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, 2002
                                       OR

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

                 For the transition period from        to
                                                ------    ------
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                              Exact name of registrants as specified in their
    Commission             charters, state of incorporation, address of principal         I.R.S. Employer
    File Number                   executive offices, and telephone number              Identification Number

          1-15929                          Progress Energy, Inc.                            56-2155481
                                        410 South Wilmington Street
                                     Raleigh, North Carolina 27601-1748
                                         Telephone: (919) 546-6111
                                   State of Incorporation: North Carolina

           1-3382                      Carolina Power & Light Company                       56-0165465
                                   d/b/a Progress Energy Carolinas, Inc.
                                        410 South Wilmington Street
                                     Raleigh, North Carolina 27601-1748
                                         Telephone: (919) 546-6111
                                   State of Incorporation: North Carolina

                            SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
           Title of each class                     Name of each exchange on which registered
           Progress Energy, Inc.:
            Common Stock (Without Par Value)       New York Stock Exchange


                            SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
           Progress Energy, Inc.:                  None

           Carolina Power & Light Company:         $100 par value Preferred Stock, Cumulative
                                                   $100 par value Serial Preferred Stock, Cumulative
</TABLE>

Indicate by check mark whether the  registrants (1) have 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  registrants  were
required  to file  such  reports),  and (2) have  been  subject  to such  filing
requirements for the past 90 days.
Yes     X     .  No           .
    ----------      ----------

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

Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes     X     .  No           .
    ----------      ----------

Indicate by check mark whether  Carolina Power & Light Company is an accelerated
filer (as defined in Rule 12b-2 of the Act).
Yes             .  No     X     .
    ------------      ----------

As of June 30, 2002,  the  aggregate  market value of the voting and  non-voting
common   equity  of  Progress   Energy,   Inc.   held  by   non-affiliates   was
$11,466,869,123.  As of June 30, 2002, the aggregate  market value of the common
equity of Carolina Power & Light Company held by  non-affiliates  was $0. All of
the common stock of Carolina Power & Light Company is owned by Progress  Energy,
Inc.

                                       1
<PAGE>

As of February 28, 2003,  each  registrant  had the  following  shares of common
stock outstanding:

        Registrant                         Description                 Shares
        ----------                         -----------                 ------
Progress Energy, Inc.            Common Stock (Without Par Value)   239,172,863
Carolina Power & Light Company   Common Stock (Without Par Value)   159,608,055


                       DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Progress Energy and CP&L definitive proxy statements dated March
31, 2003 are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof.

This combined Form 10-K is filed separately by two registrants: Progress Energy,
Inc.  (Progress  Energy) and Carolina Power & Light Company (CP&L).  Information
contained  herein  relating  to either  individual  registrant  is filed by such
registrant solely on its own behalf.

                                       2
<PAGE>
                                TABLE OF CONTENTS

GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS


                                     PART I

ITEM 1.  BUSINESS

ITEM 2.  PROPERTIES

ITEM 3.  LEGAL PROCEEDINGS

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

         EXECUTIVE OFFICERS OF THE REGISTRANTS

                                     PART II

ITEM 5.  MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED SHAREHOLDER
         MATTERS

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

ITEM 8.  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. CONTROLS AND PROCEDURES

                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

PROGRESS ENERGY, INC. RISK FACTORS

CAROLINA POWER & LIGHT COMPANY RISK FACTORS

                                       3
<PAGE>
                                GLOSSARY OF TERMS

The following  abbreviations  or acronyms used in the text of this combined Form
10-K are defined below:

