hartsville, S.C.)          2           1971           Nuclear      683MW

Roxboro                     1           1966            Coal        385MW
(Roxboro, N.C.)             2           1968            Coal        670MW
                            3           1973            Coal        707MW
                            4           1980            Coal        700MW<F1>

L.V. Sutton                 1           1954            Coal         97MW
(Wilmington, N.C.)          2           1955            Coal        106MW
                            3           1972            Coal        410MW

Brunswick                   1           1977           Nuclear      767MW<F1>
(Southport, N.C.)           2           1975           Nuclear      754MW<F1>

Mayo                        1           1983            Coal        745MW<F1>
(Roxboro N.C.)

Harris                      1           1987           Nuclear      860MW<F1>
(New Hill, N.C.)

<FN>
<F1>
Facilities  are jointly owned by the Company and Power Agency,
and the capacity shown includes Power Agency's share.
</FN>
</TABLE>



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 rate making 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  1997.  Over the next ten years,  system sales
         growth is forecasted to average  approximately 2.6% per year and annual
         growth in system  peak  demand is  projected  to average  approximately
         2.6%. The Company's  generation  additions  schedule,  which is updated
         annually,  provides for the addition of 2,887  megawatts of  combustion
         turbine  capacity and 3,600  megawatts of combined  cycle capacity over
         the period 1998 to 2011.  Additions  planned through 2003 are discussed
         below.

         a)       The Company  received a Certificate of Public  Convenience and
                  Necessity from the North Carolina Utilities  Commission (NCUC)
                  on  March  21,   1996   granting   permission   to   construct
                  approximately  500 MW of combustion  turbine capacity adjacent
                  to the  Company's  Lee Steam  Electric  Plant in Wayne County,
                  North  Carolina.  The  units  will  primarily  be used  during
                  periods of summer and winter peak  demands.  Under the current
                  schedule for the combustion turbine capacity,  construction is
                  to begin in August 1998.  Commercial  operation is anticipated
                  to begin in June 2000,  with the aggregate cost of these units
                  expected to approximate $130 million. In the interim,  peaking
                  requirements will be met with power purchases.

         b)       The Company issued a Notice of Inquiry (NOI) on March 12, 1996
                  concerning  short-term  power  purchases  for the peak  winter
                  months of 1998-1999  and the peak summer  months of 1998.  The
 
                                      6
<PAGE>

                  NOI was sent to a number of  electric  utilities,  independent
                  power producers and power  marketers.  The Company  received a
                  number of bids,  which resulted in contract  purchases for the
                  summer of 1998.

         c)       In June 1996, the Company  issued  Requests for Proposal (RFP)
                  for purchased power of 700 to 1,000 MW of capacity to meet the
                  Company's future generation needs in its service territory and
                  to replace contract  purchases  terminating in 1998-1999.  The
                  Company projected a need of approximately 200 to 350 MW in its
                  western service territory,  and approximately 350 to 650 MW in
                  its eastern service  territory.  The capacity was requested to
                  be  available  for  delivery by June 1, 1999.  Proposals  were
                  invited  from all  potential  suppliers  who were  capable  of
                  meeting the conditions of the RFP. In January 1997 the Company
                  decided,   based  on  the  proposals  received,   to  purchase
                  approximately one-third of the necessary peaking capacity, and
                  on July 14, 1997,  the Company and PECO Power Team, a division
                  of PECO Energy Co.  (PECO),  announced  an  agreement  for the
                  Company to purchase up to 300  megawatts of peaking power from
                  PECO  for  the  summer  periods  of 1999 to  2003.  The  other
                  two-thirds  of  capacity  for  1999  will  be  supplied  by  a
                  combination  of  short-term  purchases,  and  power  from  the
                  Buncombe County combustion  turbine, as described in paragraph
                  3.e. below.

         d)       In April 1997, the Company issued a RFP for purchased power of
                  400  to  800 MW of  capacity  to  meet  the  Company's  future
                  generation  needs  beginning  in  the  years  2000  and  2001.
                  Proposals  were invited from all potential  suppliers who were
                  capable  of meeting  the  conditions  of the RFP.  On July 30,
                  1997,  11 proposals  were  received  from 9 bidders,  offering
                  approximately 2,300 MW of capacity.  The Company is continuing
                  to evaluate the proposals.

         e)       Due to  increased  economic  activity  and load  growth in its
                  western service  territory,  on September 4, 1996, the Company
                  filed  with  the  NCUC  its  preliminary  plans  to  construct
                  approximately 320 MW of combustion turbine generating capacity
                  in Buncombe County,  North Carolina at the Company's  existing
                  Asheville Steam Electric Plant, with an in-service date of the
                  summer of 1999.  Pursuant to those plans, on January 31, 1997,
                  the  Company  filed  with  the  NCUC  an  Application   for  a
                  Certificate  of  Public  Convenience  and  Necessity  for  one
                  combustion  turbine  unit  of  approximately  160  MW  at  the
                  Asheville  Plant.  A  Certificate  of Public  Convenience  and
                  Necessity  was  issued  by the  NCUC on  August  1,  1997,  to
                  construct the combustion turbine unit. On August 15, 1997, the
                  Company   contracted   with   General   Electric   Company  to
                  manufacture  and install this  combustion  turbine  unit.  The
                  expected  in-service date is June 1999.  (This turbine,  along
                  with certain  power  purchases  described  in  paragraph  3.c.
                  above,   will  satisfy  the   Company's   anticipated   future
                  generation  needs  in  its  western  service  territory.  As a
                  result, plans to construct the additional 160 MW of combustion
                  turbines in Buncombe County have been indefinitely postponed.)
                  The Company cannot predict the outcome of this matter.

                                       7
<PAGE>

INTERCONNECTIONS WITH OTHER SYSTEMS
-----------------------------------

1.       Interconnections.  The  Company's  facilities in Asheville and vicinity
         -----------------
         are  integrated  into the total system  through the  facilities of Duke
         Energy  Corporation (Duke) via  interconnection  agreements that permit
         transfer of power to and from the Asheville  area. The Company also has
         major  interconnections  with the  Tennessee  Valley  Authority  (TVA),
         Appalachian  Power  Company  (APCO),  Virginia  Power,  South  Carolina
         Electric  and  Gas  Company  (SCE&G),  South  Carolina  Public  Service
         Authority (SCPSA) and Yadkin,  Inc.  (Yadkin).  Major  interconnections
         include 115 kV and 230 kV ties with SCE&G and SCPSA; 115 kV, 230 kV and
         500 kV ties with Duke and Virginia  Power; a 115 kV tie with Yadkin;  a
         161 kV tie  with  TVA;  and  three  138 kV ties and one 230 kV tie with
         APCO. See paragraph 3.b. below.

2.       Interchange and Power Purchase/Sale Agreements.
         -----------------------------------------------

         a)       The Company has interchange agreements with APCO, Duke, SCE&G,
                  SCPSA,  TVA,  Virginia  Power and Yadkin which provide for the
                  purchase and sale of power for hourly, daily, weekly,  monthly
                  or longer periods. In addition to the interchange  agreements,
                  the Company has executed  individual  purchase  agreements and
                  sales  agreements  with more  than 100  companies  beyond  the
                  Virginia-Carolinas   Subregion  described  in  paragraph  2.b.
                  below.  Purchases and sales under these agreements may be made
                  due to economic or reliability considerations.

                  By letter dated May 24, 1996,  the Company  provided Duke with
                  written  notice that effective June 1, 1999, it will terminate
                  Schedule G to the  Interchange  Agreement  between the Company
                  and Duke.  Schedule G provides for the wheeling of electricity
                  between the Company's eastern area and its western area.

                  By letter dated  December 30, 1996,  Duke provided the Company
                  with written notice that effective  December 31, 1999, it will
                  terminate the Standby  Concurrent  Exchange Agreement (Standby
                  Agreement) between the Company and Duke. The Standby Agreement
                  provides  for  the  simultaneous  exchange  of  up to 70 MW of
                  electricity   during  periods  of  scheduled   maintenance  or
                  breakdown.

                  On  December  31,  1996,   pursuant  to  the  Federal   Energy
                  Regulatory  Commission (FERC) Order 888, which directs that no
                  bundled economy energy  coordination  transactions occur after
                  December  31,  1996,  the  Company  submitted  to  the  FERC a
                  compliance filing to unbundle  transmission  charges from rate
                  schedules  that are  applicable to the power sales  agreements
                  between  the   Company  and  others.   See  PART  I,  ITEM  1,
                  "Competition", paragraph 2, for further discussion of the FERC
                  Order 888.

         b)       The Virginia-Carolinas  Subregion of the Southeastern Electric
                  Reliability Council is made up of the Company, Duke, Nantahala
                  Power  &  Light  Company,   SCE&G,   SCPSA,   Virginia  Power,
                  Southeastern Power Administration and Yadkin. Electric service
                  reliability is promoted by  arrangements  among the members of
                  electric reliability organizations at the subregional level.

3.       Long-Term Purchase Power Contracts.
         -----------------------------------

         a)       In March 1987,  the Company  entered  into an  agreement  with
                  Duke, which has been accepted by the FERC,  whereby Duke would
                  provide 400 MW of firm capacity to the  Company's  system over
                  the  period  January  1,  1992,  through  December  31,  1997.
                  Pursuant to an amendment of the contract,

                                       8
<PAGE>
                  commencement  of the  purchase  of  power by the  Company  was
                  delayed until July 1993 and termination  was extended  through
                  June 1999.  The  estimated  minimum  annual  payment for power
                  purchases under the six-year  agreement is  approximately  $48
                  million,    representing   capital-related   capacity   costs.
                  Purchases under this  agreement,  including  transmission  use
                  charges, totaled $69.5 million in 1997.

         b)       The  Company  has entered  into an  agreement,  which has been
                  approved  by the FERC,  with APCO and Indiana  Michigan  Power
                  Company (Indiana Michigan), operating subsidiaries of American
                  Electric   Power   Company,    to   upgrade   a   transmission
                  interconnection  with APCO in the  Company's  western  service
                  area, establish a new interconnection in the Company's eastern
                  service area and purchase 250 MW of  generating  capacity from
                  Indiana  Michigan's  Rockport  Unit No. 2  through  2009.  The
                  upgrade to the transmission  interconnection  in the Company's
                  western  service area was  completed in 1992,  and the Company
                  recently  announced  plans  to  upgrade  an  existing  138  kV
                  transmission  line between Person  County,  North Carolina and
                  Danville,    Virginia,    rather   than    establish   a   new
                  interconnection  in its eastern  service area.  The upgrade is
                  currently expected to be completed by mid-1998.  The estimated
                  minimum annual payment for power purchases under the agreement
                  is  approximately  $31 million,  representing  capital-related
                  capacity  costs.  In 1997,  purchases  under  this  agreement,
                  including transmission use charges, totaled $61.9 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, energy
                  cost  savings  are  expected  during  each of the  years  1997
                  through 2002.

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 Mayo and Harris  Plants
         through 1997 and 2007,  respectively.  The buyback period ended in 1997
         for Mayo.  The Harris Plant  buyback will continue  through  2007.  The
         estimated  minimum annual  payments for these  purchases,  representing
         capital-related   capacity  costs,  total  approximately  $26  million.
         Purchases  under the agreement  with Power Agency totaled $36.2 million
         in 1997.

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 deregulate aspects of retail electric service.  The issue of
         retail  deregulation  and  competition is being reviewed by a number of
         states  and  bills  have  been  introduced  in  Congress  that  seek to
         introduce retail deregulation 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 (those costs
         and  investments  made by  utilities  in order to meet their  statutory
         obligation  to  provide  electric  service)  if  the  market  price  of
         electricity following industry restructuring is not sufficient to cover
         those  costs.  The  amount of such  stranded  costs the  Company  might
         experience would depend on the timing of, and the

                                       9
<PAGE>

         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  results  of  operations  and  financial
         position of the Company would 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 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.

         In November 1997, the Company applied to the FERC for authority to sell
         power at market-based  rates. In January 1998, the FERC issued an order
         accepting the Company's  application and permitting the Company to sell
         power at market-based rates.

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, including California and Pennsylvania,
         have  changed  their  laws and  regulations  to allow  retail  electric
         customers  to buy power from  suppliers  other than the local  utility.
         Other states are considering similar changes,  and some have instituted
         experimental  programs to allow a limited number of customers to select
         electric  suppliers.  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.

                                       10
<PAGE>

4.       North Carolina Activities
         -------------------------
         Since  1995,  the NCUC has been  considering  the  impact of  increased
         competition in the electric  industry.  In May 1996, the NCUC issued an
         order  stating  that the FERC  Orders  888 and 889 would  provide a new
         focus for NCUC  proceedings with respect to competition in the electric
         industry.  As a result,  the NCUC held Docket No. E-100,  Sub 77, which
         concerned  retail  competition,  in abeyance  pending further order and
         established a new docket (Docket No. E-100, Sub 78) to address the FERC
         Orders 888 and 889. The NCUC has received several rounds of comments in
         this  docket;  the  Company  filed its most recent  comments  and reply
         comments in November 1997 and December 1997, respectively.  The Company
         cannot predict the outcome of this matter.

         In April 1997, the North Carolina General Assembly  (General  Assembly)
         approved  legislation  establishing  a 23-member  study  commission  to
         evaluate the future of electric service in the state. The commission is
         comprised  of 12 state  legislators,  two  residential  customers,  two
         industrial  customers,  a commercial  customer,  a power  marketer,  an
         environmentalist  and representatives from each of the four major power
         suppliers  in the state.  The  commission  is examining a wide range of
         issues  related  to the cost and  delivery  of  electric  service.  The
         commission will make an interim report to the 1998 General Assembly and
         a final report in 1999.  The Company cannot predict the outcome of this
         matter.


5.       South Carolina Activities
         -------------------------
         In  February  1997,  representatives  in  the  South  Carolina  General
         Assembly introduced a bill calling for a transition to full competition
         in the electric utility industry beginning in 1998. No action was taken
         on this bill. In addition,  by letter dated May 6, 1997, the Speaker of
         the South  Carolina House of  Representatives  requested that the South
         Carolina Public Service  Commission  (SCPSC) prepare a proposal for the
         deregulation  and  restructuring  of electricity in South Carolina.  On
         February  3,  1998,  the SCPSC  issued a report  to the South  Carolina
         General  Assembly  recommending  caution and more study on the issue of
         deregulation.  The report outlines a five-year  transition plan that it
         recommends be followed if the South Carolina  legislators  decide to go
         forward  with  deregulation.  The  South  Carolina  General  Assembly's
         Utility  Subcommittee  has completed  six hearings  around the state in
         order  to  receive  citizen  input  on  the  deregulation   issue.  The
         subcommittee  will  continue to meet.  The Company  cannot  predict the
         outcome of this matter.

6.       Federal Activities
         ------------------
         Numerous  bills were  introduced in the 105th  Congress  concerning the
         restructuring of the electric utility  industry.  Key provisions of the
         bills vary widely. Committee Chairs have held workshops and hearings to
         discuss  various  aspects of  restructuring.  No legislation was passed
         during the 1997  session of  Congress,  and more  restructuring-related
         bills are  expected to be  introduced  in  Congress  during  1998.  The
         Company cannot predict the outcome of this matter.

7.       Company Activities
         ------------------
         The   developments   described  above  have  created  greater  planning
         uncertainty and risks for the Company.  The Company has been addressing
         these  risks  by  securing  long-term   contracts  with  its  wholesale
         customers  and by  continuing  to work to meet the energy  needs of its
         industrial customers. To position itself to better address these risks,
         the Company internally  organized into separate business units in early
         1998. The

                                       11
<PAGE>

         business units include Energy Supply,  Energy Delivery and Retail Sales
         and Services.  The focus of these business units will be to further the
         development  of a corporate  culture  that is necessary to compete in a
         deregulated  environment.  Other elements of the Company's  strategy to
         respond  to the  changing  market  for  electricity  include  promoting
         economic development,  implementing new marketing strategies, improving
         customer satisfaction and increasing the focus on managing and reducing
         costs (and, consequently, avoiding future rate increases).

         In late  1996,  the  Company  and North  Carolina  Electric  Membership
         Corporation (NCEMC) entered into a revised Power Coordination Agreement
         (PCA) under which NCEMC will  receive  discounted  capacity in exchange
         for long-term commitments to the Company for its supplemental power. As
         a result of this  revised  agreement,  the Company  provided  100 MW of
         baseload  power to NCEMC in 1997,  and will  provide  a block of 225 MW
         from 1998 to 2010, an additional  block of 225 MW from 2000 to 2004 and
         a third block of 225 MW from 2001 to 2008.  The  remainder of the NCEMC
         capacity provided by the Company, not separately  contracted for in the
         revised agreement, will be billed at fixed rates through the year 2003,
         rather than at the formula rates  established  in the original PCA. The
         FERC has accepted the revised  PCA.  When NCEMC seeks future  supplies,
         the  Company  will  respond and  expects to remain  competitive  in the
         pursuit and retention of wholesale load.

         In August 1996,  Power Agency  notified the Company of its intention to
         discontinue  certain  contractual  purchases  of power from the Company
         effective  September 1, 2001.  Power Agency's notice  indicated that it
         intends to replace these contractual  obligations  through purchases of
         capacity and energy and related  services in the open market,  and that
         the  Company  will be  considered  as a  potential  supplier  for those
         purchases.  Under the 1981 Power  Coordination  Agreement,  as amended,
         between  the  Company  and Power  Agency,  Power  Agency can reduce its
         purchases from the Company with an appropriate  five-year  notice.  The
         Company and Power Agency have agreed on a process for  determining  the
         sufficiency  of the August 1996 notice.  The Company cannot predict the
         outcome of this matter.

         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  regulatory  assets and liabilities  resulting
         from  the  effects  of  the  ratemaking   process.   These  assets  and
         liabilities 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,  deregulation  and  restructuring in the
         electric utility industry.  In the event that SFAS-71 no longer applied
         to a separable portion of the Company's operations,  related regulatory
         assets  and  liabilities  would be  eliminated  unless  an  appropriate
         regulatory recovery mechanism is provided.  Additionally, these factors
         could  result in an  impairment  of electric  utility  plant  assets as
         determined pursuant to Statement of Financial  Accounting Standards No.
         121,  "Accounting  for the  Impairment  of  Long-Lived  Assets  and for
         Long-Lived Assets to Be Disposed Of."


CAPITAL REQUIREMENTS
--------------------

         Capital  Requirements.  During 1997 the Company expended  approximately
         ----------------------
         $549 million for capital  requirements.  Estimated capital requirements
         for 1998 through 2000 primarily reflect construction  expenditures that
         will be made to meet customer growth by adding generating, transmission
         and distribution facilities,  as well as upgrading existing facilities.
         The  Company's   capital   requirements,   excluding   expenditures  of
         diversified businesses,  for those years are reflected in the following
         table (in millions).

                                       12
<PAGE>
<TABLE>
<CAPTION>
                                               1998      1999      2000
                                               -----     -----     -----
<S>                                            <C>       <C>       <C>     

Construction Expenditures                      $398      $494      $526
Nuclear Fuel Expenditures                        93        83        96
AFUDC                                            (6)       (5)       (7)
                                               -----     -----     -----
Net Expenditures <F1>                           485       572       615
Mandatory Retirements of Long-Term Debt         208        53       197
TOTAL                                          $693      $625      $812
-----                                          =====     =====     =====  

<FN>
<F1>         Reflects  reductions of approximately $11 million,  $18 million and
             $7 million for 1998,  1999 and 2000,  respectively,  in net capital
             requirements resulting from Power Agency's projected payment of its
             ownership  share  of  capital  expenditures  related  to the  Joint
             Facilities.
</FN>
</TABLE>

         This table includes Clean Air Act  expenditures  of  approximately  $32
         million, and generating facility addition expenditures of approximately
         $405  million.  The  generating  facility  addition  expenditures  will
         primarily be used to construct new combustion  turbine units, which are
         intended  for use  during  periods  of high  demand.  These  units  are
         scheduled to be placed in service during 1999 through 2002. See PART I,
         ITEM  1,   "Environmental   Matters",   paragraph  2,  and  "Generating
         Capability,"  paragraph 3, for further  discussion of the impact of the
         Clean  Air  Act  on  the  Company  and  planned  generation  additions,
         respectively.

         In  addition,   total   projected  cash   requirements  of  diversified
         businesses  for the years 1998 through 2000  approximate  $362 million.
         These   expenditures    include    affordable   housing    investments,
         telecommunications  infrastructure development,  acquisitions and other
         capital  requirements of the Company's  diversified  businesses.  These
         projections are periodically reviewed and may change significantly.

FINANCING PROGRAM
-----------------

1.       Financing Requirements.  Based on the Company's most recent estimate of
         -----------------------
         capital  requirements,  external  funding  requirements,  which  do not
         include early redemptions of long-term debt or redemptions of preferred
         stock,  are expected to approximate  $220 million in 1998.  These funds
         will be required for construction,  mandatory  retirements of long-term
         debt  and  general  corporate  purposes,  including  the  repayment  of
         short-term   debt.  The  Company  expects  to  have  external   funding
         requirements  of $100  million  and  $200  million  in 1999  and  2000,
         respectively.  The amount and timing of future  sales of the  Company's
         securities will depend upon market conditions and the specific needs of
         the Company.  The Company may from time to time sell securities  beyond
         the amount  needed to meet capital  requirements  in order to allow for
         the early  redemption of long-term  debt,  the  redemption of preferred
         stock, the reduction of short-term debt or for other general  corporate
         purposes. See PART II, ITEM 7, "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
         FINANCIAL  CONDITION AND RESULTS OF OPERATIONS",  for further  analysis
         and discussion of the Company's  financing plans and capital  resources
         and liquidity.

                                       13
<PAGE>

2.       SEC Filings.
         ------------
         a)       The  Company  has on file  with the  Securities  and  Exchange
                  Commission  (SEC) a shelf  registration  statement  (File  No.
                  33-57835),  under which $250 million principal amount of first
                  mortgage  bonds  and $125  million  principal  amount of first
                  mortgage bonds and/or unsecured debt securities of the Company
                  remain available for issuance.

         b)       The  Company  has on file  with  the SEC a shelf  registration
                  statement (File No. 33-5134)  enabling the Company to issue up
                  to $180 million of Serial Preferred Stock.

3.       Issuances of Bonds, Preferred Stock and Debentures.
         ---------------------------------------------------
                  External financings during 1997 included:

                  The  issuance on August 26, 1997,  of $200  million  principal
                  amount of First Mortgage Bonds, 6.80% Series due on August 15,
                  2007. The net proceeds of approximately $199 million were used
                  to reduce  the  outstanding  balance of  commercial  paper and
                  other   short-term  debt  and  for  other  general   corporate
                  purposes.

4.       Redemptions/Retirements of Bonds, Preferred Stock and Debentures.
         -----------------------------------------------------------------
                   Redemptions and retirements during 1997 included:

         a)       The  retirement on January 24, 1997, of $60 million  principal
                  amount of First  Mortgage  Bonds,  7.75%  Secured  Medium-Term
                  Notes, Series C, which matured on that date.

         b)       The  redemption  on July 1,  1997,  of all  500,000  shares of
                  Serial Preferred Stock, $7.72 Series, at a redemption price of
                  $101.00 per share.

         c)       The  redemption  on July 1,  1997,  of all  350,000  shares of
                  Serial Preferred Stock, $7.95 Series, at a redemption price of
                  $101.00 per share.

         d)       The  retirement on October 1, 1997,  of $40 million  principal
                  amount of First Mortgage Bonds,  6-3/8% Series,  which matured
                  on that date.

5.       Credit  Facilities.  As of December 31, 1997,  the Company's  revolving
         -------------------
         credit facilities totaled $515 million,  substantially all of which are
         long-term  agreements  supporting its commercial paper borrowings.  The
         Company is required to pay minimal annual  commitment  fees to maintain
         its credit facilities.  Consistent with management's intent to maintain
         a  portion  of  its  commercial  paper  on a  long-term  basis,  and as
         supported by its long-term revolving credit facilities, the Company has
         included in its  long-term  debt  $245.9  million of  commercial  paper
         outstanding as of December 31, 1997. See PART II, ITEM 8, "CONSOLIDATED
         FINANCIAL  STATEMENTS  AND  SUPPLEMENTARY  DATA",  Note  3,  for a more
         detailed discussion of the Company's revolving credit facilities.

                                       14
<PAGE>

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.

2.       Current Retail Rates. The rates of return granted to the Company in its
         ---------------------
         most recent general rate cases are as follows:

<TABLE>
1988 North Carolina Utilities Commission Order (test year ended March 31, 1987)
-------------------------------------------------------------------------------
<CAPTION>
                        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          .65
Common Equity           44.00          12.75         5.61
                                                    -----
Rate of Return                                      10.45%
                                                    =====
</TABLE>
<TABLE>
1988 South Carolina Public Service Commission Order (test year ended 
September 30, 1987)
-------------------------------------------------------------------------------
<CAPTION>
                        Capital      Weighted    Weighted
Capital Structure        Ratio       Cost Rate     Cost
-----------------       -------      ---------     --------
<S>                     <C>          <C>           <C>  
Long-Term Debt          47.82%        8.62%         4.12%
Preferred Stock          7.46         8.75           .65
Common Equity           44.72        12.75          5.71
                                                   -----
Rate of Return                                     10.48%
                                                   =====
</TABLE>

         A petition was filed on July 19, 1996 by the Carolina  Industrial Group
         for Fair Utility Rates (CIGFUR) with the NCUC, requesting that the NCUC
         conduct  an  investigation  of the  Company's  base  rates or treat its
         petition as a complaint against the Company (Docket No. E-2, Sub. 699).
         The petition  alleged that the  Company's  return on equity  (which was
         authorized by the NCUC in the Company's last general rate proceeding in
         1988),  and earnings are too high. By order dated December 6, 1996, the
         NCUC approved the  Company's  proposal to  accelerate  amortization  of
         certain regulatory assets over a three year period beginning January 1,
         1997. The accelerated  amortization of these regulatory  assets reduced
         income by approximately $43 million, after tax, in each of the 3 years.
         The NCUC also authorized the Company to defer operation and maintenance
         expenses associated with Hurricane Fran. On December 27, 1996, the NCUC
         issued  an  order  denying  CIGFUR's   petition  and  stating  that  it
         tentatively  found no  reasonable  grounds  to  proceed  with  CIGFUR's
         petition as a complaint. On January 10, 1997, CIGFUR filed a motion for
         reconsideration  with the  NCUC,  to which  the  Company  responded  on
         January 23, 1997. On February 6, 1997, the NCUC issued an order denying
         CIGFUR's motion for reconsideration. On February 25, 1997, CIGFUR filed
         a Notice of Appeal of the NCUC order with the North  Carolina  Court of
         Appeals.  The Company filed its brief with the North  Carolina Court of
         Appeals on July 18, 1997,  and oral  argument was held before the North
         Carolina  Court of Appeals on November  19,  1997.  The Company  cannot
         predict the outcome of this matter.

                                       15
<PAGE>

3.       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. By Order issued
         September  16,  1997,  the  NCUC  initiated  a  rulemaking   proceeding
         regarding its existing IRP process.  By order issued  January 27, 1998,
         the NCUC  notified  all  interested  parties  that  given  the  pending
         rulemaking  the utilities  should not  anticipate an IRP filing in 1998
         under the current IRP rules.  The NCUC stated that an IRP filing may be
         required later in 1998, but if such a filing is required, the utilities
         will be given  sufficient  time to prepare  such a filing.  The utility
         companies  operating in South  Carolina  have filed a petition with the
         SCPSC to revise and  streamline  the South  Carolina IRP  process.  The
         Company cannot predict the outcome of these matters.

4.       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 5, 1997, the Company filed its 1997 application proposing
                  to  lower  the  Company's   billing  fuel  factor  from  1.109
                  cents/kWh to 1.097 cents/kWh. The fuel factor hearing was held
                  on August 5, 1997 and the NCUC issued a final order  approving
                  the billing  fuel factor of 1.097  cents/kWh  on  September 8,
                  1997. This new factor became effective on September 15, 1997.

         b)       In the South Carolina retail jurisdiction,  fuel rates are set
                  by  the  SCPSC.  At the  fuel  hearings,  any  past  over-  or
                  under-recovery   of  fuel  costs  is  taken  into  account  in
                  establishing  the new rate. On February 25, 1998,  the Company
                  filed a proposal  with the SCPSC to continue the existing fuel
                  factor of 1.122  cents/kWh.  In  accordance  with the modified
                  fuel cost recovery statute,  the Company's South Carolina fuel
                  proceeding  was held on March  25,  1998.  The  approved  fuel
                  factor will be effective  for the period April 1, 1998 through
                  March 31, 1999.

5.       Avoided Cost  Proceedings.  In 1996,  the NCUC opened Docket No. E-100,
         --------------------------
         Sub 79 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 4, 1996. Intervenor comments
         on the  utilities'  filings  were made on January  10,  1997.  By order
         issued June 19, 1997, the NCUC approved the updated  avoided cost rates
         and provisions that were proposed by the Company.

                                       16
<PAGE>

WHOLESALE RATE MATTERS
----------------------

1.       General.  The Company is subject to regulation by the FERC with respect
         --------
         to rates for transmission and sale of electric energy at wholesale, the
         interconnection  of  facilities  in  interstate  commerce  (other  than
         interconnections for use in the event of certain emergency situations),
         the  licensing  and  operation of  hydroelectric  projects  and, to the
         extent the FERC  determines,  accounting  policies and  practices.  The
         Company and its wholesale  customers last agreed to a general  increase
         in wholesale rates in 1988; however, wholesale rates have been adjusted
         since that time through contractual negotiations.

2.       FERC Matters.
         -------------

         a)       On July 7, 1995,  Smithfield  Foods,  Inc.,  doing business as
                  Carolina Foods  Processors,  Inc.  (Carolina  Foods),  filed a
                  Complaint  with the FERC (Docket No.  EL95-60)  alleging  that
                  certain  charges  imposed upon NCEMC under the PCA between the
                  Company and NCEMC are unreasonable.  These charges are related
                  to  generation  installed by Carolina  Foods,  which  receives
                  electric  service  from Four County EMC (a customer of NCEMC).
                  The Company  filed its response to the Complaint on August 10,
                  1995. The Company cannot predict the outcome of this matter.

         b)       On March 1, 1996,  the Company and Power Agency entered into a
                  contractual  agreement  which  provides that Power Agency will
                  delay  construction  and  startup  of its 183.7 MW  combustion
                  turbine  generating  project  until  2004.  (That  project was
                  scheduled  to  begin  commercial   operation  in  June  1998.)
                  Pursuant to a 1981 Power Coordination  Agreement,  as amended,
                  between  Power  Agency  and  the  Company,   Power  Agency  is
                  obligated to purchase this  electricity  from the Company from
                  1995 through May 31, 1998.  As a result of the new  agreement,
                  Power Agency will purchase  peaking  capacity from the Company
                  as  follows:  110 MW from June 1, 1998  through  December  31,
                  1998,  116 MW in 1999 and 183.7 MW from 2000 through 2003. The
                  Company filed the agreement with the FERC on June 6, 1997. The
                  agreement  was  accepted  by the FERC by order  dated June 27,
                  1997.

         c)       On November  13,  1997,  the  Company  applied to the FERC for
                  authority to sell power at market-based  rates. On January 12,
                  1998,  the  FERC  issued  an  order  accepting  the  Company's
                  application  and  permitting  the  Company  to sell  power  at
                  market-based rates.

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,  however, are constantly evolving and the character, scope
         and  ultimate  costs  for  compliance   with  such  evolving  laws  and
         regulations  cannot now be accurately  estimated.  The costs associated
         with  compliance  with  pollution  control laws and  regulations at the
         Company's  existing  facilities  that the Company expects to incur from
         1998 through 2000 are included in the estimates of capital requirements
         under PART I, ITEM 1, "Capital Requirements".

2.       Clean Air  Legislation.  The 1990 amendments to the Clean Air Act (Act)
         -----------------------
         require  substantial  reductions in sulfur dioxide and nitrogen  oxides
         emissions from fossil-fueled  electric  generating plants. The Act will

                                       17
<PAGE>

         require the Company to meet more stringent provisions effective January
         1,  2000.  The  Company  plans to meet  the  sulfur  dioxide  emissions
         requirements   by  utilizing  the  most   economical   combination   of
         fuel-switching and sulfur dioxide emission allowances.  Installation of
         additional  equipment  will  be  necessary  to  reduce  nitrogen  oxide
         emissions.  The  Company  estimates  that future  capital  expenditures
         necessary  to meet these  nitrogen  oxide  emission  requirements  will
         approximate $32 million.  Increased  operation and  maintenance  costs,
         including emission allowance expenses, and increased fuel costs are not
         expected to be material to the results of operations of the Company.

         In  addition,  there  are  emerging  regulatory  requirements  that may
         require  utilities  to install  additional  controls on nitrogen  oxide
         emissions and controls on toxics and  particulate  matter.  The Company
         cannot predict the outcome of these matters.

         With  regard to  revisions  to  existing  air  quality  standards,  the
         Environmental Protection Agency (EPA) issued final regulations revising
         the ozone standard and establishing a new fine-particulate  standard in
         July,  1997.   These   regulations  may  require  the  installation  of
         additional  control  equipment at some of the  Company's  fossil-fueled
         electric generating plants. The Company is evaluating the impact of the
         new regulations on its facilities and cannot  determine,  at this time,
         the  estimated  costs of  additional  controls that may be required for
         compliance  with the new  standards.  The  Company  cannot  predict the
         outcome of this matter.

3.       Superfund. The provisions of the Comprehensive  Environmental Response,
         ----------
         Compensation and Liability Act of 1980, as amended (CERCLA),  authorize
         the EPA to require  clean up of  hazardous  waste  sites.  This statute
         imposes retroactive joint and several liability. 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.

         a)       In  1986,  the  EPA  notified  the  Company  of its  potential
                  liability pursuant to CERCLA for the investigation and cleanup
                  activities  associated  with the Maxey Flats Nuclear  Disposal
                  Site,  a low-level  nuclear  waste  disposal  site  located in
                  Fleming  County,  Kentucky.  The  Company has signed a Consent
                  Decree as part of the Maxey Flats  Steering  Committee,  which
                  together  with  several  federal  agencies  will  perform  the
                  Initial   Remediation   Phase.  The  State  of  Kentucky  will
                  thereafter  perform  the  Balance of  Remediation  Phase.  The
                  Consent  Decree has been approved by the U. S. District  Court
                  for Eastern  District of Kentucky  and the work it requires is
                  in progress.  Although the Company  cannot predict the outcome
                  of this matter,  it does not anticipate that costs  associated
                  with this site will be material  to the results of  operations
                  of the Company.

         b)       By letter  dated May 21,  1991,  the EPA  notified the Company
                  that it is a Potentially  Responsible Party (PRP) with respect
                  to the disposal of hazardous  substances at the Benton Salvage
                  site in Little Rock, Arkansas.  The Company has been unable to
                  identify any records of shipments by the Company to that site.
                  Until any such documentation can be produced, the Company does
                  not intend to participate  in cleanup  activities at the site.
                  The Company cannot predict the outcome of this matter.

         c)       In 1991,  the North  Carolina  Department of  Environment  and
                  Natural Resources (DENR),  formerly North Carolina  Department
                  of  Environment,   Health,   and  Natural  Resources  (DEHNR),
                  notified  the  Company  that it is a PRP with  respect  to the
                  disposal  of  hazardous   waste  at  the   Seaboard   Chemical
                  Corporation  (Seaboard)  site in  Jamestown,  North  Carolina.
                  Seaboard is in bankruptcy.  The wastes sent from the Company's
                  facilities  to  the  Seaboard  site  consisted   primarily  of
                  cleaning and degreasing  solvents,  solvent  contaminated oils
                  and  paint-related  waste.

                                       18
<PAGE>

                  As part of the Seaboard Group (a group of PRPs with respect to
                  the  Seaboard   Site),   the  Company  has  entered  into  two
                  Administrative  Orders of Consent (AOC) with DENR, Division of
                  Waste  Management,  to  investigate  and  remediate  the site.
                  Although  the  Company  cannot  predict  the  outcome  of this
                  matter, it does not anticipate that costs associated with this
                  site would be  material to the  results of  operations  of the
                  Company.

         d)       In 1994,  Crown Cork & Seal Company,  Inc. and Clark Equipment
                  Co.  filed a motion to add the  Company as a  defendant  in an
                  ongoing  lawsuit  in the U. S.  District  Court for the Middle
                  District of North Carolina  concerning the Macon-Dockery site,
                  located near  Cordova,  North  Carolina.  The lawsuit seeks to
                  recover   costs   incurred   in   undertaking   the   Remedial
                  Investigation  Feasibility  Study and the Remedial  Design for
                  the   Macon-Dockery   site.   Wastes   disposed   of  at   the
                  Macon-Dockery  site  include  antifreeze,  used oils,  metals,
                  paint,  solvent wastes and waste acids and bases.  The Company
                  made arrangements in the past for the  transportation and sale
                  of  some  petroleum  products  to C & M  Oil  Distributors,  a
                  company  that  operated  an oil  reprocessing  facility at the
                  Macon-Dockery site. However, the information  available to the
                  Company indicates that no CERCLA hazardous wastes from Company
                  facilities were sent to the site. The court has dismissed this
                  action.  The Company  anticipates  that this  lawsuit  will be
                  refiled  shortly.  The Company  cannot  predict the outcome of
                  this matter.

         e)       Various  organic  materials  associated with the production of
                  manufactured  gas,  generally  referred  to as coal  tar,  are
                  regulated  under  various  federal and state  laws.  There are
                  several  manufactured  gas  plant  (MGP)  sites to  which  the
                  Company and certain  entities  that were later merged into the
                  Company had some  connection.  In this  regard,  the  Company,
                  along with others,  is participating  in a cooperative  effort
                  with the DENR, Division of Waste Management (DWM) to establish
                  a  uniform  framework  for  addressing  these MGP  sites.  The
                  investigation  and  remediation  of specific MGP sites will be
                  addressed  pursuant  to one or more  Administrative  Orders on
                  Consent between the DWM and the PRP. The Company  continues to
                  investigate the identities of parties  connected to individual
                  MGP sites, the relative relationships of the Company and other
                  parties to those sites and the degree  which the Company  will
                  undertake efforts with others at individual sites.

                  The Company has been notified by regulators of its involvement
                  or  potential  involvement  in several  sites,  other than MGP
                  sites,  that  require  remedial  action.  Although the Company
                  cannot  predict  the  outcome  of these  matters,  it does not
                  expect costs associated with these sites to be material to the
                  results of operations of the Company.

         f)       In 1996,  the EPA  notified  the Company that it is a PRP with
                  respect  to  the  disposal  of  hazardous  substances  at  the
                  Cherokee  Oil Company  (Cherokee)  sites in  Charlotte,  North
                  Carolina.  The materials sent from the Company's facilities to
                  the Cherokee sites were  associated with tank cleanings at the
                  Company's former  Wilmington Oil Terminal.  In 1997, a consent
                  decree  resolving  the  Company's  and  many  other  entities'
                  liability  at the site was  entered  with  the  United  States
                  District Court for the Western District of North Carolina.

4.       Other  Environmental  Matters.  In 1989,  the DENR,  Division  of Water
         ------------------------------
         Quality, formerly the Division of Environmental  Management,  requested
         that the Company address  groundwater  contamination  at its Wilmington
         Oil Terminal in New Hanover County,  North Carolina.  DENR approved the
         Company's  Corrective  Action  Plan  modifications,  which  allowed the
         Company to demonstrate to DENR's  satisfaction that natural attenuation
         will  address  this  contamination.  The  Company  has  since  sold the
         terminal,  and does not anticipate that costs associated with this site
         will be material to the results of operations of the Company.