            TERM                                 DEFINITION

AFUDC                      Allowance for funds used during construction
the Agreement              Stipulation and Settlement Agreement
APEC                       Albemarle Pamlico Economic Development Corporation
Bain Capital               Bain Capital, Inc. and affiliates
Bcf                        Billion cubic feet
BellSouth Carolinas PCS    BellSouth Carolinas, PCS L.P.
Btu                        British thermal units
Caronet                    Caronet, Inc.
CERCLA or Superfund        Comprehensive Environmental Response, Compensation
                           and Liability Act of 1980, as amended
Code                       Internal Revenue Service Code
Colona                     Colona Synfuel Limited Partnership, L.L.L.P.
the Company                Progress Energy, Inc. and subsidiaries
CP&L                       Carolina Power & Light Company
CP&L Energy                CP&L Energy, Inc., now known as Progress Energy, Inc.
CR3                        Crystal River Unit No. 3
CVO                        Contingent value obligation
DOE                        United States Department of Energy
dt                         Dekatherm
DWM                        North Carolina Department of Environment and Natural
                           Resources, Division of Waste Management
EBITDA                     Earning before interest, taxes, and depreciation and
                           amortization
ENCNG                      Eastern North Carolina Natural Gas Company, formerly
                           referred to as EasternNC
EITF                       Emerging Issues Task Force
EITF Issue 02-03           EITF Issue 02-03, "Accounting for Contracts Involved
                           in Energy Trading and Risk Management Activities"
EPA                        United States Environmental Protection Agency
EPA of 1992                Energy Policy Act of 1992
ESOP                       Employee Stock Ownership Plan
FASB                       Financial Accounting Standards Board
FERC                       Federal Energy Regulatory Commission
FDEP                       Florida Department of Environment and Protection
Financial Statements       Progress Energy Financial Statements, for the year
                           ended December 31, 2002 contained under ITEM 8 herein
FIN No. 45                 FASB Interpretation No. 45, "Guarantor's Accounting
                           and Disclosure Requirements for Guarantees, Including
                           Indirect Guarantees of Indebtedness of Others - an
                           Interpretation of FASB Statements No. 5, 57 and 107
                           and Rescission of FASB Interpretation No. 34"
FIN No. 46                 FASB Interpretation No. 46, "Consolidation of
                           Variable Interest Entities - an Interpretation of
                           ARB No. 51"
Florida Power              Florida Power Corporation
Florida Progress or FPC    Florida Progress Corporation
FPSC                       Florida Public Service Commission
Funding Corp.              Florida Progress Funding Corporation
Georgia Power              Georgia Power Company
Harris Plant               Shearon Harris Nuclear Plant
Interpath                  Interpath Communications, Inc.
IBEW                       International Brotherhood of Electrical Workers
IRS                        Internal Revenue Service
ISO                        Independent System Operator
KWh                        Kilowatt-hour
kV                         Kilovolt
kVA                        Kilovolt-ampere
LIBOR                      London Inter Bank Offering Rate
LSEs                       Load-serving entities
MDC                        Maximum Dependable Capability

                                       4
<PAGE>

MGP                        Manufactured Gas Plant
Monroe Power               Monroe Power Company
MW                         Megawatt
MWh                        Megawatt-hour
NCNG                       North Carolina Natural Gas Corporation
NCUC                       North Carolina Utilities Commission
NEIL                       Nuclear Electric Insurance Limited
NOx                        SIP Call EPA rule which requires 22 states
                           including North and South Carolina to further
                           reduce nitrogen oxide emissions.
NRC                        United States Nuclear Regulatory Commission
NSP                        Northern States Power
Nuclear Waste Act          Nuclear Waste Policy Act of 1982
OPEB                       Postretirement benefits other than pensions
the Plan                   Revenue Sharing Incentive Plan
PLR                        Private Letter Ruling
Pollution control bonds    Pollution control revenue refunding bonds
Power Agency               North Carolina Eastern Municipal Power Agency
PCH                        Progress Capital Holdings, Inc.
Progress Energy            Progress Energy, Inc.
Progress Fuels             Progress Fuels Corporation, formerly Electric Fuels
                           Corporation
Progress Rail              Progress Rail Services Corporation
Progress Telecom           Progress Telecommunications Corporation
Progress                   Ventures Business segment of Progress Energy
                           primarily made up of merchant energy generation,
                           coal and synthetic fuel operations and energy
                           marketing and trading, formerly referred to as
                           Energy Ventures
Preferred Securities       FPC-obligated mandatorily redeemable preferred
                           securities of FPC Capital I
PRP                        Potentially responsible party, as defined in CERCLA
PSSP                       Performance Share Sub-Plan
PUHCA                      Public Utility Holding Company Act of 1935, as
                           amended
PURPA                      Public Utilities Regulatory Policies Act of 1978
PVI                        Legal entity of Progress Ventures, Inc. (formerly
                           referred to as CPL Energy Ventures, Inc.)
PWR                        Pressurized water reactor
QF                         Qualifying facilities
RSA                        Restricted Stock Awards program
RTO                        Regional Transmission Organization
SCPSC                      Public Service Commission of South Carolina
SEC                        United States Securities and Exchange Commission
Section 29                 Section 29 of the Internal Revenue Service Code
SFAS No. 4                 Statement of Financial Accounting Standards No. 4,
                           "Reporting Gains and Losses from Extinguishment of
                           Debt (an amendment of Accounting Principles Board
                           (APB) Opinion No. 30)"
SFAS No. 5                 Statement of Financial Accounting Standards No. 5,
                           "Accounting for Contingencies"
SFAS No. 71                Statement of Financial Accounting Standards No. 71,
                           "Accounting for the Effects of Certain Types of
                           Regulation"
SFAS No. 87                Statement of Financial Accounting Standards No. 87,
                           "Employers' Accounting for Pensions"
SFAS No. 106               Statement of Financial Accounting Standards No. 106,
                           "Employers' Accounting for Postretirement Benefits
                           Other Than Pensions"
SFAS No. 121               Statement of Financial Accounting Standards No. 121,
                           "Accounting for the Impairment of Long-Lived Assets
                           and for Long-Lived Assets to Be Disposed Of"
SFAS No. 123               Statement of Financial Accounting Standards No. 123,
                           "Accounting for Stock-Based Compensation"
SFAS No. 133               Statement of Financial Accounting Standards No. 133,
                           "Accounting for Derivative and Hedging Activities"
SFAS No. 138               Statement of Financial Accounting Standards No. 138,
                           "Accounting for Certain Derivative Instruments and
                           Certain Hedging Activities - an Amendment of FASB
                           Statement No. 133"
SFAS No. 142               Statement of Financial Accounting Standards No. 142,
                           "Goodwill and Other Intangible Assets"
SFAS No. 143               Statement of Financial Accounting Standards No. 143,
                           "Accounting for Asset Retirement Obligations"