                                       19
<PAGE>

         The Company  has filed  claims  with its  general  liability  insurance
         carriers  to  recover   costs   arising  out  of  actual  or  potential
         environmental  liabilities.  The Company  cannot predict the outcome of
         these matters.

5.       Environmental   Accrual.  The  Company  carries  a  liability  for  the
         ------------------------
         estimated  costs  associated with remedial  activities,  except for MGP
         site remediation costs. This liability is not material to the financial
         position  of the  Company.  The  MGP  site  remediation  costs  are not
         currently  determinable;  however,  the Company  does not expect  those
         costs to be material to the financial position of the Company.

NUCLEAR MATTERS
---------------

1.       General.   Under  the  Atomic   Energy  Act  of  1954  and  the  Energy
         --------
         Reorganization Act of 1974, as amended,  operation of nuclear plants is
         intensively regulated by the Nuclear Regulatory Commission (NRC), which
         has broad power to impose nuclear safety and security requirements.  In
         the event of noncompliance,  the NRC has the authority to impose fines,
         set  license  conditions,   or  shut  down  a  nuclear  unit,  or  some
         combination of these,  depending upon its assessment of the severity of
         the  situation,  until  compliance  is achieved.  The electric  utility
         industry in general  has  experienced  challenges  in a number of areas
         relating to the operation of nuclear  plants,  including  substantially
         increased capital outlays for  modifications;  the effects of inflation
         upon the cost of operations; increased costs related to compliance with
         changing  regulatory   requirements;   renewed  emphasis  on  achieving
         excellence in all phases of  operations;  unscheduled  outages;  outage
         durations;  and  uncertainties  regarding both disposal  facilities for
         low-level  radioactive  waste and storage  facilities for spent nuclear
         fuel.  See  paragraphs  2 and 3 below.  The Company  experiences  these
         challenges to varying degrees.  Capital  expenditures for modifications
         at the Company's  nuclear units,  excluding  Power  Agency's  ownership
         interests,   during   1998,   1999  and  2000  are  expected  to  total
         approximately $50 million, $45 million,  and $36 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.  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.  As of December 31, 1997,
         sufficient  on-site spent nuclear fuel storage  capability is available
         for the  full-core  discharge  of  Brunswick  Unit No. 1 through  1999,
         Brunswick Unit No. 2 through 1998, and Robinson Unit No. 2 through 2000
         assuming  normal  operating and refueling  schedules.  The Harris Plant
         spent fuel storage  facilities,  with certain  modifications,  together
         with the spent fuel storage  facilities  at the  Brunswick and Robinson
         Units, are 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 the  licenses,  dry storage may be  necessary in
         conjunction  with the  decommissioning  of the  units.  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, on April 27, 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.  Due to the success of the Company's  shipping
         efforts to date, however,  at the Company's request,  the NRC suspended
         review of the Company's license application pending notification by the
         Company of its desire to continue the application  process. The Company
         cannot predict the outcome of this matter.

                                       20
<PAGE>


         As required  by the  Nuclear  Waste Act,  the  Company  entered  into a
         contract  with the DOE in June  1983  under  which  the DOE  agreed  to
         dispose of the Company's  spent nuclear fuel. In December 1996, the DOE
         notified the Company and other  similarly  situated  utilities that the
         agency anticipated that it would be unable to begin acceptance of spent
         nuclear  fuel by January  31,  1998.  In  January  1997,  the  Company,
         together  with 35 other  utilities,  filed a Joint  Petition for Review
         with the United  States  Court of Appeals  (the Court)  requesting  the
         Court  review the final  decision  of the DOE and the DOE's  failure to
         meet its  unconditional  obligation  under the  Nuclear  Waste Act.  In
         November  1997,  the  Court  found  that  the DOE had an  unconditional
         obligation to begin disposal of spent nuclear fuel by January 31, 1998,
         and issued a writ of mandamus  precluding  the DOE from  advancing  any
         construction of the contract that would excuse the DOE's delinquency on
         the grounds that it has not yet  established a permanent  repository or
         an interim  storage  program.  The DOE  defaulted on its  obligation to
         begin  taking spent  nuclear  fuel by January 31, 1998,  and a group of
         utilities,  including the Company, is considering measures to force the
         DOE to take spent nuclear fuel or to pay damages from monies other than
         the Nuclear Waste Fund.  As of December 31, 1997,  the Company has paid
         $324 million  (including Power Agency's share), to the DOE. The Company
         cannot predict the outcome of this matter.

         By order  issued  August 20, 1997,  the NCUC  requested  comments  from
         interested  parties  regarding  the  utilities'  spent fuel storage and
         disposal  activities and costs and the reasonableness of the utilities'
         continuing  to pay a disposal  fee to the DOE after  January 31,  1998.
         Initial comments were filed by the Company and other interested parties
         on September 30, 1997.  Reply  comments were filed on October 21, 1997.
         The Company cannot predict the outcome of this matter.

         In October of 1997, the U.S. House of Representatives  voted 307 to 120
         in favor of  legislation  calling  for the  construction  of an interim
         nuclear  waste storage site in Nevada by 2002. A similar waste bill was
         approved  by the U.S.  Senate  in April of  1997.  The  Company  cannot
         predict the outcome of this matter.

3.       Low-Level  Radioactive Waste.  Disposal costs for low-level radioactive
         -----------------------------
         waste that result from normal operation of nuclear units have increased
         significantly  in recent  years and are  expected  to continue to rise.
         Pursuant to the  Low-Level  Radioactive  Waste  Policy Act of 1980,  as
         amended in 1985,  each state is  responsible  for disposal of low-level
         waste  generated in that state.  States that do not have existing sites
         may join in regional  compacts.  The States of North and South Carolina
         were  participants  in the Southeast  regional  compact and disposed of
         waste at a disposal site in South  Carolina along with other members of
         the compact.  Effective July 1, 1995, South Carolina  withdrew from the
         Southeast regional compact and excluded North Carolina waste generators
         from the existing  disposal site in South  Carolina.  As a result,  the
         State of North Carolina does not have access to a low-level radioactive
         waste disposal facility. The North Carolina Low-Level Radioactive Waste
         Management  Authority,  which is responsible for siting and operating a
         new low-level  radioactive  waste  disposal  facility for the Southeast
         regional compact,  has submitted a license  application for the site it
         selected in Wake County,  North Carolina to the North Carolina Division
         of Radiation  Protection.  In December  1997,  the  Southeast  Regional
         Compact  Commission   suspended  funding  for  the  proposed  low-level
         radioactive waste facility in Wake County.  The future funding for this
         project  remains  uncertain.  Although the Company does not control the
         future availability of low-level waste disposal facilities, the cost of
         waste disposal or the development  process, it supports the development
         of new  facilities  and is  committed  to a timely  and  cost-effective
         solution to low-level waste disposal.  The Company's  nuclear plants in
         North Carolina are currently  storing  low-level  waste on site and are
         developing additional storage capacity to accommodate future needs. The
         Company's  nuclear  plant in South  Carolina has access to the existing
         disposal site in South  Carolina.  Although the Company  cannot predict
         the outcome of this  matter,  it does not expect the cost of  providing
         additional on-site storage capacity for low-level  radioactive waste to
         be material to the results of operations  or financial  position of the
         Company.

                                       21
<PAGE>

4.       Decommissioning.
         ----------------

         a)       Pursuant to an NRC rule,  licensees of nuclear  facilities are
                  required to submit  decommissioning  funding  plans to the NRC
                  for approval to provide reasonable assurance that the licensee
                  will   have   the   financial   ability   to   implement   its
                  decommissioning  plan for  each  facility.  The rule  requires
                  licensees  to do one of the  following:  prepay  at  least  an
                  NRC-prescribed minimum amount immediately;  set up an external
                  sinking fund for  accumulation of at least that minimum amount
                  over the operating  life of the facility;  or provide a surety
                  to  guarantee  financial  performance  in  the  event  of  the
                  licensee's    financial    inability    to   perform    actual
                  decommissioning.  On July 26, 1990, the Company  submitted its
                  decommissioning  funding plans to the NRC. In this regard, the
                  Company entered into a Master  Decommissioning Trust Agreement
                  dated  July 19,  1990  (Trust),  with  Wachovia  Bank of North
                  Carolina,  N.A.,  as  Trustee,  as a vehicle to  achieve  such
                  decommissioning  funding.  In June  1991,  the  Company  began
                  depositing funds into the Trust.

                  With regard to the Company's recovery through rates of nuclear
                  decommissioning  costs, in the Company's retail jurisdictions,
                  provisions for nuclear  decommissioning costs were approved by
                  the NCUC and the  SCPSC in the  Company's  1988  general  rate
                  cases, and were 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 $33.2 million,  $33.1 million and
                  $31.2   million   in  1997,   1996  and  1995,   respectively.
                  Accumulated  decommissioning  costs,  which  are  included  in
                  accumulated depreciation, were $428.7 million and $326 million
                  at  December  31,  1997 and 1996,  respectively.  These  costs
                  include amounts  retained  internally and amounts funded in an
                  external  decommissioning  trust.  The  balance of the nuclear
                  decommissioning trust was $245.5 million and $145.3 million at
                  December  31,  1997 and  1996,  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.  Based on the
                  site-specific  estimates  discussed below and using an assumed
                  after-tax earnings rate of 8.5% 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 1993 using 1993 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 1993 dollars,  are
                  $257.7  million for  Robinson  Unit No. 2, $235.4  million for
                  Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2,
                  and $284.3 million for the Harris Plant.  These  estimates are
                  subject to change  based on a variety of  factors,  including,
                  but not  limited to, cost  escalation,  changes in  technology
                  applicable to nuclear decommissioning, and changes in federal,
                  state or local  regulations.  The cost  estimates  exclude the
                  portion attributable to Power Agency, which holds an undivided
                  ownership   interest  in  the  Brunswick  and  Harris  nuclear
                  generating   facilities.   To  the  extent  of  its  ownership
                  interests,  Power Agency is  responsible  for  satisfying  the
                  NRC's financial  assurance  requirements  for  decommissioning
                  costs.  See  PART  I,  ITEM  1,   "Generating   Capabilities",
                  paragraph 1.

         c)       The Financial  Accounting  Standards Board has reached several
                  tentative  conclusions  with respect to its project  regarding
                  accounting   practices  related  to  closure  and  removal  of
                  long-lived  assets.  It 

                                       22
<PAGE>
                  is uncertain when the final  statement will be issued and what
                  impacts it may ultimately have on the Company's accounting for
                  nuclear decommissioning and other closure and removal 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.

<TABLE>
                              Facility Operating License
<CAPTION>
                    Facility                         Expiration Date
                    --------                         ---------------
                    <S>                              <C>    

                    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
</TABLE>

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.
                  The Company has been working  closely with the Nuclear  Energy
                  Institute  (formerly  the  Nuclear  Management  and  Resources
                  Council) and with other  utilities  to develop its  compliance
                  approach and to minimize the financial and operational impacts
                  of the new rule. The Company  anticipates  its compliance will
                  be  on  schedule  and  is  evaluating  the  magnitude  of  the
                  financial and operational  impacts of this new rule.  Although
                  the Company cannot predict the outcome of this matter, it does
                  not expect the  impacts of the new rule to be  material to the
                  Company's results of operations.

         b)       On November 23,  1988,  the NRC  requested  in Generic  Letter
                  88-20 that utilities  perform  Individual  Plant  Examinations
                  (IPEs)  to  determine  potential   vulnerabilities  to  severe
                  accidents  beyond the  design  basis  accidents  for which the
                  plants  are  designed.  These  are  considered  to be very low
                  probability  events.  The Company submitted the results of the
                  first phase (for internally  initiated  events) in August 1992
                  for the Brunswick and Robinson Plants. Based on those results,
                  potential  enhancements  for the Robinson Plant were evaluated
                  and  several  enhancements  were made to the  Robinson  Plant.
                  These  changes had  insignificant  financial  and  operational
                  impacts.  For  the  Brunswick  Plant,  no  modifications  were
                  required  to meet the  guidelines  of the IPE.  On August  20,
                  1993,  the Company  submitted  the results of the Harris Plant
                  IPE. While some Harris Plant procedural  changes were made due
                  to the IPE results,  the IPE did not result in any significant
                  financial  or  operational  impacts or  identify  any need for
                  plant  modifications.  In June 1995, the Company completed and
                  submitted  the  results of the  second  phase of the IPEs (for
                  externally  initiated  events) for the Company's three nuclear
                  plants. The results of the IPEs indicated that some procedural
                  changes may be required for the Harris and  Brunswick  Plants.
                  Those  results  also  indicated  that  both  minor  procedural
                  changes and minor plant modifications will be required for the
                  Robinson   Plant.   All  IPE  items  and  findings  have  been
                  addressed,  with implementation completed in all areas, except
                  for those items which are being  addressed  through the Severe
                  Accident   Management   Guideline  programs  at  each  of  the
                  Company's  nuclear  plants.  The  programs  are targeted to be
                  fully  implemented  by  year-end  1998.  Although  the Company

                                       23
<PAGE>

                  cannot  predict  at  this  time  the  exact  magnitude  of the
                  financial and  operational  impacts of the second phase of the
                  IPEs,  it does not expect those  impacts to be material to the
                  results of operations or financial position of the Company.

         c)       Degradation  of  tubing   internal  to  steam   generators  in
                  pressurized  water reactor  power plants due to  intergranular
                  stress  corrosion  cracking  has  been  an  on-going  industry
                  phenomenon.   The  Company  has  determined   that  the  steam
                  generators at the Harris Plant are subject to steam  generator
                  degradation  and the Company is closely  monitoring  the steam
                  generator  performance.  Experience  and testing  conducted to
                  date indicate that the Harris Plant steam  generators will not
                  require  replacement  before 2000. The steam generators at the
                  H.B.  Robinson plant were replaced in 1984 and are expected to
                  perform until the plant's operating license expires.  Although
                  the Company cannot predict the outcome of this matter, it does
                  not expect the cost of replacing  the steam  generators at the
                  Harris  Plant to be material to the results of  operations  or
                  financial position of the Company.

         d)       The Company is insured against public  liability for a nuclear
                  incident  up to $8.9  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
                  $75.5 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 11 b.

FUEL
----
1.       Sources  of  Generation.   Total  system  generation  (including  Power
         ------------------------
         Agency's share) by primary energy source,  along with purchased  power,
         for the years 1994 through 1998 is set forth below:

<TABLE>
<CAPTION>
                       1994        1995        1996       1997        1998
                       ----        ----        ----       ----        ----
                                                            (estimated)
    <S>                <C>         <C>         <C>        <C>         <C>
    Fossil             43%         44%         45%        46%         51%
    Nuclear            42          42          41         43          39
    Purchased Power    13          13          12         10           9
    Hydro               2           1           2          1           1
</TABLE>


2.       Coal. a) The Company has  intermediate  and long-term  agreements  from
         -----
         which  it  expects  to  receive  approximately  73%  of its  coal  burn
         requirements in 1998.  During both 1996 and 1997, the Company  obtained
         approximately  68% (7,181,257 tons and 7,398,850 tons in 1996 and 1997,
         respectively),  of its coal burn  requirements  from  intermediate  and
         long-term agreements. Existing agreements have expiration dates ranging
         from 1998 to 2006.  During 1997, the Company  maintained  from 25 to 62
         system days' supply of coal, based on anticipated burn rate. 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  

                                       24
<PAGE>

         Matters",  paragraph 2. The Company purchased  approximately  3,340,000
         tons of coal in the spot market during 1996 and 3,125,000 tons in 1997.
         The Company's  contract  coal  purchase  prices during 1997 ranged from
         approximately  $21.64 to $41.5 per ton (F.O.B.  mine adjusted to 12,000
         Btu/lb.).  The average  cost  (including  transportation  costs) to the
         Company of coal delivered for the past five years is as follows:

<TABLE>
<CAPTION>
                  Year         Dollars/Ton        Cents/Million BTU
                  ----         -----------        -----------------
                  <S>             <C>                     <C>    
                  1993            43.10                   172
                  1994            43.36                   174
                  1995            44.46                   179
                  1996            42.21                   170
                  1997            41.42                   169
</TABLE>
 
         b)       The Company and certain  subsidiaries  of Zeigler Coal Holding
                  Company (Zeigler) have renegotiated  their existing  contract.
                  Under  the  revised  agreement,  which  expires  in 2006,  the
                  Company will continue to purchase  approximately  2.75 million
                  tons of coal annually from Zeigler's Marrowbone mine, and will
                  purchase  approximately  6 million tons of  additional,  lower
                  cost coal from Zeigler over a period of several  years under a
                  new  contract.  The  coal  will be  required  to meet the same
                  technical specifications for sulfur and thermal content as the
                  coal supplied  from the  Marrowbone  mine,  and is expected to
                  save the Company  more than $100  million over the life of the
                  contract.

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  burned
         approximately  12.1 million  gallons and 18.3 million  gallons of No. 2
         oil during  1996 and 1997,  respectively.  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 dislocations in
         the oil market,  seven combustion turbine units with a total generating
         capacity of 364 MW have been  converted to burn either propane or No. 2
         oil.  In  addition,  fourteen  combustion  turbine  units  with a total
         generating capacity of 665 MW can burn natural gas when available. Over
         the last five years, No. 2 oil,  natural gas and propane  accounted for
         2.4% of the  Company's  total  burned  fuel cost.  In 1997,  No. 2 oil,
         natural  gas and  propane  accounted  for 3.7% of the  Company's  total
         burned  fuel  cost.  The  availability  and cost of fuel  oil  could be
         adversely   affected  by  energy   legislation   enacted  by  Congress,
         disruption  of oil or gas  supplies,  labor unrest and the  production,
         pricing and embargo policies of foreign countries.

4.       Nuclear.  The  nuclear  fuel cycle  requires  the mining and milling of
         --------
         uranium ore to provide uranium oxide concentrate (U3O8), the conversion
         of U3O8 to uranium  hexafluoride  (UF6),  the enrichment of the UF6 and
         the fabrication of the enriched uranium into fuel assemblies.  Existing
         uranium  contracts are expected to supply the necessary nuclear fuel to
         operate Robinson Unit No. 2 through 1998,  Brunswick Unit No. 1 through
         1998,  Brunswick  Unit No. 2 through 1998 and the Harris Plant  through
         1999.

         The Company expects to meet its future U3O8 requirements from inventory
         on hand and  amounts  received  under  contract.  Although  the Company
         cannot  predict the future  availability  of uranium  and nuclear  fuel
         services,  the Company  does not  currently  expect to have  difficulty
         obtaining  U3O8  and  the  services 

                                       25
<PAGE>

         necessary for its conversion,  enrichment and fabrication  into nuclear
         fuel.  For a discussion  of the  Company's  plans with respect to spent
         fuel storage, see PART I, ITEM 1, "Nuclear Matters", paragraph 2.

5.       DOE Enrichment  Facilities  Decontamination and  Decommissioning  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  will  be  based  on that  utility's  past  purchases  of
         services  as  a  percentage  of  all  purchases  of  services  by  U.S.
         utilities,  with total annual  contributions capped at $150 million per
         year, indexed to inflation, and an overall cap of $2.25 billion over 15
         years,  also indexed to inflation.  The Company has paid  approximately
         $29 million in D&D fees through  1997,  and expects to pay a cumulative
         total of  approximately  $83  million  over the 15 year  period  ending
         September 30, 2007  (excluding  Power Agency's  ownership  share).  The
         Company is recovering these costs as a component of fuel cost.

         On or about  March 4,  1997,  the  Company  filed a claim  with the DOE
         seeking  a  refund  of  part  of the  price  paid  by the  Company  for
         enrichment services purchased from the DOE in 1993. It is the Company's
         position  that the  contract  price it paid to DOE in 1993 for  uranium
         purchases  included  the cost of D&D,  and  that  DOE's  collection  of
         additional  D&D  fees  pursuant  to  the  Energy  Act  resulted  in  an
         overpayment of fees by the Company totaling approximately $1.4 million.
         The Company cannot predict the outcome of this matter.