                                       5

<PAGE>

SFAS No. 144               Statement of Financial Accounting Standards No. 144,
                           "Accounting for the Impairment or Disposal of Long-
                           Lived Assets"
SFAS No. 145               Statement of Financial Accounting Standards No. 145,
                           "Rescission of FASB Statements No. 4, 44, and 64,
                           Amendment of FASB Statement No. 13 and Technical
                           Corrections"
SFAS No. 148               Statement of Financial Accounting Standards No. 148,
                           "Accounting for Stock-Based Compensation - Transition
                           and Disclosure - An Amendment of FASB Statement
                           No. 123"
SMD NOPR                   Notice of Proposed Rulemaking in Docket No. RM01-12-
                           000, Remedying Undue Discrimination through Open
                           Access Transmission and Standard Market Design
SO2                        Sulfur dioxide
SRS                        Strategic Resource Solutions Corp.
Transco                    Transcontinental Gas Pipeline Corporation
the Trust                  FPC Capital I


                                       6
<PAGE>
                   SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

In addition, examples of forward-looking statements discussed in this Form 10-K,
include a) PART II, ITEM 7,  "Management's  Discussion and Analysis of Financial
Condition and Results of Operations"  including,  but not limited to, statements
under the  following  headings:  1)  "Liquidity  and  Capital  Resources"  about
operating cash flows,  estimated capital  requirements through the year 2005 and
future  financing  plans,  2) "Future  Outlook" about Progress  Energy's  future
earnings   potential,   and  3)  "Other   Matters"  about  the  effects  of  new
environmental  regulations,  nuclear  decommissioning  costs  and the  effect of
electric  utility  industry  restructuring,  and b) statements made in the "Risk
Factors" sections.

Any forward-looking statement speaks only as of the date on which such statement
is made,  and neither  Progress  Energy nor CP&L  undertakes  any  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 you should consider with respect to any forward-looking
statements made throughout  this document  include,  but are not limited to, the
following:  the impact of fluid and  complex  government  laws and  regulations,
including those relating to the environment;  the impact of recent events in the
energy markets that have  increased the level of public and regulatory  scrutiny
in the energy industry and in the capital markets; deregulation or restructuring
in  the  electric  industry  that  may  result  in  increased   competition  and
unrecovered (stranded) costs; the uncertainty regarding the timing, creation and
structure  of  regional  transmission  organizations;  weather  conditions  that
directly  influence  the demand  for  electricity  and  natural  gas;  recurring
seasonal fluctuations in demand for electricity and natural gas; fluctuations in
the price of energy commodities and purchased power;  economic  fluctuations and
the corresponding impact on the Company's  commercial and industrial  customers;
the  ability  of  the  Company's  subsidiaries  to  pay  upstream  dividends  or
distributions  to it; the impact on the  facilities  and the  businesses  of the
Company  from a  terrorist  attack;  the  inherent  risks  associated  with  the
operation of nuclear facilities, including environmental, health, regulatory and
financial risks; the ability to successfully access capital markets on favorable
terms;  the impact that  increases  in  leverage  may have on the  Company;  the
ability of the Company to maintain  its current  credit  ratings;  the impact of
derivative  contracts used in the normal course of business by the Company;  the
Company's  continued  ability to use Section 29 tax credits  related to its coal
and  synthetic  fuels   businesses;   the  continued   depressed  state  of  the
telecommunications  industry and the Company's ability to realize future returns
from Progress  Telecommunications  Corporation and Caronet,  Inc.; the Company's
ability  to  successfully   integrate  newly  acquired  assets,   properties  or
businesses  into its  operations as quickly or as  profitably  as expected;  the
Company's  ability to successfully  complete the sale of North Carolina  Natural
Gas and apply the proceeds  therefrom to reduce  outstanding  indebtedness;  the
Company's  ability  to  manage  the risks  involved  with the  construction  and
operation of its nonregulated plants, including construction delays,  dependence
on third  parties  and  related  counter-party  risks,  and a lack of  operating
history;  the Company's  ability to manage the risks  associated with its energy
marketing  and  trading  operations;  and  unanticipated  changes  in  operating
expenses  and capital  expenditures.  Many of these risks  similarly  impact the
Company's subsidiaries.

These and other risk factors are detailed from time to time in the Company's SEC
reports.  Many,  but not all of the factors that may impact  actual  results are
discussed in the "Risk Factors"  sections of this report.  You should  carefully
read the "Risk Factors" sections of this report.  All such factors are difficult
to predict, contain uncertainties that may materially affect actual results, and
may be beyond the control of Progress  Energy and CP&L.  New factors emerge from
time to time, and it is not possible for management to predict all such factors,
nor can it assess the effect of each such factor on Progress Energy and CP&L.

                                       7
<PAGE>
PART I

ITEM 1.  BUSINESS

GENERAL

COMPANY

Progress  Energy,  Inc.  (Progress  Energy or the Company,  which term  includes
consolidated  subsidiaries unless otherwise indicated),  is a registered holding
company under the Public Utility  Holding  Company Act (PUHCA) of 1935. Both the
Company and its subsidiaries are subject to the regulatory  provisions of PUHCA.
Progress  Energy was  incorporated on August 19, 1999. The Company was initially
formed as CP&L Energy, Inc. (CP&L Energy),  which became the holding company for
Carolina  Power & Light  Company  (CP&L) on June 19, 2000.  All shares of common
stock of CP&L were exchanged for an equal number of shares of CP&L Energy common
stock.

On July 1, 2000, CP&L  distributed its ownership  interest in the stock of North
Carolina  Natural Gas Corporation  (NCNG),  Strategic  Resource  Solutions Corp.
(SRS), Monroe Power Company (Monroe Power) and Progress Ventures,  Inc. (PVI) to
CP&L Energy.  As a result,  those companies  became direct  subsidiaries of CP&L
Energy  and are not  included  in CP&L's  results  of  operations  or  financial
position since that date.

Subsequent to the acquisition of Florida  Progress  Corporation  (FPC or Florida
Progress) (see "Significant  Transactions"  below), the Company changed its name
from CP&L Energy to Progress Energy, Inc. on December 4, 2000.

Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation
(Florida  Power)  and  NCNG,   Progress  Energy  is  primarily  engaged  in  the
generation,  transmission,  distribution  and sale of electricity in portions of
North Carolina, South Carolina and Florida; and the transportation, distribution
and sale of natural  gas in  portions of North  Carolina.  Through the  Progress
Ventures  business   segment,   Progress  Energy  is  involved  in  nonregulated
generation  operations;  natural  gas  exploration  and  production;  coal  fuel
extraction,  manufacturing  and  delivery;  and  energy  marketing  and  trading
activities.  Through the Rail Services business segment, Progress Energy engages
in various rail and railcar  related  services.  Through other  business  units,
Progress  Energy  engages  in  other   nonregulated   business  areas  including
telecommunications and holding company operations.

Effective  January 1, 2003,  CP&L,  Florida  Power and PVI began doing  business
under the names Progress Energy Carolinas,  Inc., Progress Energy Florida,  Inc.
and  Progress  Energy  Ventures,  Inc.,  respectively.  The legal names of these
entities have not changed and there is no  restructuring  of any kind related to
the name change.  The current  corporate  and business  unit  structure  remains
unchanged.

Progress  Energy is an integrated  energy  company  located  principally  in the
southeast  region  of the  United  States.  The  Company  has more  than  21,900
megawatts  (MW) of electric  generation  capacity and serves  approximately  3.0
million electric and natural gas customers in portions of North Carolina,  South
Carolina  and  Florida.  CP&L's  and  Florida  Power's  utility  operations  are
complementary:  CP&L has a summer  peaking  demand,  while  Florida  Power has a
winter peaking demand. In addition,  CP&L's greater proportion of commercial and
industrial  customers  combined  with  Florida  Power's  greater  proportion  of
residential  customers  creates a more balanced  customer  base.  The Company is
dedicated to expanding the region's electric  generation capacity and delivering
reliable, competitively priced energy.