         Additionally, on or about March 21, 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
         the recovery of  approximately  $27 million  (including  Power Agency's
         ownership  share)  representing  D&D  assessments  paid by the  Company
         through 1996, and the elimination of future D&D fund assessments. It is
         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  has been  stayed
         pending the outcome of a similar case,  Yankee Atomic Electric  Company
         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.  The Company cannot predict the outcome of these
         matters.

6.       Purchased Power. The Company purchased 5,886,722 MWh in 1997, 6,792,340
         ----------------
         MWh in 1996 and  6,974,597  MWh in 1995 or  approximately  10%, 12% and
         13%, respectively,  of its system energy requirements  (including Power
         Agency) and had available 1,839 MW in 1997,  1,536 MW in 1996 and 1,596
         MW in 1995 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.  

DIVERSIFIED BUSINESSES
----------------------

1.       Interpath  Communications,  Inc. (formerly CaroNet,  LLC). In 1997, the
         ----------------------------------------------------------
         Company  created  a  new  subsidiary,  Interpath  Communications,  Inc.
         (Interpath).  All of CaroNet,  LLC's assets,  liabilities and operating
         certificates are being transferred to Interpath. Interpath has acquired
         Capitol  Information  Services,   Inc.,  a  regional  Internet  service
         provider  based in Raleigh,  North  Carolina.  Interpath  will  provide

                                       26
<PAGE>
         Internet retail  telecommunications  solutions and will expand services
         to include more telecommunications business solutions,  including voice
         and data applications for small and medium-sized businesses.

         Interpath  also owns a 10% limited  partnership  interest in  BellSouth
         Carolinas PCS, L.P. BellSouth Personal Communications, Inc. manages the
         partnership as the general  partner.  PCS is a wireless  communications
         technology  that  provides  high-quality  mobile  communications.   The
         partnership  serves PCS  subscribers  in North and South Carolina and a
         small  portion of Georgia  pursuant to a license  issued by the Federal
         Communications Commission.

2.       CaroHome,  LLC.  In 1995,  the  Company  established  CaroHome,  LLC, a
         ---------------
         limited  liability  company,  to further the Company's  investments  in
         affordable housing.  These investments are designed to earn tax credits
         while helping communities meet their needs for affordable housing.  The
         Company,  principally through CaroHome,  LLC, has invested or committed
         to invest a total of $58 million in affordable  housing and anticipates
         investing  up to a total of $125 million in  affordable  housing by the
         year 2000.

3.       Strategic Resource  Solutions Corp.  (formerly  CaroCapital,  Inc.). In
         --------------------------------------------------------------------
         1997, CaroCapital, Inc. (CaroCapital), a wholly owned subsidiary of the
         Company,  acquired the remaining interest in Knowledge  Builders,  Inc.
         (KBI) and entered into a merger  agreement  under which KBI, was merged
         into  CaroCapital.  KBI was an  energy-management  software and control
         systems company in which CaroCapital  purchased a 40% interest in 1996.
         Pursuant to the merger  agreement the remaining KBI stock was exchanged
         for shares of common  stock of the Company  according to a market value
         formula.   Initial   payments  under  the  merger   agreement   totaled
         approximately $22 million, payable primarily in unregistered restricted
         shares  of the  Company's  common  stock.  The  merger  agreement  also
         provides  for other  incentive  payments  that may be earned by the KBI
         founders  based on  CaroCapital's  future  results  of  operations.  If
         earned,   these   additional   payments  will  be  made   primarily  in
         unregistered,  restricted  shares of the Company's common stock (valued
         according to a market value  formula).  Following the completion of the
         merger,  CaroCapital's name was changed to Strategic Resource Solutions
         Corp.  (SRS),  a  North  Carolina  Enterprise  Corporation.  SRS  is  a
         technology-based energy services company delivering facility-management
         and  energy-management   products  and  services  to  the  educational,
         commercial,  industrial and  governmental  markets  nationwide.  During
         1997, SRS purchased  Diversified Control Systems, a building automation
         systems  company,  and made a  minority  investment  in  Remote  Source
         Lighting International,  Inc., a fiber optic lighting company. Also, in
         January 1998, SRS acquired the assets of Parke Industries, Inc. (Parke)
         a lighting  technology  and  management  company.  Parke was the fourth
         largest  lighting  company  in the  United  States.  These  investments
         enhance  SRS's  ability  to  deliver  energy-management  solutions  and
         value-added products into the marketplace.

OTHER MATTERS
-------------

1.       Safety Inspection  Reports. On April 3, 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  requesting  the  Company  to
         undertake certain  supplemental  analyses and investigations  regarding
         the  stability  of  the  dam  under  extreme  and  improbable   loading
         conditions. Similar letters were sent by the FERC on May 30, 1990, with
         respect to the Company's Blewett and Tillery Hydroelectric Plants. With
         the independent consultant, the Company has begun addressing the issues
         raised  by  the  FERC  and  is  working   with  the  FERC  to  complete
         investigations  and analyses with respect to each of these matters.  On
         November 30, 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.  While the Company
         does not believe that there are any  stability  concerns  that would be
         cause for any imminent safety concerns,  the FERC's review and analysis
         of the consultant's report are pending.  The consultant's 

                                       27
<PAGE>

         final reports  regarding the Blewett and Tillery  Hydroelectric  Plants
         are not yet  completed.  On February 27, 1997,  the Company  received a
         letter from the FERC  pertaining  to the  Company's  inspection  report
         filed in November 1994.  The FERC submitted  comments on the inspection
         report and requested  that further  analysis be conducted.  The Company
         filed a response on April 24, 1997, to the FERC's letter dated February
         27, 1997. In its response,  the Company  agreed with some of the FERC's
         comments and took  exception to others.  The Company has not received a
         reply from the FERC as of this date.  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 these
         matters.

2.       Marshall Hydroelectric Project. On November 21, 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.  On  April  6,  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 by letter dated  September
         15, 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.       Stone  Container  Dispute.  On April  20,  1994,  the  Company  filed a
         --------------------------
         Complaint with the FERC (Docket No.  EL-94-62-000 and QF85-102-005) and
         in the United States  District Court for the Eastern  District of North
         Carolina in Raleigh,  North Carolina (Civil Action No.  5:94-CV-285-DI)
         claiming  that the rate the Company  pays for power it  purchases  from
         Stone Container  Corporation (Stone Container) is invalid.  The Company
         entered  into  a  twenty-year   purchase  power  agreement  with  Stone
         Container  in  1984,  and  in  1987  began   receiving   power  from  a
         cogeneration  facility  operated by Stone Container in Florence,  South
         Carolina.  It is the  Company's  position  that  when  Stone  Container
         elected to sell the facility's  gross output under a "buy all/sell all"
         option in 1991, the facility lost its status as a "qualified  facility"
         under the Public Utilities  Regulatory Policies Act and became a public
         utility.  As a result,  the  contract  rate the Company  pays for power
         purchased  from  the  facility  is no  longer  valid,  and a  just  and
         reasonable  rate  should be  established  by the FERC under the Federal
         Power Act. On February 12, 1998,  the FERC issued an order  denying the
         Company's claim that the rate it pays for power it purchases from Stone
         Container  is invalid.  As a result,  the Company will file a motion to
         dismiss  the  District  Court  action.  The  Company  will  continue to
         purchase electricity from Stone Container at the current contract rate.

4.       Tax Refund  Dispute.  On April 28, 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.  On  December  19,  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>


<TABLE>
OPERATING STATISTICS
--------------------
<CAPTION>
                                                                               Years Ended December 31

                                                            1997           1996          1995          1994           1993
                                                         -----------    -----------   -----------   -----------    -----------
<S>                                                   <C>            <C>            <C>           <C>           <C>       
Energy supply (millions of kWh)
  Generated - coal                                           25,545         24,859        23,517        21,001         25,807
              nuclear                                        21,690         20,284        19,949        18,511         13,691
              hydro                                             799            882           824           884            784
              combustion turbines                               189             68            56            67             84
  Purchased                                                   6,318          7,292         7,433         7,039          7,110
                                                         -----------    -----------   -----------   -----------    -----------
      Total energy supply (Company share)                    54,541         53,385        51,779        47,502         47,476
  Power Agency share <F1>                                     4,101          3,616         3,828         3,236          2,402
                                                         -----------    -----------   -----------   -----------    -----------
      Total system energy supply                             58,642         57,001        55,607        50,738         49,878
                                                         ===========    ===========   ===========   ===========    ===========
Average fuel cost (per million BTU)
  Fossil                                              $        1.75  $        1.75  $       1.83  $       1.78  $        1.75
  Nuclear fuel                                                 0.46           0.45          0.46          0.47           0.46
  All fuels                                                    1.14           1.14          1.17          1.14           1.28
Energy sales (millions of kWh)
  Residential                                                12,488         12,611        12,074        11,147         11,398
  Commercial                                                 10,010          9,615         9,276         8,690          8,548
  Industrial                                                 15,073         14,456        14,312        14,030         13,557
  Government and municipal                                    1,294          1,263         1,288         1,263          1,248
  Power Agency contract requirements                          2,072          2,523         2,338         2,589          3,505
  NCEMC                                                       4,174          3,947         5,454         4,885          4,778
  Other wholesale                                             2,120          2,014         1,915         1,983          2,144
  Other utilities                                             5,534          4,899         3,233           985            327
                                                         -----------    -----------   -----------   -----------    -----------
      Total energy sales                                     52,765         51,328        49,890        45,572         45,505
  Company uses and losses                                     1,776          2,057         1,889         1,930          1,971
                                                         -----------    -----------   -----------   -----------    -----------
      Total energy requirements                              54,541         53,385        51,779        47,502         47,476
                                                         ===========    ===========   ===========   ===========    ===========
Customers billed
  Residential                                               972,385        945,703       920,495       894,616        873,377
  Commercial                                                172,821        167,151       159,064       155,349        151,242
  Industrial                                                  5,072          5,066         4,863         4,845          4,825
  Government and municipal                                    2,785          2,774         2,328         2,302          2,214
  Resale                                                         43             27            17            12             26
                                                         -----------    -----------   -----------   -----------    -----------
      Total customers billed                              1,153,106      1,120,721     1,086,767     1,057,124      1,031,684
                                                         ===========    ===========   ===========   ===========  =============
Operating revenues (in thousands)
  Residential                                         $     986,835  $     992,152  $    969,112  $    915,986  $     943,697
  Commercial                                                648,440        627,880       618,394       595,573        592,973
  Industrial                                                738,084        721,588       733,448       741,662        744,016
  Government and municipal                                   77,150         75,391        78,400        78,317         78,616
  Power Agency contract requirements                         71,318         96,795       100,951       115,262        134,258
  NCEMC                                                     225,951        234,653       299,171       266,733        253,859
  Other wholesale                                            92,084         87,463        82,407        84,775        100,062
  Other utilities                                           129,085        105,077        78,147        33,789         11,232
  Miscellaneous revenue                                      55,142         54,716        46,523        44,492         36,670
                                                         -----------    -----------   -----------   -----------    -----------
      Total operating revenues                        $   3,024,089  $   2,995,715  $  3,006,553  $  2,876,589  $   2,895,383
                                                         ===========    ===========   ===========   ===========    ===========
Peak demand of firm load (thousands of kW)
  System                                                     10,030          9,812        10,156        10,144          9,589
  Company                                                     9,344          9,264         9,500         9,642          9,107
Total capability at year-end (thousands of kW) <F2>
  Fossil plants                                               6,571          6,331         6,331         6,331          6,331
  Nuclear plants                                              3,064          3,064         3,064         3,064          3,064
  Hydro plants                                                  218            218           218           218            218
  Purchased                                                   1,588          1,603         1,592         1,596          1,289
                                                         -----------    -----------   -----------   -----------    -----------
      Total system capability                                11,441         11,216        11,205        11,209         10,902
Less Power Agency-owned portion <F1>                            690            686           682           654            627
                                                         -----------    -----------   -----------   -----------    -----------
      Total Company capability                               10,751         10,530        10,523        10,555         10,275
                                                         ===========    ===========   ===========   ===========    ===========
<FN>
<F1>
Net of the Company's purchases from Power Agency.
<F2>
Represents  peak  generating  capability,  based on summer  peak  conditions
Assuming all generating  units are available for operation.  Amounts include
capacity under contract with  cogenerators,  small power producers and other
utilities.
</FN>
</TABLE>

                                       29
<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,  with a total generating capacity (including Power
Agency's  share)  of 9,853  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, automotive components and electronic machinery and equipment.

At December 31,  1997,  the Company had 5,586 pole miles of  transmission  lines
including  292  miles of 500 kV lines  and  2,916  miles  of 230 kV  lines,  and
distribution  lines of  approximately  43,764 pole miles of  overhead  lines and
approximately  11,604 miles of underground lines.  Distribution and transmission
substations in service had a transformer capacity of approximately 36,253 kVA in
2,245  transformers.  Distribution  line  transformers  numbered 413,269 with an
aggregate 17,204,000 kVA capacity.

Power Agency has acquired undivided  ownership  interests of 18.33% in Brunswick
Unit Nos. 1 and 2, 12.94% in Roxboro  Unit No. 4 and 16.17% in Harris Unit No. 1
and Mayo Unit No. 1. Otherwise, the Company has good and marketable title to its
principal  plants and important  units,  subject to the lien of its Mortgage and
Deed  of  Trust,  with  minor  exceptions,  restrictions,  and  reservations  in
conveyances,  as well  as  minor  defects  of the  nature  ordinarily  found  in
properties  of similar  character and  magnitude.  The Company also owns certain
easements over private property on which transmission and distribution lines are
located.

The Company  believes that its  generating  facilities  are suitable,  adequate,
well-maintained and in good operating condition.

Plant  Accounts  (including  nuclear  fuel) - During the period  January 1, 1993
-------------------------------------------
through  December  31, 1997,  there was  $2,434,308,343  added to the  Company's
utility plant accounts,  there was  $689,400,439  of property  retired and there
were  transfers  and  adjustments  of  $(51,673,030)  resulting in net additions
during the period of $1,693,234,874, an increase of approximately 15.55%.

                                       30
<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.

                                       31
<PAGE>

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
-------    ---------------------------------------------------

No matters were submitted to a vote of security holders in the fourth quarter of
1997.

                                       32
<PAGE>

<TABLE>
                      EXECUTIVE OFFICERS OF THE REGISTRANT
<CAPTION>
Name                                Age           Recent Business Experience
<S>                                 <C>    <C> 
William Cavanaugh III               59     President    and   Chief    Executive
                                           Officer,  October  1996  to  present;
                                           President    and   Chief    Operating
                                           Officer,  September  1992 to  October
                                           1996. Before joining the Company, Mr.
                                           Cavanaugh    held   various    senior
                                           management  and  executive  positions
                                           during a 23-year  career with Entergy
                                           Corporation,   an  electric   utility
                                           holding  company with  operations  in
                                           Arkansas,  Louisiana and Mississippi.
                                           Member of the Board of  Directors  of
                                           the Company since 1993.

Glenn E. Harder                     47     Executive  Vice  President  and Chief
                                           Financial     Officer,      Financial
                                           Services,  August  1995  to  present;
                                           Senior    Vice    President,    Group
                                           Executive   -   Financial   Services,
                                           October 1994 to August  1995.  Before
                                           joining the Company,  Mr. Harder held
                                           various    senior    management   and
                                           executive   positions   with  Entergy
                                           Corporation,   an  electric   utility
                                           holding  company with  operations  in
                                           Arkansas,  Louisiana and Mississippi,
                                           and related entities.

William S. Orser                    53     Executive  Vice  President  and Chief
                                           Nuclear   Officer,   Energy   Supply,
                                           December  1996 to present;  Executive
                                           Vice President - Nuclear  Generation,
                                           April   1993   to   December    1996;
                                           Executive  Vice  President  - Nuclear
                                           Generation,  Detroit Edison  Company,
                                           April 1993;  Senior Vice  President -
                                           Nuclear  Generation,  Detroit  Edison
                                           Company.  Prior  to 1987,  Mr.  Orser
                                           held  various  other  positions  with
                                           Detroit  Edison,  and  with  Portland
                                           General  Electric  Company,  Southern
                                           California  Edison,  and  the  U.  S.
                                           Navy.

James M. Davis, Jr.                 61     Senior    Vice    President,    Group
                                           Executive  - Power  Operations,  June
                                           1986   to   present;    Senior   Vice
                                           President - Operations Support Group,
                                           August 1983.

Fred N. Day, IV                     54     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                  54     Senior  Vice   President   and  Chief
                                           Administrative               Officer,
                                           Administrative   Services,   December
                                           1996   to   present;    Senior   Vice
                                           President,    Human   Resources   and
                                           Support    Services,    March   1995-
                                           December 1996; Vice President - Human
                                           Resources      (formerly     Employee
                                           Relations  Department),  May  1983 to
                                           March 1995.

John E. Manczak                     50     Senior Vice  President,  Retail Sales
                                           and  Services,  June 1997 to present;
                                           Vice  President,   Retail  Marketing,
                                           Consumers Energy, an electric and gas
                                           utility,  October  1994 to June 1997;
                                           President,  Michigan Gas Utilities, a
                                           division  of  Utilicorp   United,   a
                                           natural gas utility,  October 1991 to
                                           September 1994.

                                       33
<PAGE>

Robert B. McGehee                   55     Senior  Vice  President  and  General
                                           Counsel,    Public   and    Corporate
                                           Relations,  May 1997 to present; 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.

Bonnie V. Hancock                   36     Vice   President   and    Controller,
                                           February  1997 to  present;  Manager,
                                           Tax  Department,  September  1995  to
                                           February  1997;  Director,  Corporate
                                           Income  Tax,   Treasury   Department,
                                           September  1993  to  September  1995.
                                           Before   joining  the  Company,   Ms.
                                           Hancock   held   various   management
                                           positions  in the Tax  Department  at
                                           Potomac Electric Power Company.
</TABLE>

                                       34
<PAGE>

                                                      PART II

ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER 
-------    MATTERS
           -----------------------------------------------------------------
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  paid per share are as
follows:
<TABLE>
<CAPTION>
1996                  High           Low             Dividends Paid
-----                 ----           ---             --------------
<S>                  <C>            <C>              <C>  
First Quarter        $38 3/8        $34 1/2          $ .455
Second Quarter        38             34 7/8            .455
Third Quarter         38 1/4         34 1/8            .455
Fourth Quarter        37             34 1/4            .455
</TABLE>
<TABLE>
<CAPTION>
1997                  High           Low             Dividends Paid
-----                 ----           ---             --------------
<S>                  <C>            <C>              <C>  
First Quarter        $37 7/8        $36 1/8          $ .47
Second Quarter        36 1/4         33                .47
Third Quarter         36 5/8         33 3/4            .47
Fourth Quarter        42 1/2         34 5/16           .47
</TABLE>

The December 31 closing price of the Company's  Common Stock was $36 1/2 in 1996
and $42 3/8 in 1997.

As of February  27,  1998,  the  Company had 71,017  holders of record of Common
Stock.

On July  13,  1994,  the  Board  of  Directors  of the  Company  authorized  the
repurchase of up to 10 million shares of the Company's  Common Stock on the open
market. Under this stock repurchase program, the Company purchased approximately
0.7 million  shares in 1997 and 1996, 4.2 million shares in 1995 and 4.4 million
shares in 1994.  The program was completed in 1997.

                                       35
<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>
                                                           Years Ended December 31
<CAPTION>
                                           1997             1996             1995              1994             1993
                                        -----------      -----------      ------------      -----------      ------------
                                                        (dollars in thousands except per share data)
<S>                                  <C>              <C>               <C>              <C>               <C>          
Operating results
-----------------
  Operating revenues                 $   3,024,089    $   2,995,715     $   3,006,553    $   2,876,589     $   2,895,383
  Net income                         $     388,317    $     391,277     $     372,604    $     313,167     $     346,496
  Earnings for common stock          $     382,265    $     381,668     $     362,995    $     303,558     $     336,887

Ratio of earnings to fixed charges            4.17             4.12              3.67             3.31              3.23
----------------------------------

Per share data
--------------
  Basic and diluted earnings per
     common share                    $        2.66    $        2.66     $        2.48    $        2.03     $        2.10
  Dividends declared per common
     share                           $       1.895    $       1.835     $       1.775    $       1.715     $       1.655

Assets                               $   8,220,728    $   8,364,862     $   8,227,150    $   8,211,163     $   8,194,018
------

Capitalization
--------------
  Common stock equity                $   2,818,807    $   2,690,454     $   2,574,743    $   2,586,179     $   2,632,116
  Preferred stock - redemption
     not required                           59,376          143,801           143,801          143,801           143,801
  Long-term debt, net                    2,415,656        2,525,607         2,610,343        2,530,773         2,584,903
                                        -----------      -----------      ------------      -----------      ------------
    Total capitalization             $   5,293,839    $   5,359,862     $   5,328,887    $   5,260,753     $   5,360,820
                                        ===========      ===========      ============      ===========      ============
</TABLE>

                                       36
<PAGE>

ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 
-------    RESULTS OF OPERATIONS
           ---------------------------------------------------------------
RESULTS OF OPERATIONS
---------------------

Operating Revenues
------------------

Operating  revenue  fluctuations  as  compared  to the prior year are due to the
following factors (in millions):
<TABLE>
<CAPTION>
                                                  1997             1996
                                                  ----             ----
<S>                                               <C>              <C>      
Customer growth/changes in usage patterns         $ 124         $  87
Sales to other utilities                             24            34
Weather                                             (55)            4
NCEMC load loss                                       -           (96)
Price                                               (39)          (36)
Sales to Power Agency                               (26)           (4)
                                                   -----          -----
                                                  $  28         $ (11)
                                                   =====          =====
</TABLE>

The  increase in the  customer  growth/changes  in usage  patterns  component of
revenue for both comparison  periods is primarily a result of continued economic
growth  within  the  Company's  service  territory.  Sales  to  other  utilities
increased in both comparison periods as a result of the Company's active pursuit
of opportunities in the wholesale power market. The 1997 decrease in the weather
component  of revenue is the result of milder  than normal  temperatures  in the
current period.  Both the customer  growth/changes in usage patterns and weather
components of revenue were affected by lost revenues  caused by Hurricanes  Fran
and Bertha in 1996. Beginning in January 1996, the Company lost 200 megawatts of
load from North Carolina Electric Membership Corporation (NCEMC), resulting in a
$96 million  decrease  in  revenues.  For 1997,  the  price-related  decrease is
primarily  attributable to a combination of decreases in the fuel cost component
of revenue and changes to the Power Coordination Agreement, which were effective
January 1, 1997, between the Company and NCEMC. The 1996 price-related  decrease
is primarily  attributable  to decreases in the fuel cost  component of revenue.
The 1997  decrease  in  revenue  related  to sales  to  North  Carolina  Eastern
Municipal  Power Agency (Power Agency) is primarily due to the impacts of milder
weather,  along  with  the  increased  availability  in the  current  period  of
generating units owned jointly by the Company and Power Agency.

Operating Expenses
------------------

Fuel expense  increased in 1997  primarily due to a 4.6% increase in generation.
Fuel expense decreased in 1996 due to renegotiated  coal contracts,  spot market
coal purchases at lower market prices and the refunding of  over-recovered  fuel
costs.  This decrease more than offset the increase in fuel expense related to a
3.9% increase in generation during 1996.

The decrease in purchased  power in 1997 is primarily a result of  amendments to
electric  purchase power  agreements  between the Company and Cogentrix of North
Carolina,  Inc.  and  Cogentrix  Eastern  Carolina  Corporation,   which  became
effective  in September  1996.  This  decrease is partially  offset by increased
purchases from other utilities due to the Company's more active participation in
wholesale power marketing.

Other operation and maintenance  expense  decreased for both comparison  periods
reflecting the Company's continued cost reduction efforts.  Also contributing to
the  decrease  in 1997  were  lower  expenses  resulting  from one less  nuclear
refueling  outage and fewer fossil  outages.  Other  operation  and  maintenance
expense in 1996  includes  storm-related  expenses of  approximately  $6 million
incurred  as a result of severe  ice  storms  experienced  in early 1996 and the
impact of Hurricane Bertha, which struck the Company's service territory in July
1996.  Hurricane 

                                       37
<PAGE>

Fran struck significant portions of the Company's service territory in September
1996.  In  December  1996,  the  North  Carolina  Utilities   Commission  (NCUC)
authorized the Company to defer  operation and maintenance  expenses  associated
with Hurricane Fran. See further discussion of Hurricane Fran below. In December
1996,  the NCUC  authorized  the Company to accelerate  amortization  of certain
regulatory  assets over a three-year  period beginning January 1, 1997. In March
1997, the South Carolina Public Service  Commission  (SCPSC)  approved a similar
plan for the  Company to  accelerate  the  amortization  of  certain  regulatory
assets,  including plant  abandonment  costs related to the Harris Plant, over a
three-year  period  beginning  January 1, 1997.  Depreciation  and  amortization
increased  approximately  $68  million  in 1997 as a result  of the  accelerated
amortization of these regulatory assets.  Depreciation and amortization  expense
also  includes  amortization  of deferred  operation  and  maintenance  expenses
associated  with Hurricane Fran of  approximately  $12 million and $4 million in
1997 and 1996, respectively.

Income tax expense  decreased in 1997 primarily due to the impact of current and
prior period tax provision  adjustments  recorded for potential  audit issues in
open tax years.

Other Income
------------

Interest  income  increased in 1997 primarily as a result of interest  income of
$11 million related to an income tax refund.

Other income, net, decreased in 1997 primarily due to losses incurred on certain
diversified  investments  which are in start-up  phases.  In 1996, other income,
net,  increased  primarily  due  to  an  adjustment  of  $22.9  million  to  the
unamortized  balance  of  abandonment  costs  related to the  Harris  Plant.  In
anticipation of approval by the SCPSC of the Company's December 1996 proposal to
accelerate amortization of certain regulatory assets, the unamortized balance of
plant  abandonment  costs  related to the Harris  Plant was  adjusted in 1996 to
reflect the present value impact of the shorter recovery period.  In March 1997,
the SCPSC approved the Company's accelerated amortization proposal.

Interest Charges
----------------

Interest  charges on long-term debt have  decreased  since 1995 primarily due to
reductions of long-term debt balances. Also contributing to the decrease in 1996
were  refinancings  of  long-term  debt  with  lower-interest  commercial  paper
borrowings  which  are  backed  by  the  Company's  long-term  revolving  credit
facilities.  See discussion of credit  facilities in PART II, ITEM 7, "LIQUIDITY
AND CAPITAL RESOURCES".

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 diversified investments.

The Company has on file with the  Securities  and  Exchange  Commission  (SEC) a
shelf registration  statement under which $250 million principal amount of first
mortgage bonds and $125 million  principal amount of first mortgage bonds and/or
unsecured  debt  securities of the Company  remain  available for issuance.  The
Company can also issue up to $180 million of additional  preferred stock under a
shelf registration statement on file with the SEC.

                                       38
<PAGE>


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  $4.3 billion in first  mortgage  bonds and an  additional 32 million
shares  of  preferred  stock at an  assumed  price of $100 per share and a $6.05
annual  dividend  rate.  The Company also has 10 million  authorized  preference
stock shares available for issuance that are not subject to an earnings test.

In July 1997, the Company  redeemed all 500,000 shares of $7.72 Serial Preferred
Stock and all 350,000 shares of $7.95 Serial  Preferred  Stock,  at a redemption
price of $101 per share. The redemptions were funded with additional  commercial
paper borrowings and/or internally generated funds.

In August 1997, the Company issued $200 million of first mortgage bonds. The net
proceeds  from this  issuance  were used to reduce  the  outstanding  balance of
commercial  paper and other  short-term  debt and for  other  general  corporate
purposes.

As of December 31, 1997, the Company's  revolving credit facilities totaled $515
million,  substantially  all of which are long-term  agreements  supporting  its
commercial  paper  borrowings.  The Company is  required  to pay minimal  annual
commitment fees to maintain its credit facilities.  Consistent with management's
intent to maintain a portion of its commercial  paper on a long-term  basis, and
as supported by its long-term revolving credit facilities,  the Company included
in  long-term  debt  $245.9  million  and  $350  million  of  commercial   paper
outstanding as of December 31, 1997 and 1996, respectively.

The  proceeds  from the  issuance  of  commercial  paper  related  to the credit
facilities  mentioned  above,  net  cash  inflow  from  the  company-owned  life
insurance program, and/or internally generated funds, financed the retirement of
long-term  debt totaling $103 million in 1997.  External  funding  requirements,
which do not include  early  redemptions  of long-term  debt or  redemptions  of
preferred stock, are expected to approximate $220 million, $100 million and $200
million in 1998, 1999 and 2000,  respectively.  These funds will be required for
construction,  mandatory  retirements  of long-term  debt and general  corporate
purposes, including the repayment of short-term debt.

The Company's  access to outside  capital depends on its ability to maintain its
credit  ratings.  The Company's  first mortgage bonds are currently  rated A2 by
Moody's Investors  Service,  A by Standard & Poor's and A+ by Duff & Phelps. The
Company's  commercial  paper is  currently  rated  P-1,  A-1 and D-1 by  Moody's
Investors Service, Standard & Poor's and Duff & Phelps, respectively.

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.

In 1994,  the Board of Directors of the Company  authorized the repurchase of up
to 10 million  shares of the  Company's  common stock on the open market.  Under
this stock repurchase program,  the Company purchased  approximately 0.7 million
shares in both 1997 and 1996,  4.2 million shares in 1995 and 4.4 million shares
in 1994. The program was completed in 1997.

Capital Requirements
--------------------

Estimated   capital   requirements  for  1998  through  2000  primarily  reflect
construction  expenditures  that will be made to meet customer  growth by adding
generating,  transmission  and  distribution  facilities,  as well as  upgrading
existing facilities. The Company's capital requirements,  excluding expenditures
of diversified businesses,  for those years are 

                                       39
<PAGE>

reflected in the following table (in millions).
<TABLE>
<CAPTION>
                                                   1998       1999      2000
                                                   ----       ----      ----
<S>                                              <C>        <C>       <C>   
 Construction expenditures                       $  398     $  494    $  526
 Nuclear fuel expenditures                           93         83        96
 AFUDC                                               (6)        (5)       (7)
 Mandatory retirements of long-term debt            208         53       197
                                                 ------     ------    ------
           Total                                 $  693     $  625    $  812
                                                 ======     ======    ======
</TABLE>

This table includes Clean Air Act expenditures of approximately  $32 million and
generating  facility addition  expenditures of approximately  $405 million.  The
generating  facility  addition  expenditures will primarily be used to construct
new combustion  turbine units, which are intended for use during periods of high
demand.  These units are  scheduled to be placed in service  during 1999 through
2002.

In addition, total projected cash requirements of diversified businesses for the
years 1998 through 2000 approximate  $362 million.  These  expenditures  include
affordable housing investments,  telecommunications  infrastructure development,
acquisitions  and  other  capital  requirements  of  the  Company's  diversified
businesses.   These  projections  are  periodically   reviewed  and  may  change
significantly.

The Company has 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 is with Duke
Energy  (Duke)  for the  purchase  of 400  megawatts  of firm  capacity  through
mid-1999.  The estimated minimum annual payments for power purchases under these
agreements are  approximately $31 million for Rockport and $48 million for Duke,
representing capital-related capacity costs. In 1997, total purchases (including
transmission  use charges)  under the Rockport and Duke  agreements  amounted to
$61.9 million and $69.5 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 Mayo and Harris  Plants.  For Mayo,  the buyback  period ended in 1997.  The
Harris Plant buyback period will continue  through 2007.  The estimated  minimum
annual  payments  for these  purchases,  representing  capital-related  capacity
costs, total approximately $26 million. Purchases under the agreement with Power
Agency totaled $36.2 million in 1997.

OTHER MATTERS
-------------

Retail Rate Matters
-------------------

A  petition  was filed in July 1996 by the  Carolina  Industrial  Group for Fair
Utility  Rates  (CIGFUR)  with the NCUC,  requesting  that the NCUC  conduct  an
investigation  of the Company's  base rates or treat its petition as a complaint
against the Company.  The petition  alleged that the Company's  return on equity
(which was authorized by the NCUC in the Company's last general rate  proceeding
in 1988) and earnings are too high. In December  1996,  the NCUC issued an order
denying  CIGFUR's  petition and stating that it tentatively  found no reasonable
grounds to proceed  with  CIGFUR's  petition as a  complaint.  In January  1997,
CIGFUR filed its Comments and Motion for  Reconsideration,  to which the Company
responded.  In February 1997, the NCUC issued an order denying  CIGFUR's  Motion
for Reconsideration.  CIGFUR filed a Notice of Appeal of the NCUC Order with the
North Carolina  Court of Appeals.  The Company filed its brief in this matter in
July 1997, and oral argument was held before the North Carolina Court of Appeals
in November 1997. The Company cannot predict the outcome of this matter.

                                       40
<PAGE>


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 various federal and state
laws. There are several  manufactured gas plant (MGP) sites to which the Company
and  certain  entities  that  were  later  merged  into  the  Company  had  some
connection.  In this regard, the Company, along with others, is participating in
a  cooperative  effort with the North  Carolina  Department of  Environment  and
Natural  Resources,  Division of Waste Management  (DWM), to establish a uniform
framework for addressing these MGP sites. The  investigation  and remediation of
specific  MGP sites will be  addressed  pursuant  to one or more  Administrative
Orders on  Consent  between  the DWM and the  potentially  responsible  party or
parties.  The  Company  continues  to  investigate  the  identities  of  parties
connected to individual MGP sites, the relative relationships of the Company and
other parties to those sites and the degree to which the Company will  undertake
efforts with others at individual sites.

The Company has been  notified by  regulators  of its  involvement  or potential
involvement  in  several  sites,  other than MGP sites,  that  require  remedial
action.  Although the Company cannot  predict the outcome of these  matters,  it
does not expect costs  associated with these sites to be material to the results
of operations of the Company.

The Company carries a liability for the estimated costs associated with remedial
activities,  except  for MGP  site  remediation  costs.  This  liability  is not
material to the  financial  position of the  Company.  The MGP site  remediation
costs are not currently determinable; however, the Company does not expect those
costs to be material to the financial position of the Company.

The 1990 amendments to the Clean Air Act (Act) require substantial reductions in
sulfur  dioxide  and  nitrogen  oxides  emissions  from  fossil-fueled  electric
generating  plants.  The Act will  require  the  Company to meet more  stringent
provisions  effective  January 1,  2000.  The  Company  plans to meet the sulfur
dioxide emissions  requirements by utilizing the most economical  combination of
fuel-switching   and  sulfur  dioxide  emission   allowances.   Installation  of
additional  equipment will be necessary to reduce nitrogen oxide emissions.  The
Company  estimates  that  future  capital  expenditures  necessary  to meet  the
nitrogen oxide emission  requirements  will  approximate $32 million.  Increased
operation and maintenance  costs,  including  emission  allowance  expense,  and
increased  fuel  costs  are  not  expected  to be  material  to the  results  of
operations of the Company.

In  addition,  there  are  emerging  regulatory  requirements  that may  require
utilities  to install  additional  controls  on  nitrogen  oxide  emissions  and
controls  on toxics and  particulate  matter.  The  Company  cannot  predict the
outcome of these matters.

With regard to revisions to existing air quality  standards,  the  Environmental
Protection  Agency  issued final  regulations  revising  the ozone  standard and
establishing a new fine-particulate standard in July 1997. These regulations may
require  the  installation  of  additional  control  equipment  at  some  of the
Company's  fossil-fueled  electric  generating plants. The Company is evaluating
the impact of the new  regulations on its facilities  and cannot  determine,  at
this time, the estimated  costs of additional  controls that may be required for
compliance  with the new  standards.  The Company  cannot predict the outcome of
this matter.

                                       41
<PAGE>

Nuclear
-------

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 upon in  applicable
rate agreements. Based on the site-specific estimates discussed below, and using
an assumed  after-tax  earnings rate of 8.5% 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  1993,   using  1993  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 1993
dollars,  are  $257.7  million  for  Robinson  Unit No. 2,  $235.4  million  for
Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 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  has  reached  several  tentative
conclusions with respect to its project regarding  accounting  practices related
to closure and removal of  long-lived  assets.  It is  uncertain  when the final
statement  will  be  issued  and  what  impacts  it may  ultimately  have on the
Company's  accounting for nuclear  decommissioning and other closure and removal
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 dispose of the  Company's  spent  nuclear  fuel.  In December  1996,  the DOE
notified  the Company and other  similarly  situated  utilities  that the agency
anticipated that it would be unable to begin acceptance of spent nuclear fuel by
January  31,  1998.  In  January  1997,  the  Company,  together  with 35  other
utilities,  filed a Joint  Petition  for Review with the United  States Court of
Appeals (the Court)  requesting  that the Court review the final decision of the
DOE and the DOE's failure to meet its unconditional obligation under the Nuclear
Waste Act. In November 1997,  the Court found that the DOE has an  unconditional
obligation  to begin  disposal of spent  nuclear fuel by January 31,  1998,  and
issued a writ of mandamus  precluding the DOE from advancing any construction of
the contract that would excuse the DOE's  delinquency on the grounds that it has
not yet established a permanent  repository or an interim storage  program.  The
DOE  defaulted on its  obligation  to begin taking spent nuclear fuel by January
31,  1998,  and a group of  utilities,  including  the Company,  is  considering
additional  measures  to  force  the DOE to take  spent  nuclear  fuel or to pay
damages  from monies  other than the  Nuclear  Waste  Fund.  The Company  cannot
predict the outcome of this matter.

With certain modifications,  the Company's spent nuclear fuel storage facilities
will be sufficient to provide  storage space for spent nuclear 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.

                                       42
<PAGE>

Other Business
--------------

In 1997,  CaroCapital,  Inc.  (CaroCapital),  a wholly owned  subsidiary  of the
Company,  acquired the remaining interest in Knowledge Builders,  Inc. (KBI) and
entered into a merger agreement under which KBI was merged into CaroCapital. KBI
was  an  energy-management   software  and  control  systems  company  in  which
CaroCapital  purchased a 40% interest in 1996.  Following the  completion of the
merger,  CaroCapital's  name was changed to Strategic  Resource  Solutions Corp.
(SRS).   SRS  is  a   technology-based   energy  services   company   delivering
facility-management   and   energy-management   products  and  services  to  the
educational,  commercial, industrial and governmental markets nationwide. During
the year,  SRS purchased  Diversified  Control  Systems,  a building  automation
systems  company,  and made a  minority  investment  in Remote  Source  Lighting
International,  Inc., a fiber optic lighting company. Also, in January 1998, SRS
purchased Parke  Industries,  Inc., the fourth largest  lighting  company in the
United   States.   These   investments   enhance   SRS's   ability   to  deliver
energy-management solutions and value-added products to the marketplace.

In 1997, the Company created a new subsidiary,  Interpath  Communications,  Inc.
(Interpath).   All  of  CaroNet,   LLC's  assets,   liabilities   and  operating
certificates  are  being  transferred  to this  new  subsidiary.  Interpath  has
acquired  Capitol  Information  Services,  Inc.,  a  regional  Internet  service
provider  based in Raleigh,  North  Carolina.  Interpath  will provide  Internet
retail  telecommunications  solutions  and will expand  services to include more
telecommunications business solutions, including voice and data applications for
small and medium-sized businesses.