Progress Energy revenues for the year ended December 31, 2002 were $7.9 billion,
and assets at year-end were $21.4 billion.  Its principal  executive offices are
located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone
number (919) 546-6111.  The Progress Energy home page on the Internet is located
at  http://www.progress-energy.com,  the contents of which are not and shall not
be deemed a part of this  document  or any other U.S.  Securities  and  Exchange
Commission  (SEC)  filing.  The Company  makes  available  free of charge on its
website its annual report on Form 10-K,  quarterly reports on Form 10-Q, current
reports on Form 8-K and all  amendments  to those  reports as soon as reasonably
practicable after such material is electronically filed or furnished to the SEC.

The  operations of Progress  Energy and its  subsidiaries  are divided into five
major  segments:  two  electric  utilities  (CP&L and Florida  Power),  Progress
Ventures,  Rail Services and Other.  Progress  Energy's  legal  structure is not
currently aligned with the functional  management and financial reporting of its
segments.  Whether, and when, the legal and functional  structures will converge
depends upon  legislative  and  regulatory  action,  which  cannot  currently be
anticipated.  The Other segment primarily includes  telecommunication  services,
miscellaneous   nonregulated   activities,   holding   company   operations  and
elimination entries. For information  regarding the revenues,  income and assets
attributable to the Company's business segments,  see PART II, ITEM 8, Note 4 to
the Progress Energy consolidated financial statements.

                                       8
<PAGE>
SIGNIFICANT TRANSACTIONS

Generation Acquisition

On February 15, 2002, PVI completed the  acquisition of two electric  generating
projects totaling nearly 1,100 MW in capacity in Georgia and related tolling and
power sale  agreements from LG&E Energy Corp. for a total cash purchase price of
approximately  $350 million including direct transaction costs. The two projects
consist of 1) the Walton project in Monroe,  Georgia, a 460 MW natural gas-fired
plant placed in service in June 2001 and 2) the Washington project in Washington
County,  Georgia,  a planned  600 MW  natural  gas-fired  plant  expected  to be
operational by June 2003. The  transaction  included a power purchase  agreement
with LG&E  Marketing,  Inc. for both  projects  through  December  31, 2004.  In
addition,  there is a project  management and completion  agreement whereby LG&E
Energy  Corp.  has  agreed to  manage  the  completion  of the  Washington  site
construction  for PVI in exchange for cash  consideration  of $181 million.  The
estimated  costs to complete the Washington  project as of December 31, 2002 are
approximately $57.8 million. See PART II, ITEM 8, Note 2A to the Progress Energy
consolidated financial statements for additional discussion of this transaction.

Westchester Gas Company Acquisition

On April 26, 2002,  Progress Fuels Corporation  (Progress Fuels), a wholly owned
subsidiary of Progress  Energy,  completed the  acquisition of  Westchester  Gas
Company,  which included approximately 215 natural gas-producing wells, 52 miles
of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate
purchase price of approximately  $153 million consisted of cash consideration of
approximately  $22  million and the  issuance of 2.5 million  shares of Progress
Energy common stock valued at  approximately  $129 million.  The purchase  price
included  approximately $2 million of direct  transaction  costs. The properties
are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border.  This  transaction  added  approximately  140 billion  cubic feet of gas
reserves to the growing energy portfolio of Progress  Fuels).  See PART II, ITEM
8,  Note  2B to  the  Progress  Energy  consolidated  financial  statements  for
additional discussion of this transaction.

Acquisition of Natural Gas Wells

During the first quarter of 2003,  Progress Fuels entered into three independent
transactions  to acquire  approximately  162  natural  gas-producing  wells with
proven  reserves of  approximately  195 billion  cubic feet (Bcf) from  Republic
Energy,  Inc. and two other  privately-owned  companies,  all  headquartered  in
Texas.  The total gross purchase price for the  transactions  was  approximately
$133 million.

Wholesale Energy Contract Acquisition

On March 20, 2003, PVI entered into a definitive  agreement with Williams Energy
Marketing  and  Trading,  a  subsidiary  of  Williams,  to  acquire a  long-term
full-requirements power supply agreement with Jackson Electric Membership Corp.,
located in Jefferson, Georgia. The agreement calls for a $188 million payment to
Williams in exchange for assignment of the Jackson supply  agreement.  The power
supply  agreement  runs  through  2015 and includes the use of 640 MW of Georgia
system  generation  comprised of nuclear,  coal,  gas and  pumped-storage  hydro
resources. Progress Energy expects to supplement the acquired resources with its
own  intermediate  and peaking assets in Georgia to serve  Jackson's  forecasted
1,100 MW peak demand in 2005  growing to a 1,700 MW demand by 2015.  The sale is
expected to close in the second  quarter of 2003,  subject to customary  closing
conditions.