Interpath also owns a 10% limited  partnership  interest in BellSouth  Carolinas
PCS, L.P. BellSouth Personal Communications, Inc. manages the partnership as the
general  partner.  PCS is a wireless  communications  technology  that  provides
high-quality  mobile  communications.  The partnership serves PCS subscribers in
North and South Carolina, and a small portion of Georgia,  pursuant to a license
issued by the Federal Communications Commission.

In 1995, the Company established CaroHome,  LLC, a limited liability company, to
further the Company's  investments in affordable housing.  These investments are
designed  to earn tax credits  while  helping  communities  meet their needs for
affordable housing. The Company, principally through CaroHome, LLC, has invested
or  committed  to  invest a total  of $58  million  in  affordable  housing  and
anticipates investing up to a total of $125 million in affordable housing by the
year 2000.

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 deregulate aspects of
retail electric  service.  The issue of retail  deregulation  and competition is
being reviewed by a number of states and bills have been  introduced in Congress
that seek to introduce retail deregulation 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 (those costs and investments made by
utilities  in order to meet  their  statutory  obligation  to  provide  electric
service) if the market price of electricity following industry  restructuring is
not  sufficient  to cover those  costs.  The amount of such  stranded  costs 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 results of  operations  and
financial

                                       43
<PAGE>

position of the Company would 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
greater  participation  by traditional  electricity  suppliers,  wholesale power
marketers  and brokers,  and due to the trading of energy  futures  contracts on
various  commodities  exchanges.  This  increased  competition  could affect the
Company's load forecasts,  plans for power supply and wholesale energy sales and
related  revenues.  The  impact  could  vary  depending  on the  extent to which
additional  generation  is  built  to  compete  in  the  wholesale  market,  new
opportunities  are  created  for the Company to expand its  wholesale  load,  or
current  wholesale  customers  elect to  purchase  from  other  suppliers  after
existing contracts expire.

To assist in the  development  of  wholesale  competition,  the  Federal  Energy
Regulatory  Commission  (FERC), in 1996, issued standards for wholesale wheeling
of electric  power  through its rules on open access  transmission  and stranded
costs and on information  systems and standards of conduct (Orders 888 and 889).
The rules  require  all  transmitting  utilities  to have on file an open access
transmission  tariff,  which  contains  provisions  for the recovery of stranded
costs and  numerous  other  provisions  that could  affect the sale of  electric
energy at the wholesale  level.  The Company filed its open access  transmission
tariff with the FERC in  mid-1996.  Shortly  thereafter,  Power Agency and other
entities filed protests challenging numerous aspects of the Company's tariff and
requesting  that an evidentiary  proceeding be held. The FERC set the matter for
hearing and set a discovery and procedural  schedule.  In July 1997, the Company
filed an offer of  settlement  in this  matter.  The  administrative  law  judge
certified  the offer to the full FERC in  September  1997.  The offer is pending
before the FERC. The Company cannot predict the outcome of this matter.

In November 1997, the Company applied to the FERC for authority to sell power at
market-based  rates.  In January  1998,  the FERC issued an order  accepting the
Company's  application  and permitting the Company to sell power at market-based
rates.

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,  including  California  and  Pennsylvania,  have changed  their laws and
regulations to allow retail electric customers to buy power from suppliers other
than the local utility.  Other states are considering similar changes,  and some
have instituted  experimental programs to allow a limited number of customers to
select  electric  suppliers.  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.

North Carolina Activities
-------------------------

Since 1995, the NCUC has been considering the impact of increased competition in
the electric  industry.  In May 1996,  the NCUC issued an order stating that the
FERC  Orders  888 and 889 would  provide a new focus for NCUC  proceedings  with
respect to  competition  in the electric  industry.  As a result,  the NCUC held
Docket No.  E-100,  Sub 77,  which  concerned  retail  competition,  in abeyance
pending further order and established a new docket (Docket No. E-100, Sub 78) to
address the FERC Orders 888 and 889.  The NCUC has  received  several  rounds of
comments in this docket;  the Company  filed its most recent  comments and reply
comments in November 1997 and December  1997,  respectively.  The Company cannot
predict the outcome of this matter.

                                       44
<PAGE>

In April 1997, the North Carolina General Assembly (General  Assembly)  approved
legislation  establishing a 23-member study commission to evaluate the future of
electric  service  in  the  state.  The  commission  is  comprised  of 12  state
legislators,  two residential customers,  two industrial customers, a commercial
customer, a power marketer, an environmentalist and representatives from each of
the four major power suppliers in the state.  The commission is examining a wide
range of issues  related  to the cost and  delivery  of  electric  service.  The
commission will make an interim report to the 1998 General  Assembly and a final
report in 1999. The Company cannot predict the outcome of this matter.

South Carolina Activities
-------------------------

In  February  1997,  representatives  in the  South  Carolina  General  Assembly
introduced a bill calling for a transition to full  competition  in the electric
utility  industry  beginning  in 1998.  No  action  was taken on this  bill.  In
addition,  by letter dated May 6, 1997,  the Speaker of the South Carolina House
of  Representatives  requested  that  the  SCPSC  prepare  a  proposal  for  the
deregulation and restructuring of electricity in South Carolina.  On February 3,
1998,  the  SCPSC  issued  a  report  to the  South  Carolina  General  Assembly
recommending  caution  and more study on the issue of  deregulation.  The report
outlines a five-year transition plan that it recommends be followed if the South
Carolina legislators decide to go forward with deregulation.  The South Carolina
General  Assembly's  Utility  Subcommittee has completed six hearings around the
state  in  order  to  receive  citizen  input  on the  deregulation  issue.  The
subcommittee  will continue to meet.  The Company  cannot predict the outcome of
this matter.

Federal Activities
------------------

Numerous   bills  were   introduced  in  the  105th   Congress   concerning  the
restructuring of the electric utility industry. Key provisions of the bills vary
widely.  Committee  Chairs have held  workshops and hearings to discuss  various
aspects of  restructuring.  No legislation was passed during the 1997 session of
Congress, and more restructuring-related  bills are expected to be introduced in
Congress during 1998. The Company cannot predict the outcome of this matter.

Company Activities
------------------

The developments  described above have created greater planning  uncertainty and
risks for the Company.  The Company has been addressing  these risks by securing
long-term  contracts  with its wholesale  customers and by continuing to work to
meet the energy needs of its industrial customers.  To position itself to better
address these risks,  the Company  internally  organized into separate  business
units in early 1998. The business units include Energy Supply,  Energy  Delivery
and Retail  Sales and  Services.  The focus of these  business  units will be to
further the development of a corporate culture that is necessary to compete in a
deregulated environment.  Other elements of the Company's strategy to respond to
the changing  market for electricity  include  promoting  economic  development,
implementing new marketing  strategies,  improving  customer  satisfaction,  and
increasing the focus on managing and reducing costs (and, consequently, avoiding
future rate increases).

In late 1996,  the Company and NCEMC entered into a revised  Power  Coordination
Agreement (PCA) under which NCEMC will receive  discounted  capacity in exchange
for long-term commitments to the Company for its supplemental power. As a result
of this revised  agreement,  the Company  provided  100 MW of baseload  power to
NCEMC  in 1997,  and  will  provide  a block  of 225 MW from  1998 to  2010,  an
additional  block of 225 MW from  2000 to 2004 and a third  block of 225 MW from
2001 to 2008. The remainder of the NCEMC capacity  provided by the Company,  not
separately  contracted  for in the  revised  agreement,  will be billed at fixed
rates through the year 2003, rather than at the formula rates established in the
original  PCA. The FERC has  accepted  the revised PCA.  When NCEMC seeks future
supplies,  the Company  will  respond and expects to remain  competitive  in the
pursuit and retention of wholesale load.

                                       45
<PAGE>

In  August  1996,  Power  Agency  notified  the  Company  of  its  intention  to
discontinue  certain  contractual  purchases of power from the Company effective
September 1, 2001.  Power Agency's  notice  indicated that it intends to replace
these  contractual  obligations  through  purchases  of capacity  and energy and
related services in the open market,  and that the Company will be considered as
a potential  supplier  for those  purchases.  Under the 1981 Power  Coordination
Agreement,  as amended,  between the Company and Power Agency,  Power Agency can
reduce its purchases from the Company with an appropriate  five-year notice. The
Company  and  Power  Agency  have  agreed  on  a  process  for  determining  the
sufficiency of the August 1996 notice. The Company cannot predict the outcome of
this matter.

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
regulatory  assets and liabilities  resulting from the effects of the ratemaking
process.  These assets and  liabilities  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, deregulation 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."


Year 2000 Computer Issues
-------------------------

The Company initiated steps in 1994 to bring its computer systems into Year 2000
compliance.  Only a few of the Company's core business applications remain to be
brought into compliance. All remaining computer systems, including equipment and
devices containing microprocessors, are being evaluated and will be brought into
compliance  or replaced if  necessary.  Estimated  costs to be incurred  will be
determined as this evaluation is finalized.

The Year 2000 issue may affect other  entities with which the Company  transacts
business.   The  Company  cannot  estimate  or  predict  the  potential  adverse
consequences,  if any, that could result from such entities'  failure to address
this issue.

                                       46
<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 to earnings,
cash flow and fair value risks due to changes in interest  rates with respect to
its long-term debt. 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.  For the  Company's  long-term
debt obligations at December 31, 1997,  including  current  portions,  the table
below presents principal cash flows and related weighted-average interest rates,
by expected maturity date.
<TABLE>
<CAPTION>
                               1998    1999     2000     2001     2002     Thereafter  Total    Fair Value
(Dollars in millions)         -------  -------  -------  -------  -------  ---------   -------  -------
<S>                           <C>      <C>      <C>      <C>      <C>      <C>         <C>      <C>
Fixed rate long-term debt     $  208   $   53   $  197     -      $  100   $1,219      $1,777   $1,846
Average interest rate           5.57%    7.11%    5.92%    -        6.75%    7.41%       6.98% 
Variable rate long-term debt      -        -       -       -          -    $  620      $  620   $  622
Average interest rate             -        -       -       -          -      3.75%       3.75% 

</TABLE>


The  table  above  excludes  commercial  paper  classified  as  long-term  debt.
Commercial paper does not have associated  significant interest rate risk due to
the short maturity of that instrument.


                                       47
<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                                                                           49

Consolidated Financial Statements:

     Consolidated Statements of Income for the Years Ended December 31, 1997, 1996 and 1995            50
     Consolidated Balance Sheets as of December 31, 1997 and 1996                                      51
     Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996
           and 1995                                                                                    52
     Consolidated Schedules of Capitalization as of December 31, 1997 and 1996                         53
     Consolidated Statements of Retained Earnings for the Years Ended December 31, 1997, 1996
            and 1995                                                                                   54
     Consolidated Quarterly Financial Data (Unaudited)                                                 54
     Notes to Consolidated Financial Statements                                                        55



Consolidated  Financial  Statement  Schedules  for the Years Ended  December 31,
    1997, 1996 and 1995:

     II- Valuation and Qualifying Accounts                                                             67




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  Consolidated  Financial
Statements.

</TABLE>

                                       48
<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, 1997 and 1996, and the related consolidated  statements of income,  retained
earnings,  and cash  flows  for each of the  three  years  in the  period  ended
December 31, 1997.  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  Carolina  Power &  Light  and
subsidiaries at December 31, 1997 and 1996, and the results of their  operations
and their cash flows for each of the three  years in the period  ended  December
31, 1997, 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.

We have also previously  audited, in accordance with generally accepted auditing
standards, the consolidated balance sheets and schedules of capitalization as of
December 31, 1995,  1994, and 1993, and the related  consolidated  statements of
income,  retained earnings, and cash flows for the years ended December 31, 1994
and 1993 (none of which are  presented  herein);  and we  expressed  unqualified
opinions on those financial statements.

In our opinion,  the  information  set forth in the selected  financial data for
each of the five years in the period ended  December 31, 1997,  and appearing at
Item  6, is  fairly  presented  in all  material  respects  in  relation  to the
consolidated financial statements from which it has been derived.


/s/ DELOITTE & TOUCHE LLP
---------------------------
Raleigh, North Carolina
February 9, 1998


                                       49
<PAGE>



<TABLE>
                                    CONSOLIDATED STATEMENTS OF INCOME
<CAPTION>


                                                                         Years ended December 31
(In thousands except per share data)                                1997          1996          1995
--------------------------------------------------------------- ------------  ------------  -----------
<S>                                                             <C>           <C>           <C>        
Operating revenues                                              $  3,024,089  $  2,995,715  $ 3,006,553
--------------------------------------------------------------- ------------  ------------  -----------
Operating expenses
--------------------------------------------------------------- ------------  ------------  -----------
Fuel                                                                 534,268       515,050      529,812
Purchased power                                                      387,296       412,554      409,940
Other operation and maintenance                                      661,466       730,140      738,031
Depreciation and amortization                                        481,650       386,927      364,527
Taxes other than on income                                           139,478       140,479      144,043
Income tax expense                                                   253,048       269,763      259,224
Harris Plant deferred costs, net                                      24,296        26,715       28,128
--------------------------------------------------------------- ------------  ------------  -----------
        Total operating expenses                                   2,481,502     2,481,628    2,473,705
--------------------------------------------------------------- ------------  ------------  -----------
Operating income                                                     542,587       514,087      532,848
--------------------------------------------------------------- ------------  ------------  -----------
Other income
--------------------------------------------------------------- ------------  ------------  -----------
Allowance for equity funds used during construction                        -            11        3,350
Income tax credit                                                     19,332        13,847       18,541
Harris Plant carrying costs                                            4,626         7,299        8,297
Interest income                                                       18,335         4,063        8,680
Other income, net                                                    (19,275)       37,340        9,063
--------------------------------------------------------------- ------------  ------------  -----------
        Total other income                                            23,018        62,560       47,931
--------------------------------------------------------------- ------------  ------------  -----------
Income before interest charges                                       565,605       576,647      580,779
--------------------------------------------------------------- ------------  ------------  -----------
Interest charges
--------------------------------------------------------------- ------------  ------------  -----------
Long-term debt                                                       163,468       172,622      187,397
Other interest charges                                                18,743        19,155       25,896
Allowance for borrowed funds used during construction                 (4,923)       (6,407)      (5,118)
--------------------------------------------------------------- ------------  ------------  -----------
        Total interest charges, net                                  177,288       185,370      208,175
--------------------------------------------------------------- ------------  ------------  -----------
Net income                                                      $    388,317  $    391,277  $   372,604
--------------------------------------------------------------- ------------  ------------  -----------
Preferred stock dividend requirements                                 (6,052)       (9,609)      (9,609)
--------------------------------------------------------------- ------------  ------------  -----------
Earnings for common stock                                       $    382,265  $    381,668  $   362,995
--------------------------------------------------------------- ------------  ------------  -----------
Average common shares outstanding                                    143,645       143,621      146,232
--------------------------------------------------------------- ------------  ------------  -----------
Basic and diluted earnings per common share                     $       2.66  $       2.66  $      2.48
--------------------------------------------------------------- ------------  ------------  -----------
Dividends declared per common share                             $      1.895  $      1.835  $     1.775
--------------------------------------------------------------- ------------  ------------  -----------
See notes to consolidated financial statements.
</TABLE>

                                       50
<PAGE>
<TABLE>

                                    CONSOLIDATED BALANCE SHEETS
<CAPTION>

(In thousands)                                                                      December 31
ASSETS                                                                  1997                     1996
-------------------------------------------------------------------------------------------------------
<S>                                                         <C>                     <C> 

Electric utility plant
-------------------------------------------------------------------------------------------------------
Electric utility plant in service                           $      10,113,334       $        9,783,442
Accumulated depreciation                                           (4,181,417)              (3,796,645)
-------------------------------------------------------------------------------------------------------
        Electric utility plant in service, net                      5,931,917                5,986,797
Held for future use                                                    12,255                   12,127
Construction work in progress                                         158,347                  196,623
Nuclear fuel, net of amortization                                     190,991                  204,372
-------------------------------------------------------------------------------------------------------
        Total electric utility plant, net                           6,293,510                6,399,919
-------------------------------------------------------------------------------------------------------
Current assets
-------------------------------------------------------------------------------------------------------
Cash and cash equivalents                                              14,426                   10,941
Accounts receivable                                                   406,872                  384,318
Fuel                                                                   47,551                   60,369
Materials and supplies                                                136,253                  122,809
Deferred fuel cost (credit)                                            20,630                   (4,339)
Prepayments                                                            62,040                   65,794
Other current assets                                                   47,034                   27,808
-------------------------------------------------------------------------------------------------------
        Total current assets                                          734,806                  667,700
-------------------------------------------------------------------------------------------------------
Deferred debits and other assets (Note 6)
-------------------------------------------------------------------------------------------------------
Income taxes recoverable through future rates                         328,818                  384,336
Abandonment costs                                                      38,557                   65,863
Harris Plant deferred costs                                            63,727                   83,397
Unamortized debt expense                                               48,407                   69,956
Nuclear decommissioning trust funds                                   245,523                  145,316
Miscellaneous other property and investments                          256,291                  344,018
Other assets and deferred debits                                      211,089                  204,357
-------------------------------------------------------------------------------------------------------
        Total deferred debits and other assets                      1,192,412                1,297,243
-------------------------------------------------------------------------------------------------------
         Total assets                                       $       8,220,728       $        8,364,862
-------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
-------------------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of
capitalization)
-------------------------------------------------------------------------------------------------------
Common stock equity                                         $       2,818,807       $        2,690,454
Preferred stock - redemption not required                              59,376                  143,801
Long-term debt, net                                                 2,415,656                2,525,607
-------------------------------------------------------------------------------------------------------
        Total capitalization                                        5,293,839                5,359,862
-------------------------------------------------------------------------------------------------------
Current liabilities
-------------------------------------------------------------------------------------------------------
Current portion of long-term debt                                     207,979                  103,345
Short-term debt                                                             -                   64,885
Accounts payable                                                      290,352                  375,216
Interest accrued                                                       43,620                   39,436
Dividends declared                                                     72,266                   73,469
Other current liabilities                                             116,609                   74,668
-------------------------------------------------------------------------------------------------------
        Total current liabilities                                     730,826                  731,019
-------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities
-------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes                                   1,722,908                1,827,693
Accumulated deferred investment tax credits                           222,028                  232,262
Other liabilities and deferred credits                                251,127                  214,026
-------------------------------------------------------------------------------------------------------
        Total deferred credits and other liabilities                2,196,063                2,273,981
-------------------------------------------------------------------------------------------------------
Commitments and contingencies (Note 11)
-------------------------------------------------------------------------------------------------------
         Total capitalization and liabilities               $       8,220,728       $        8,364,862
-------------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
</TABLE>

                                       51
<PAGE>
<TABLE>
                                    CONSOLIDATED STATEMENTS OF CASH FLOWS
<CAPTION>
                                                                                          Years ended December 31
(In thousands)                                                                     1997             1996            1995
-------------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>             <C>              <C>           
Operating activities
-------------------------------------------------------------------------------------------------------------------------
Net income                                                              $       388,317 $        391,277 $       372,604
Adjustments to reconcile net income to net cash provided by operating
activities:
      Depreciation and amortization                                             565,212          446,508         446,662
      Harris Plant deferred costs                                                19,670           19,416          19,831
      Deferred income taxes                                                     (66,546)         130,818          89,681
      Investment tax credit                                                     (10,232)         (10,445)         (9,344)
      Allowance for equity funds used during construction                             -              (11)         (3,350)
      Deferred fuel credit                                                      (24,969)         (23,156)           (849)
      Net increase in receivables, inventories and prepaid expenses            (111,216)         (64,793)        (77,849)
      Net increase (decrease) in payables and accrued expenses                   (6,414)           4,671         (39,592)
      Miscellaneous                                                              64,223           17,922          75,308
-------------------------------------------------------------------------------------------------------------------------
           Net cash provided by operating activities                            818,045          912,207         873,102
-------------------------------------------------------------------------------------------------------------------------
Investing activities
-------------------------------------------------------------------------------------------------------------------------
Gross property additions                                                       (388,676)        (369,308)       (266,400)
Nuclear fuel additions                                                          (61,509)         (87,265)        (77,346)
Contributions to nuclear decommissioning trust                                  (30,726)         (30,683)        (38,075)
Contributions to retiree benefit trusts                                         (21,096)         (24,700)         (2,400)
Net cash flow of company-owned life insurance program                           138,508           46,930         (39,679)
Allowance for equity funds used during construction                                   -               11           3,350
Miscellaneous                                                                     6,706          (28,046)        (28,515)
-------------------------------------------------------------------------------------------------------------------------
          Net cash used in investing activities                                (356,793)        (493,061)       (449,065)
-------------------------------------------------------------------------------------------------------------------------
Financing activities
-------------------------------------------------------------------------------------------------------------------------
Proceeds from issuance of long-term debt                                        199,075                -         180,713
Net increase (decrease) in short-term debt (maturity less than 90               (62,224)          (8,858)          5,643
days)
Net increase (decrease) in commercial paper classified as long-term            (104,100)         350,000               -
debt (Note 3)
Retirement of long-term debt                                                   (103,410)        (467,810)       (276,144)
Redemption of preferred stock                                                   (85,850)               -               -
Purchase of Company common stock                                                (23,418)         (25,208)       (132,439)
Dividends paid on common and preferred stock                                   (277,840)        (270,818)       (267,560)
-------------------------------------------------------------------------------------------------------------------------
           Net cash used in financing activities                               (457,767)        (422,694)       (489,787)
-------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents                              3,485           (3,548)        (65,750)
Cash and cash equivalents at beginning of year                                   10,941           14,489          80,239
-------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents at end of year                                $        14,426 $         10,941 $        14,489
-------------------------------------------------------------------------------------------------------------------------
Supplemental disclosures of cash flow information
Cash paid during the year - interest                                    $       171,511 $        194,391 $       203,296
                            income taxes                                $       289,693 $        141,350 $       177,163

Noncash Activities In June 1997,  Strategic  Resource Solutions Corp.  (formerly
CaroCapital, Inc.), a wholly-owned subsidiary, purchased all remaining shares of
Knowledge  Builders,  Inc.  (KBI).  In connection  with the purchase of KBI, the
Company issued $20.5 million in common stock and paid $1.9 million in cash.