NCNG Divestiture

On October 16, 2002, the Company  approved the sale of NCNG to Piedmont  Natural
Gas Company, Inc. As a result of this action, the operating results of NCNG were
reclassified to  discontinued  operations for all reportable  periods.  Progress
Energy  expects  to sell  NCNG in the  summer  of  2003,  for  net  proceeds  of
approximately  $400  million.  The asset  group,  including  goodwill,  has been
recorded  at fair value less cost to sell,  resulting  in an  estimated  loss on
disposal of  approximately  $29.4  million,  which has been  recorded  until the
disposition is complete and the actual loss can be determined. See PART II, ITEM
8, Note 3A to the Progress Energy consolidated financial statements.

Railcar Ltd. Divestiture

In December 2002, the Progress Energy Board of Directors adopted a resolution to
sell the assets of  Railcar  Ltd.,  a leasing  subsidiary  included  in the Rail
Services  segment.  An  estimated  impairment  on assets  held for sale of $58.8
million has been  recognized for the write-down of the assets to be sold to fair
value less the costs to sell. See PART II, ITEM 8, Note 3 to the Progress Energy
consolidated financial statements.

On March 12, 2003, the Company signed a letter of intent to sell Railcar Ltd. to
The Andersons,  Inc. The proceeds of the sale will be used by the Company to pay
off Railcar Ltd. lease obligations.  The transaction is still subject to various
closing conditions  including  financing,  due diligence and the completion of a
definitive purchase agreement.

Florida Progress Acquisition

On  November  30,  2000,  the  Company  completed  its  acquisition  of  FPC,  a
diversified,  exempt electric utility holding company, for an aggregate purchase
price of  approximately  $5.4 billion.  The Company paid cash  consideration  of
approximately  $3.5  billion and issued 46.5  million  common  shares  valued at
approximately  $1.9  billion.  In  addition,  the Company  issued  98.6  million
contingent value obligations (CVOs) valued at approximately  $49.3 million.  See
PART  II,  ITEM  8,  Note  2C to  the  Progress  Energy  consolidated  financial
statements for additional discussion of the FPC acquisition.

                                       9

<PAGE>

The FPC  acquisition  was accounted for using the purchase  method of accounting
and,  accordingly,  the results of operations  for FPC have been included in the
Company's consolidated financial statements since the date of acquisition.

Sale of MEMCO Barge Line, Inc.

On July 23, 2001, Progress Energy announced the disposition of the Inland Marine
Transportation  segment of FPC,  which was  operated by MEMCO  Barge Line,  Inc.
Inland Marine provided  transportation of coal,  agricultural and other dry-bulk
commodities  as well as fleet  management  services.  On November  1, 2001,  the
Company  completed the sale of the Inland Marine  Transportation  segment to AEP
Resources,  Inc., a wholly owned subsidiary of American Electric Power. See PART
II, ITEM 8, and Note 3C to the Progress Energy consolidated financial statements
for additional discussion of this transaction.

COMPETITION

GENERAL

In recent years,  the electric  utility  industry has  experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy.  Several states have also decided to restructure  aspects
of retail electric service. The issue of retail restructuring and competition is
being  reviewed  by a number of states  and bills have been  introduced  in past
sessions of Congress that sought to introduce such restructuring in all states.

Several  electric  industry  restructuring  bills  introduced  during  the 106th
Congress died upon  adjournment in 2000.  During the 107th  Congress,  attention
turned more toward a comprehensive  energy policy as opposed to restructuring of
the  electric  industry.  However,  the 107th  Congress  failed to pass either a
comprehensive energy policy or industry restructuring bills. Restructuring could
eventually  become part of any  legislation  and/or specific  electric  industry
restructuring  legislation  could be  introduced  and  considered  by the  108th
Congress. The Company cannot predict the outcome of this matter.

As a result of the Public Utilities  Regulatory Policies Act of 1978 (PURPA) and
the  Energy  Policy  Act of 1992 (EPA of  1992),  competition  in the  wholesale
electricity market has greatly increased, especially from non-utility generators
of electricity.  In 1996, the Federal Energy Regulatory Commission (FERC) issued
new rules on  transmission  service to facilitate  competition  in the wholesale
market on a  nationwide  basis.  The rules  give  greater  flexibility  and more
choices to wholesale power customers.

In  early  2000,  the  FERC  issued  Order  No.  2000 on  Regional  Transmission
Organizations (RTOs), which set minimum  characteristics and eight functions for
transmission  entities,  including independent system operators and transmission
companies,  that are required to become FERC-approved RTOs. The rule stated that
public utilities that own, operate or control interstate transmission facilities
had to have filed,  by October 15, 2000,  either a proposal to participate in an
RTO or an alternative  filing describing  efforts and plans to participate in an
RTO. The order  provided  guidance and  specified  minimum  characteristics  and
functions required of an RTO and also stated that all RTOs should be operational
by December 15, 2001.  During 2001, the deadline for RTOs to be operational  was
extended.   See   PART  I,   ITEM  1,   "Competition"   of   Electric-CP&L   and
Electric-Florida  Power for a discussion of the  development  activities for the
GridSouth RTO and  GridFlorida  RTO,  respectively.  See PART II, ITEM 7, "Other
Matters," for additional discussion of current developments.