See notes to consolidated financial statements.
</TABLE>
                                       52
<PAGE>

<TABLE>
                                       CONSOLIDATED SCHEDULES OF CAPITALIZATION
<CAPTION>

                                                                                                             December, 31
(Dollars in thousands except per share data)                                                             1997              1996
------------------------------------------------------------------------------------------- --- -------------- --- -------------
<S>                                                                                         <C>                <C>               
Common stock equity
------------------------------------------------------------------------------------------- --- -------------- --- -------------
Common stock without par value, authorized 200,000,000 shares, issued and
   outstanding 151,340,394 and 151,415,722 shares, respectively (Note 7)                    $       1,371,520  $      1,366,100
Unearned ESOP common stock                                                                           (165,804)         (178,514)
Capital stock issuance expense                                                                           (790)             (790)
Retained earnings (Note 5)                                                                          1,613,881         1,503,658
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total common stock equity                                                           $       2,818,807  $      2,690,454
------------------------------------------------------------------------------------------- --- -------------- --- -------------
Cumulative preferred stock, without par value (entitled to $100 a share plus accumulated
dividends in the event of liquidation; outstanding shares are as of December 31, 1997)
------------------------------------------------------------------------------------------- --- -------------- --- -------------
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
     7.95 Serial Preferred                                                                                  -            35,000
     7.72 Serial Preferred                                                                                  -            49,425
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total preferred stock - redemption not required                                     $          59,376  $        143,801
------------------------------------------------------------------------------------------- --- -------------- --- -------------
Long-term debt (interest rates are as of December 31, 1997)
------------------------------------------------------------------------------------------- --- -------------- --- -------------
First mortgage bonds:
6.375% due 1997                                                                             $               -  $         40,000
5.375% and 6.875% due 1998                                                                            140,000           140,000
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                 -
6.875% to 8.625% due 2021-2023                                                                        500,000           500,000
First mortgage bonds - secured medium-term notes:
7.75% due 1997                                                                                              -            60,000
5.00% to 5.06% due 1998                                                                                65,000            65,000
7.15% due 1999                                                                                         50,000            50,000
First mortgage bonds - pollution control series:
6.30% to 6.90% due 2009-2014                                                                           93,530            93,530
3.80% and 4.00% due 2024                                                                              122,600           122,600
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total first mortgage bonds                                                                  1,721,130         1,621,130
------------------------------------------------------------------------------------------- --- -------------- --- -------------
Other long-term debt:
Pollution control obligations backed by letter of credit, 3.70% to 5.40% due 2014-2017                442,000           442,000
Other pollution control obligations, 3.90% 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 3)                                              245,900           350,000
Miscellaneous notes                                                                                    53,486            56,858
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total other long-term debt                                                                    922,026         1,029,498
------------------------------------------------------------------------------------------- --- -------------- --- -------------
Unamortized premium and discount, net                                                                 (19,521)          (21,676)
Current portion of long-term debt                                                                    (207,979)         (103,345)
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total long-term debt, net                                                           $       2,415,656  $      2,525,607
------------------------------------------------------------------------------------------- --- -------------- --- -------------
        Total capitalization                                                                $       5,293,839  $     5,359,862
------------------------------------------------------------------------------------------- --- -------------- --- -------------
See notes to consolidated financial statements.
</TABLE>

                                       53
<PAGE>

<TABLE>

                      CONSOLIDATED STATEMENTS OF RETAINED EARNINGS

<CAPTION>

                                                                                Years ended December 31
(In thousands except per share data)                                1997                 1996                1995
--------------------------------------------------------- ---- --------------- ---- --------------- ---- --------------
<S>                                                         <C>                  <C>                  <C>          
Retained earnings at beginning of year                      $       1,503,658    $       1,385,378    $      1,280,960
--------------------------------------------------------- ---- --------------- ---- --------------- ---- --------------
Net income                                                            388,317              391,277             372,604
Preferred stock dividends at stated rates                              (4,627)              (9,609)             (9,609)
Common stock dividends at annual per share rate of
   $1.895, $1.835 and $1.775, respectively                           (272,011)            (263,388)           (258,577)
Other adjustments                                                      (1,456)                   -                   -
--------------------------------------------------------- ---- --------------- ---- --------------- ---- --------------
Retained earnings at end of year                            $       1,613,881    $       1,503,658    $      1,385,378
--------------------------------------------------------- ---- --------------- ---- --------------- ---- --------------

</TABLE>
<TABLE>
                    CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
<CAPTION>
                                                         First           Second         Third          Fourth
     (In thousands except per share data)                Quarter         Quarter        Quarter        Quarter
     ------------------------------------------------------------------------------------------------------------
     Year ended December 31, 1997
     ------------------------------------------------------------------------------------------------------------
     <S>                                              <C>            <C>             <C>            <C> 
     Operating revenues                               $    716,084   $     666,023   $    906,841   $    735,141
     Operating income                                      122,762          86,988        211,281        121,556
     Net income                                             82,262          54,289        167,829         83,937
     Common stock data:
     Basic and diluted earnings per common share               .56             .37           1.15            .58
     Dividend paid per common share                           .470            .470           .470           .470
     Price per share - high                                37  7/8          36 1/4         36 5/8        42  1/2
                       low                                 36  1/8          33             33 3/4        34 5/16       
                                                                      
     ------------------------------------------------------------------------------------------------------------
     Year ended December 31, 1996
     ------------------------------------------------------------------------------------------------------------
     Operating revenues                              $     783,585  $      685,968  $     831,590  $     694,572
     Operating income                                      154,428          94,966        164,125        100,568
     Net income                                            118,346          62,656        129,159         81,116
     Common stock data:
     Basic and diluted earnings per common share               .81             .42            .88            .55
     Dividend paid per common share                           .455            .455           .455           .455
     Price per share - high                                38  3/8         38             38  1/4        37
                       low                                 34  1/2         34  7/8        34  1/8        34  1/4

         See notes to consolidated financial statements.

</TABLE>
                                       54
<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.  The Company has no other
material segments of business.

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 South  Carolina  Public Service  Commission  (SCPSC).
Certain amounts for 1996 and 1995 have been  reclassified to conform to the 1997
presentation,  with no effect on previously  reported net income or common stock
equity.

2.  Summary of Significant Accounting Policies

a.  Principles of Consolidation

The consolidated  financial statements include the activities of the Company and
majority-owned  subsidiaries.  These subsidiaries have invested in areas such as
communications  technology,  energy-management  services and affordable housing.
Significant intercompany balances and transactions have been eliminated.

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.  Electric Utility Plant

The  cost of  additions,  including  betterments  and  replacements  of units of
property,  is charged to  electric  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.
The  balances  of  electric  utility  plant in service at December 31 are listed
below (in millions).
<TABLE>
<CAPTION>
                                                   1997                1996
                                                -------             -------
<S>                                             <C>                 <C>    
Production plant                                $ 6,297             $ 6,161
Transmission plant                                  952                 940
Distribution plant                                2,327               2,179
General plant and other                             537                 503
                                                -------             -------
 Electric utility plant in service              $10,113             $ 9,783
                                                =======             =======
</TABLE>

                                       55
<PAGE>

As prescribed in regulatory  uniform  systems of accounts,  an allowance for the
cost of  borrowed  and  equity  funds  used to finance  electric  utility  plant
construction  (AFUDC) is charged  to the cost of plant.  Regulatory  authorities
consider  AFUDC an  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 was 5.6% in 1997, 5.8% in
1996 and 8.0% in 1995.

d.  Depreciation and Amortization

For financial reporting  purposes,  depreciation of electric 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 2e), as a
percent  of  average   depreciable   property  other  than  nuclear  fuel,  were
approximately  3.9% in 1997 and 1996  and  3.8% in  1995.  Depreciation  expense
totaled $382.1  million,  $363.2  million and $344.0  million in 1997,  1996 and
1995, 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
December  1996,  the  NCUC  authorized  the  Company  to  defer  these  expenses
(approximately $40 million) with amortization over a 40-month period.

In December 1996, the NCUC authorized the Company to accelerate  amortization of
certain regulatory assets over a three-year period beginning January 1, 1997. In
March 1997,  the SCPSC approved a similar plan for the Company to accelerate the
amortization of certain  regulatory  assets,  including plant  abandonment costs
related to the Harris Plant, over a three-year period beginning January 1, 1997.
The accelerated  amortization of these  regulatory  assets results in additional
depreciation and amortization expenses of approximately $68 million in each year
of the three-year  period.  Depreciation and amortization  expense also includes
amortization of plant abandonment costs (see Note 6c).

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.

e.  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 upon in  applicable
rate  agreements.   Decommissioning  cost  provisions,  which  are  included  in
depreciation and  amortization  expense,  were $33.2 million,  $33.1 million and
$31.2 million in 1997, 1996 and 1995, respectively.

Accumulated   decommissioning   costs,   which  are   included  in   accumulated
depreciation,  were  $428.7  million and $326  million at December  31, 1997 and
1996, respectively.  These costs include amounts retained internally and amounts
funded  in an  external  decommissioning  trust.  The  balance  of  the  nuclear
decommissioning trust was $245.5 million and $145.3 million at December 31, 1997
and  1996,  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.  Based  on the
site-specific estimates discussed below, and using an assumed after-tax earnings
rate of 8.5% 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.

                                       56
<PAGE>

The Company's most recent site-specific  estimates of decommissioning costs were
developed  in  1993,   using  1993  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 1993
dollars,  are  $257.7  million  for  Robinson  Unit No. 2,  $235.4  million  for
Brunswick Unit No. 1, $221.4 million for Brunswick Unit No. 2 and $284.3 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  has  reached  several  tentative
conclusions with respect to its project regarding  accounting  practices related
to closure and removal of  long-lived  assets.  It is  uncertain  when the final
statement  will  be  issued  and  what  impacts  it may  ultimately  have on the
Company's  accounting for nuclear  decommissioning and other closure and removal
costs.

f.  Other Policies

Customers' meters are read and bills are rendered on a cycle basis. Revenues are
accrued for services rendered but unbilled at the end of each accounting period.

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.

Other  property and  investments  are stated  principally  at cost.  The Company
maintains an allowance  for doubtful  accounts  receivable,  which  totaled $3.4
million and $3.7  million at  December  31,  1997 and 1996,  respectively.  Fuel
inventory  and  materials  and  supplies  inventory  are  carried on a first-in,
first-out or average cost basis. 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 December 31, 1996 balances are being amortized
on a  three-year  accelerated  basis (see Note 6a).  The Company  considers  all
highly liquid investments with original maturities of three months or less to be
cash equivalents.

3.  Short-Term Debt and Revolving Credit Facilities

As of December 31, 1997, the Company's  revolving credit facilities totaled $515
million,  substantially  all of which are long-term  agreements  supporting  its
commercial  paper  borrowings.  The Company is  required  to pay minimal  annual
commitment fees to maintain its credit facilities.  Consistent with management's
intent to maintain a portion of its commercial  paper on a long-term  basis, and
as supported by its long-term revolving credit facilities,  the Company included
in  long-term  debt  $245.9  million  and  $350  million  of  commercial   paper
outstanding  as of December 31, 1997 and 1996,  respectively.  Also, at December
31, 1996, the Company had other short-term debt which totaled $64.9 million. The
weighted-average  interest  rates of these  borrowings  were  5.85% and 5.41% at
December  31,  1997  and  1996,   respectively,   including   commercial   paper
reclassified as long-term debt.

4.  Fair Value of Financial Instruments

The  carrying   amounts  of  cash  and  cash  equivalents  and  short-term  debt
approximate  fair value due to the short  maturities of these  instruments.  The
carrying  amount of the  Company's  long-term  debt was $2.66  billion and $2.67
billion at December 31, 1997 and 1996, respectively. The estimated fair value of
this debt, as obtained 

                                       57
<PAGE>

from an  independent  pricing  service,  was $2.71  billion and $2.67 billion at
December 31, 1997 and 1996, respectively.  There are inherent limitations in any
estimation technique,  and these estimates are not necessarily indicative of the
amount the Company could realize in current transactions.

External  funds have been  established,  as required  by the Nuclear  Regulatory
Commission, as a mechanism to fund certain costs of nuclear decommissioning (see
Note 2e). These nuclear decommissioning trust funds are invested in U.S. stocks,
bonds and cash equivalents.  "Nuclear decommissioning trust funds" are presented
at amounts that approximate fair value.

5.  Capitalization

In 1994,  the Board of Directors of the Company  authorized the repurchase of up
to 10 million  shares of the  Company's  common stock on the open market.  Under
this stock repurchase program,  the Company purchased  approximately 0.7 million
shares in both 1997 and 1996,  4.2 million shares in 1995 and 4.4 million shares
in 1994. The program was completed in 1997.

As of December 31, 1997,  the Company had  20,163,180  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.

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, 1997, there were no significant  restrictions
on the use of retained earnings.

As of December 31, 1997,  long-term debt  maturities  for the years 1998,  1999,
2000 and 2002 are $208  million,  $53 million,  $197  million and $100  million,
respectively. There are no long-term debt maturities in 2001.

6.  Regulatory Matters

a.  Regulatory Assets

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).  See Note 11c for  additional  discussion  of
SFAS-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, 1997,
the balances of the Company's regulatory assets were as follows (in millions):


Income taxes recoverable through future rates*                     $ 329
Harris Plant deferred costs                                           64
Abandonment costs*                                                    38
Loss on reacquired debt (included in unamortized debt expense)*       42
Deferred fuel                                                         21
Items included in other assets and deferred debits:
      Deferred DOE enrichment facilities-related costs                49
      Deferred hurricane-related costs                                24
      Emission allowance carrying costs*                               8
                                                                   -----
          Total                                                    $ 575
                                                                   =====

* Beginning  in 1997,  all or certain  portions of these  regulatory  assets are
subject to accelerated amortization (see Note 2d).

                                       58
<PAGE>

b.  Retail Rate Matters

A  petition  was filed in July 1996 by the  Carolina  Industrial  Group for Fair
Utility  Rates  (CIGFUR)  with the NCUC,  requesting  that the NCUC  conduct  an
investigation  of the Company's  base rates or treat its petition as a complaint
against the Company.  The petition  alleged that the Company's  return on equity
(which was authorized by the NCUC in the Company's last general rate  proceeding
in 1988) and earnings are too high. In December  1996,  the NCUC issued an order
denying  CIGFUR's  petition and stating that it tentatively  found no reasonable
grounds to proceed  with  CIGFUR's  petition as a  complaint.  In January  1997,
CIGFUR filed its Comments and Motion for  Reconsideration,  to which the Company
responded.  In February 1997, the NCUC issued an order denying  CIGFUR's  Motion
for Reconsideration.  CIGFUR filed a Notice of Appeal of the NCUC Order with the
North Carolina  Court of Appeals.  The Company filed its brief in this matter in
July 1997, and oral argument was held before the North Carolina Court of Appeals
in November 1997. The Company cannot predict the outcome of this matter.

c.  Plant-related Deferred Costs

The Company  abandoned  efforts to complete  Mayo Unit No. 2 in March 1987.  The
NCUC and SCPSC each  allowed the  Company to recover  the cost of the  abandoned
unit over a ten-year period without a return on the unamortized  balance. 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 will be  completed in 1998 for the
North  Carolina  retail and  wholesale  jurisdictions  and in 1999 for the South
Carolina retail jurisdiction.

Amortization  of  plant  abandonment  costs  is  included  in  depreciation  and
amortization expense and totaled $30.8 million,  $17.6 million and $18.3 million
in  1997,  1996  and  1995,  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 $3.5 million,
$26.4  million and $4.3  million in 1997,  1996 and 1995,  respectively,  and is
reported in other  income,  net. The accretion for 1996 includes a $22.9 million
adjustment to the unamortized  balance of plant abandonment costs related to the
Harris Plant.  This  adjustment  was made to reflect the present value impact of
the shorter  recovery  period  resulting from  accelerated  amortization of this
asset (see Note 2d).

7.  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 participant  contributions,  Company matching
and incentive contributions and/or reinvested dividends.  Dividends paid on ESOP
suspense shares and on ESOP shares  allocated to participants  are used to repay
ESOP acquisition loans.  These dividends are deductible for income tax purposes.

There were  7,536,600  ESOP  suspense  shares at December 31, 1997,  with a fair
value of $319.4  million.  ESOP shares  allocated to plan  participants  totaled
13,252,988  at December 31, 1997.  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.   

                                       59
<PAGE>

Interest income on the note receivable and dividends on unallocated  ESOP shares
are not recognized for financial statement purposes.

8.  Postretirement Benefit Plans

The Company has a noncontributory  defined benefit retirement (pension) plan for
substantially  all  full-time  employees,  and funds the pension plan in amounts
that comply with  contribution  limits  imposed by law.  Pension  plan  benefits
reflect an employee's compensation, years of service and age at retirement.

The components of net periodic pension cost are (in thousands):

                                              1997         1996         1995
                                              ----         ----         ----
Actual return on plan assets           $  (110,346)   $  (76,347)  $ (103,381)
Variance from expected return,
  deferred                                  57,368        27,056       59,425
                                       -----------    ----------   ----------
     Expected return on plan assets        (52,978)      (49,291)     (43,956)
Service cost                                18,643        19,257       16,344
Interest cost on projected benefit
  obligation                                42,468        39,505       35,592
Net amortization                             1,037           466       (3,580)
                                       -----------   -----------   -----------
     Net periodic pension cost         $     9,170   $     9,937   $    4,400
                                       ===========   ===========   ===========



Reconciliations  of the funded status of the pension plan at December 31 are (in
thousands):

                                                      1997            1996
                                                      ----            ----    

Actuarial present value of benefits for services
   rendered to date:
Accumulated benefits based on salaries to date,
including vested benefits of $463.1 million for
   1997 and $415.1 million for 1996                 $ 497,517       $ 452,552
Additional benefits based on estimated future
    salary levels                                     100,643         106,136
                                                    ----------      ----------
     Projected benefit obligation                     598,160         558,688

Fair market value of plan assets, invested
   primarily in equity and fixed-income
   securities                                         768,297         683,508
                                                    ----------      ----------
     Funded status                                    170,137         124,820
Unrecognized prior service costs                       10,916           8,023
Unrecognized actuarial gain                          (212,419)       (155,145)
Unrecognized transition obligation, amortized
   over 18.5 years beginning January 1, 1987              793             899
                                                    ----------      ----------
    Accrued pension costs                           $ (30,573)      $ (21,403)
                                                    ==========      ==========

                                       60
<PAGE>

The  weighted-average  discount  rate  used to  measure  the  projected  benefit
obligation  was 7.75% in both 1997 and 1996.  The  assumed  rate of  increase in
future  compensation used to measure the projected benefit  obligation was 4.20%
in both 1997 and 1996.  The  expected  long-term  rate of return on pension plan
assets used in determining the net periodic  pension cost was 9.25% in both 1997
and 1996 and 9% in 1995.

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.

The components of net periodic OPEB cost are (in thousands):

                                             1997         1996        1995
                                             ----         ----        ----
Actual return on plan assets             $   (4,628)  $  (2,656)  $  (2,514)
Variance from expected return,
   deferred                                   2,186         726       1,420
                                        -----------  ----------  ----------
     Expected return on plan assets          (2,442)     (1,930)     (1,094)

Service cost                                  7,988       8,412       7,498
Interest cost on accumulated benefit
     obligation                              11,065      10,629      10,595
Net amortization                              5,889       5,889       5,530
                                         ----------  ----------  ----------
     Net periodic OPEB cost              $   22,500  $   23,000  $   22,529

====================================
Reconciliations  of the funded  status of the OPEB plans at  December 31 are (in
thousands):

                                              1997              1996
                                           ---------         ---------  
Actuarial present value of benefits
   for services rendered to date:
Current retires                            $  60,588         $  60,534
Active employees eligible to retire           23,009            19,607
Active employees not eligible to retire       97,727            84,346
                                           ---------         ---------
     Accumulated postretirement
     benefit obligation                      181,324           164,487

Fair market value of plan assets,
   invested  primarily in equity and
   fixed-income securities                    33,427            28,799
                                           ---------         ---------
     Funded status                          (147,897)         (135,688)

Unrecognized actuarial gain                  (10,506)          (11,339)
Unrecognized transition obligation,
   amortized over 20 years beginning
   January 1, 1993                            88,336            94,225
                                          ----------         ----------
     Accrued OPEB costs                    $ (70,067)        $ (52,802)
                                           ==========        ==========

                                       61
<PAGE>

The  assumptions  used  to  measure  the  accumulated   postretirement   benefit
obligation are:

                                                      1997            1996
                                                      ----            ----
Weighted-average discount rate                        7.75%           7.75%
Initial medical cost trend rate for
   pre-Medicare benefits                              7.20%           7.70%
Initial medical cost trend rate for
   post-Medicare benefits                             7.00%           7.50%
Ultimate medical cost trend rate                      5.25%           5.25%
Year ultimate medical cost trend rate is achieved      2005            2005

The expected long-term rate of return on plan assets used in determining the net
periodic OPEB cost was 9.25% in both 1997 and 1996 and 9% in 1995. 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 1997 would  increase
by $3.3  million,  and the  accumulated  postretirement  benefit  obligation  at
December 31, 1997, would increase by $20.8 million.  In general,  OPEB costs are
paid as claims are  incurred  and  premiums  are paid;  however,  the Company is
partially  funding  retiree health care benefits in a trust created  pursuant to
Section 401(h) of the Internal Revenue Code.

9.  Income Taxes

Deferred  income taxes are provided for temporary  differences  between book and
tax  bases of  assets  and  liabilities.  Income  taxes  are  allocated  between
operating  income  and  other  income  based on the  source of the  income  that
generated  the tax.  Investment  tax  credits  related to  operating  income are
amortized over the service life of the related property.

Net  accumulated  deferred  income  tax  liabilities  at  December  31  are  (in
thousands):

                                                1997               1996
                                                ----               ----
Accelerated depreciation and property
   cost differences                         $ 1,676,505        $ 1,734,001
Deferred costs, net                              87,829            122,580
Miscellaneous other temporary
   differences, net                                 300                 23
                                            -----------        -----------
      Net accumulated deferred income
       tax liability                        $ 1,764,634        $ 1,856,604
                                            ===========        ===========

Total deferred  income tax  liabilities  were $2.24 billion and $2.30 billion at
December 31, 1997, and 1996, respectively. Total deferred income tax assets were
$472 million at December 31, 1997, and $439 million at December 31, 1996.

A  reconciliation  of the Company's  effective  income tax rate to the statutory
federal income tax rate is as follows:

                                       62
<PAGE>

                                            1997         1996         1995
                                            ----         ----         ----
Effective income tax rate                   37.5%        39.5%        39.2%
State income taxes, net of federal
   income tax benefit                       (4.9)        (4.9)        (5.0)
Investment tax credit amortization           1.7          1.6          1.6
Other differences, net                       0.7         (1.2)        (0.8)

      Statutory federal income tax rate     35.0%        35.0%        35.0%



The provisions for income tax expense are comprised of (in thousands):

                                            1997           1996           1995
                                            ----           ----           ----
Included in Operating Expenses
Income tax expense (credit)
Current   - federal                   $  272,570     $  132,570      $ 143,440
                 state                    59,308         29,380         41,826
Deferred -  federal                      (59,618)        97,303         75,442
                  state                   (8,980)        20,955          7,860
Investment tax credit                    (10,232)       (10,445)        (9,344)
                                      ----------     ----------      ---------
   Subtotal                              253,048        269,763        259,224
                                      ----------     ----------      ---------
Harris Plant deferred costs
Investment tax credit                       (151)          (286)          (297)
                                      ----------     ----------      ---------

   Total included in operating
      expenses                           252,897        269,477        258,927
                                      ----------     ----------      ---------
Included in Other Income
Income tax expense (credit)
Current   - federal                      (14,520)       (22,382)       (20,669)
                 state                    (2,561)        (4,025)        (4,251)
Deferred - federal                        (1,766)        10,286          5,254
                 state                      (485)         2,274          1,125
                                      ----------     ----------      ---------

   Total included in other income        (19,332)       (13,847)       (18,541)
                                     -----------       --------       --------
      Total income tax expense         $ 233,565      $ 255,630      $ 240,386
                                     ===========     ==========     ==========

10.  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  operating  expenses.  The
Company's  share of  expenses  for the  jointly  owned  units is included in the
appropriate expense category.

The Company's share of the jointly owned  generating  facilities is listed below
with related information as of December 31, 1997 (dollars in millions):

                                       63
<PAGE>

                                Company                                 
                    Megawatt    Ownership Plant       Accumulate    Under
Facility            Capability  Interest  Investment  Depreciation  Construction
--------            ----------  --------- ----------  ------------  ------------
Mayo Plant               745      83.83%   $   450     $  180       $    1
Harris Plant             860      83.83%   $ 3,014     $  933       $   16
Brunswick Plant        1,521      81.67%   $ 1,420     $  910       $    4
Roxboro Unit No. 4       700      87.06%   $   231     $  104       $    4

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.

11.  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 Mayo
and Harris  Plants.  For Mayo,  the buyback  period ended in 1997. 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.  Contractual
purchases from the Mayo and Harris plants  totaled $36.2 million,  $36.7 million
and $39.4  million  for 1997,  1996 and 1995,  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, 1997, and 1996, the Company had
deferred  purchased  capacity  costs,  including  carrying  costs accrued on the
deferred balances, of $63.7 million and $69.7 million,  respectively.  Increased
purchases (which are not being deferred for future recovery)  resulting from the
1993 agreement with Power Agency were approximately $17 million, $13 million and
$10 million for 1997, 1996 and 1995, respectively.

The Company has 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 is with Duke
Energy  (Duke)  for the  purchase  of 400  megawatts  of firm  capacity  through
mid-1999.  The estimated minimum annual payments for power purchases under these
agreements are  approximately $31 million for Rockport and $48 million for Duke,
representing   capital-related   capacity  costs.  Total  purchases   (including
transmission  use  charges)  under  the  Rockport  agreement  amounted  to $61.9
million, $60.9 million and $61.8 million for 1997, 1996 and 1995,  respectively.
Total purchases  (including  transmission  use charges) under the agreement with
Duke amounted to $69.5 million,  $65.4 million and $63.8 million for 1997,  1996
and 1995, 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.

                                       64
<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  for six weeks
(beginning  17 weeks after the outage  begins) in the amount of $3.5 million per
week. For accidental  outages  extending beyond 23 weeks, the Company is covered
for the next 52 weeks in weekly amounts of $1.5 million at Brunswick Unit No. 1,
$1.45  million at  Brunswick  Unit No. 2, $1.59  million at the Harris Plant and
$1.34  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
$15.5 million with respect to the primary coverage,  $20 million with respect to
the  decontamination,  decommissioning  and excess  property  coverage  and $6.1
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  at  present  total more than $3.9
billion.  Pursuant to  regulations  of the Nuclear  Regulatory  Commission,  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
$8.9  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 $75.5 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-71

The  Company's  ability to  continue to meet the  criteria  for  application  of
SFAS-71  (see Note 6a) may be  affected  in the  future by  competitive  forces,
deregulation 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."

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 various federal
    and state  laws.  There are  several  manufactured  gas plant (MGP) sites to
    which the  Company  and  certain  entities  that were later  merged into the
    Company had some connection. In this regard, the Company, along with others,
    is participating in a cooperative effort with the North Carolina  Department
    of Environment and Natural Resources,  Division of Waste Management (DWM) to
    establish  a  uniform   framework  for  addressing   these  MGP  sites.  The
    investigation  and  remediation  of  specific  MGP sites  will be  addressed
    pursuant to one or more Administrative Orders on Consent between the DWM and
    the  potentially  responsible  party or parties.  The Company  continues  to
    investigate the identities of parties connected to individual MGP sites, the
    relative  relationships  of the Company and other parties to those sites and
    the  degree to which the  Company  will  undertake  efforts  with  others at
    individual sites.

                                       65
<PAGE>

    The Company has been notified by regulators of its  involvement or potential
    involvement in several sites,  other than MGP sites,  that require  remedial
    action. Although the Company cannot predict the outcome of these matters, it
    does not expect  costs  associated  with these  sites to be  material to the
    results of operations of the Company.

    The Company  carries a liability for the  estimated  costs  associated  with
    remedial  activities,  except for MGP site remediation costs. This liability
    is not  material  to the  financial  position of the  Company.  The MGP site
    remediation costs are not currently determinable;  however, the Company does
    not expect  those  costs to be  material  to the  financial  position of the
    Company.

2.  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 dispose of the  Company's  spent nuclear fuel by January 31, 1998.
    The DOE  defaulted on its January 31, 1998  obligation to begin taking spent
    nuclear  fuel,  and  a  group  of  utilities,   including  the  Company,  is
    considering  measures to force the DOE to take spent  nuclear fuel or to pay
    damages from monies other than the Nuclear  Waste Fund.  The Company  cannot
    predict the outcome of this matter.

    With  certain  modifications,  the  Company's  spent  nuclear  fuel  storage
    facilities  will be  sufficient  to provide  storage space for spent nuclear
    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.

3.  In the  opinion of  management,  liabilities,  if any,  arising  under other
    pending claims would not have a material  effect on the financial  position,
    results of operations or cash flows of the Company.

                                       66
<PAGE>

<TABLE>

                                            CAROLINA POWER & LIGHT COMPANY

                                   SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>
                                             Year Ended December 31, 1997

-----------------------------------------------------------------------------------------------------------------------
           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         $      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>
                                       67
<PAGE>

<TABLE>

                                             CAROLINA POWER & LIGHT COMPANY

                                     SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>

                                              Year Ended December 31, 1996

--------------------------------------------------------------------------------------------------------------------------
           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        $       2,323,808 $       8,525,513 $       -0-       $       7,159,538 $       3,689,783
                                  ================  ================  ================  ================   ===============
Reserves other than those 
deducted from assets on 
the balance sheet:
   Injuries and damages         $       1,270,881 $       1,033,504 $       -0-       $       1,026,497 $       1,277,888
                                  ================  ================  ================  ================   ===============

   Reserve for possible coal
    mine investment losses      $       7,797,250 $       -0-       $       -0-       $         172,242 $       7,625,008
                                  ================  ================  ================  ================   ===============

   Reserve for employee
    retirement and
    compensation plans          $      91,779,866 $      41,816,846 $       -0-       $      26,027,305 $     107,569,407
                                  ================  ================  ================  ================   ===============

   Reserve for environmental
     investigation and
     remediation costs          $       1,906,730 $       -0-       $       -0-       $          90,821 $       1,815,909
                                  ================  ================  ================  ================   ===============


</TABLE>
                                       68
<PAGE>

<TABLE>

                                              CAROLINA POWER & LIGHT COMPANY

                                     SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
<CAPTION>

                                               Year Ended December 31, 1995

---------------------------------------------------------------------------------------------------------------------------
           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        $       2,520,785 $       4,622,288 $       -0-       $       4,819,265 $        2,323,808
                                  ===============  ================   ===============   ===============   ================

Reserves other than those 
deducted from assets on 
the balance sheet:
   Injuries and damages         $       2,212,161 $         566,718 $       -0-       $       1,507,998 $        1,270,881
                                  ===============  ================   ===============   ===============   ================

   Reserve for possible coal
    mine investment losses      $       8,004,970 $       -0-       $       -0-       $         207,720 $        7,797,250
                                  ===============  ================   ===============   ===============   ================

   Reserve for employee
    retirement and
    compensation plans          $      88,015,413 $      36,288,787 $       -0-       $      32,524,334 $       91,779,866
                                  ===============  ================   ===============   ===============   ================

   Reserve for environmental
     investigation and
     remediation costs          $       1,976,716 $       -0-       $       -0-       $          69,986 $        1,906,730
                                  ===============  ================   ===============   ===============  =================
</TABLE>
                                       69
<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  1998  definitive  proxy  statement  dated March 30,
                  1998, 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
          1998 definitive proxy statement dated March 30, 1998, 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 Wachovia Bank of North Carolina,
                  N.A.,  Post  Office Box 3099,  Winston-Salem,  North  Carolina
                  27102 which as of December 31, 1997, owned 8,098,921 shares of
                  Common Stock (5.3% of Class) as Trustee of the Company's Stock
                  Purchase-Savings Plan.

         b)       Information on security ownership of the Company's  management
                  is set forth in the Company's 1998 definitive  proxy statement
                  dated March 30, 1998, 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 1998 definitive proxy statement dated March 30,
          1998, and incorporated by reference herein.

                                     PART IV

ITEM 14.   EXHIBITS, CONSOLIDATED 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

                                       70
<PAGE>


                3.   Exhibits Filed:
                     ---------------
                           See EXHIBIT INDEX (page 74)


          b)   Reports  on Form 8-K  filed  during or with  respect  to the last
               quarter  of 1997 and the  portion  of the first  quarter  of 1998
               prior to the filing of this Form 10-K:

                     NONE


                                       71
<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, on the 26th day of March,
1998.

                                                  CAROLINA POWER & LIGHT COMPANY
                                                  ------------------------------
                                                  (Registrant)
                                                  By:  /s/ Glenn E. Harder
                                                  ------------------------------
                                                  Executive Vice President and 
                                                  Chief Financial Officer


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.

Signature                               Title                          Date
---------                               -----                          ----
/s/ William Cavanaugh III               Principal Executive           3/18/98
-------------------------------
(William Cavanaugh III,                 Officer and Director
President and Chief Executive
Officer)


/s/ Glenn E. Harder                     Principal Financial           3/18/98
-------------------------------
(Glenn E. Harder                        Officer
Executive Vice President and
Chief Financial Officer)


/s/ Bonnie V. Hancock                   Principal Accounting          3/18/98
-------------------------------
(Bonnie V. Hancock                      Officer                       
Vice President and Controller)


/s/ Sherwood H. Smith, Jr.              Director                      3/18/98
-------------------------------
(Sherwood H. Smith, Jr., Chairman)


/s/ Leslie M. Baker, Jr.                Director                      3/18/98
-------------------------------
(Leslie M. Baker, Jr)


/s/ Edwin B. Borden                     Director                      3/18/98
-------------------------------
(Edwin B. Borden)


/s/ Felton J. Capel                     Director                      3/18/98
-------------------------------
(Felton J. Capel)

                                       72
<PAGE>

/s/ Charles W. Coker                    Director                      3/18/98
-------------------------------
(Charles W. Coker)


/s/ Richard L. Daugherty                Director                      3/18/98
-------------------------------
(Richard L. Daugherty)


/s/ Walter Y. Elisha                    Director
-------------------------------
Walter Y. Elisha


/s/ Robert L. Jones                     Director
-------------------------------
(Robert L. Jones)


/s/ Estell C. Lee                       Director                      3/18/98
-------------------------------
(Estell C. Lee)


/s/ William O. McCoy                    Director                      3/18/98
-------------------------------
(William O. McCoy)


/s/ J. Tylee Wilson                     Director                      3/18/98
-------------------------------
(J. Tylee Wilson)

                                       73
<PAGE>


<TABLE>

                                  EXHIBIT INDEX

<CAPTION>

         Exhibit Number            Description
         <S>                       <C>  

         *3a(1)                    Restated  Charter of the 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 the  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).

         *4a(1)                    Resolution  of  Board  of  Directors,   dated
                                   December 8, 1954,  authorizing  the  issuance
                                   of, and establishing the series  designation,
                                   dividend rate and  redemption  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   (W.T.   Cunningham,
                                   Successor),  Trustees  and the First  through
                                   Fifth    Supplemental    Indentures   thereto
                                   (Exhibit  2(b),  File No.  2-64189);  and the
                                   Sixth   through   Sixty-fourth   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;

                                       74
<PAGE>

                                   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),  File No.
                                   33-38349;  Exhibit 4(e),  File No.  33-50597;
                                   Exhibit  4(e) and 4(f),  File No.  33-57835);
                                   and  Exhibit  to  Current  Report on Form 8-K
                                   dated August 28, 1997, File No. 1-3382.)

         *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
                                   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).

         *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).

                                       75
<PAGE>

         *10a(5)                   Agreement Regarding New Resources and Interim
                                   Capacity   between  Carolina  Power  &  Light
                                   Company and North Carolina Eastern  Municipal
                                   Power Agency dated  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).


         +*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.

                                       76
<PAGE>

         +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)                  Employment Agreement dated September 1, 1992,
                                   by  and   between  the  Company  and  William
                                   Cavanaugh III.

         +10b(17)                  Employment  Agreement dated April 1, 1993, by
                                   and between the Company and William S. Orser.

         +10b(18)                  Employment  Arrangement  dated  September 27,
                                   1994 by and  between the Company and Glenn E.
                                   Harder.

         +10b(19)                  Personal  Services  Agreement dated September
                                   18,  1996,  by and  between  the  Company and
                                   Sherwood H. Smith, Jr.

         +10b(20)                  Employment  Agreement  dated June 2, 1997, by
                                   and   between   the  Company  and  Robert  B.
                                   McGehee.

         +10b(21)                  Employment   Agreement  dated  September  24,
                                   1997,  by and between the Company and John E.
                                   Manczak.

         12                        Computation  of  Ratio of  Earnings  to Fixed
                                   Charges and Preferred  Dividends Combined and
                                   Ratio of Earnings to Fixed Charges.

         23(a)                     Consent of Deloitte & Touche LLP.

         23(b)                     Consent of William D. Johnson.

         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.

</TABLE>
                                       77
<PAGE>