On July 31, 2002,  the FERC issued its Notice of Proposed  Rulemaking  in Docket
No. RM01-12-000 Remedying Undue Discrimination  through Open Access Transmission
Service and Standard  Electricity  Market Design (SMD NOPR).  The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission owning utilities transfer control of their transmission  facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC-regulated  transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities  be required to meet  minimum  criteria  for  generating  reserves.  On
January 15, 2003,  the FERC  announced the issuance of a White Paper on SMD NOPR
to be  released in April 2003.  The FERC has also  indicated  that it expects to
issue final rules during the summer of 2003.  See PART I, ITEM 1,  "Competition"
of Electric-CP&L and Electric-Florida Power for further discussion.

                                       10
<PAGE>

To date, many states have adopted  legislation  that would give retail customers
the right to choose their  electricity  provider  (retail choice) and most other
states have, in some form,  considered the issue. There is currently no proposed
legislation in North Carolina,  South Carolina,  or Florida that would introduce
retail choice.

The developments  described above have created changing markets for energy. As a
strategy for  competing  in these  changing  markets,  the Company is becoming a
total energy provider in the region by providing a full array of  energy-related
services to its current  customers and  expanding its market reach.  The Company
took a major step towards  implementing this strategy through its acquisition of
FPC.

See PART I, ITEM 1, "Competition," under Electric-CP&L,  Electric-Florida  Power
and Other for  further  discussion  of  competitive  developments  within  these
segments.

PUHCA

As a result of the  acquisition  of FPC,  Progress  Energy  is now a  registered
holding  company  subject  to  regulation  by the SEC  under  PUHCA.  Therefore,
Progress Energy and its subsidiaries are subject to the regulatory provisions of
PUHCA,  including  provisions relating to the issuance of securities,  sales and
acquisitions  of  securities  and utility  assets,  and  services  performed  by
Progress Energy Service Company, LLC.

While various  proposals have been introduced in Congress  regarding  PUHCA, the
prospects for legislative reform or repeal are uncertain at this time.

ENVIRONMENTAL

GENERAL

In the areas of air quality,  water  quality,  control of toxic  substances  and
hazardous  and solid  wastes and other  environmental  matters,  the  Company is
subject to  regulation  by various  federal,  state and local  authorities.  The
Company   considers   itself  to  be  in  substantial   compliance   with  those
environmental  regulations  currently  applicable to its business and operations
and  believes  it  has  all  necessary   permits  to  conduct  such  operations.
Environmental  laws and regulations  constantly evolve and the ultimate costs of
compliance cannot always be accurately  estimated.  The capital costs associated
with  compliance  with pollution  control laws and  regulations at the Company's
existing  fossil  facilities that the Company expects to incur from 2003 through
2005 are included in the estimates under the "Investing  Activities"  discussion
under PART II, ITEM 7, "Liquidity and Capital Resources."

CLEAN AIR LEGISLATION

The 1990  amendments  to the Clean Air Act  require  substantial  reductions  in
sulfur  dioxide  and  nitrogen  oxide  emissions  from  fossil-fueled   electric
generating plants. The Clean Air Act required the Company to meet more stringent
provisions  effective  January 1, 2000.  The  Company  meets the sulfur  dioxide
emissions   requirements  by  maintaining  sufficient  sulfur  dioxide  emission
allowances.  Installation  of  additional  equipment  was  necessary  to  reduce
nitrogen oxide emissions.  Increased operation and maintenance costs,  including
emission allowance expense,  installation of additional  equipment and increased
fuel  costs  are not  expected  to be  material  to the  consolidated  financial
position or results of operations of the Company.

The U.S.  Environmental  Protection  Agency (EPA) is conducting  an  enforcement
initiative  related to a number of coal-fired  utility power plants in an effort
to  determine  whether  modifications  at those  facilities  were subject to New
Source Review  requirements or New Source Performance  Standards under the Clean
Air Act.  Both CP&L and Florida Power were asked to provide  information  to the
EPA as part  of this  initiative  and  cooperated  in  providing  the  requested
information.  The EPA initiated  enforcement  actions against other unaffiliated
utilities as part of this initiative,  some of which have resulted in settlement
agreements calling for expenditures,  ranging from $1.0 billion to $1.4 billion.
A utility  that was not subject to a civil  enforcement  action  settled its New
Source Review issues with the EPA for $300 million.  These settlement agreements
have generally  called for  expenditures  to be made over extended time periods,
and some of the  companies  may seek  recovery of the related  cost through rate
adjustments. The Company cannot predict the outcome of this matter.

                                       11

<PAGE>

In 1998,  the EPA  published  a final  rule  addressing  the  issue of  regional
transport of ozone.  This rule is commonly  known as the NOx SIP Call. The EPA's
rule requires 23  jurisdictions,  including North  Carolina,  South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to
attain a pre-set  state NOx emission  level by May 31,  2004.  CP&L is currently
installing  controls  necessary  to comply with the rule.  Capital  expenditures
needed to meet these  measures in North  Carolina and South Carolina could reach
approximately  $370  million,  which has not been  adjusted for  inflation.  The
Company  has  spent   approximately  $194  million  to  date  related  to  these
expenditures.  Increased operation and maintenance costs relating to the NOx SIP
Call are not  expected to be material to the  Company's  results of  operations.
Further controls are anticipated as electricity  demand  increases.  The Company
cannot predict the outcome of this matter.

The EPA  published a final rule  approving  petitions  under  Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain sources to
make  reductions in nitrogen oxide emissions by May 1, 2003. The final rule also
includes a set of regulations  that affect nitrogen oxide emissions from sources
included in the petitions.  The North Carolina  coal-fired  electric  generating
plants are included in these petitions. Acceptable state plans under the NOx SIP
Call can be approved in lieu of the final rules the EPA  approved as part of the
Section 126 petitions.  CP&L, other  utilities,  trade  organizations  and other
states participated in litigation challenging the EPA's action. On May 15, 2001,
the  District of Columbia  Circuit  Court of Appeals  ruled in favor of the EPA,
which will require North Carolina to make reductions in nitrogen oxide emissions
by May 1, 2003.  However,  the Court in its May 15th decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in calculating
the emissions limits for utilities.  In August 2001, the Court granted a request
by CP&L and other utilities to delay the  implementation of the Section 126 Rule
for electric generating units pending resolution by the EPA of the growth factor
issue. The Court's order tolls the three-year  compliance period (originally set
to end on May 1, 2003) for  electric  generating  units as of May 15,  2001.  On
April 30, 2002,  the EPA  published a final rule  harmonizing  the dates for the
Section 126 rule and the NOx SIP Call. In addition,  the EPA  determined in this
rule that the future growth factor estimation  methodology was appropriate.  The
new compliance  date for all affected  sources is now May 31, 2004,  rather than
May 1, 2003.  The EPA has approved  North  Carolina's  NOx SIP Call rule and has
indicated  it will  rescind the Section  126 rule in a future rule  making.  The
Company expects a favorable outcome of this matter.

On June 20,  2002,  legislation  was  enacted in North  Carolina  requiring  the
state's electric  utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide  from  coal-fired  power  plants.   The  legislation  also  freezes  the
utilities' base rates for five years unless there are  significant  cost changes
due to governmental  action,  significant  expenditures due to force majeure and
other  extraordinary  events beyond the control of the utilities,  or unless the
utilities  persistently  earn a return  substantially  in  excess of the rate of
return  established  and found  reasonable  by the NCUC in the  utilities'  last
general  rate case.  See PART II,  ITEM 8, and Note 24E to the  Progress  Energy
consolidated financial statements for additional discussion of this transaction.

SUPERFUND

The provisions of the  Comprehensive  Environmental  Response,  Compensation and
Liability  Act of 1980,  as amended  (CERCLA),  authorize the EPA to require the
clean up of hazardous waste sites.  This statute imposes  retroactive  joint and
several liability. Some states, including North and South Carolina, have similar
types of  legislation.  There are presently  several sites with respect to which
the Company has been  notified  by the EPA,  the State of North  Carolina or the
State of Florida  of its  potential  liability,  as  described  below in greater
detail.

Various organic  materials  associated with the production of manufactured  gas,
generally  referred to as coal tar, are regulated  under federal and state laws.
The lead or sole regulatory  agency that is responsible for a particular  former
coal tar site depends largely upon the state in which the site is located. There
are several  manufactured gas plant (MGP) sites to which both electric utilities
and the  gas  utility  have  some  connection.  In this  regard,  both  electric
utilities and the gas utility,  with other potentially  responsible parties, are
participating in investigating  and, if necessary,  remediating  former coal tar
sites with several regulatory agencies,  including, but not limited to, the EPA,
the Florida Department of Environmental Protection (FDEP) and the North Carolina
Department of Environment and Natural  Resources,  Division of Waste  Management
(DWM).  Although  the  Company may incur costs at these sites about which it has
been notified,  based upon current  status of these sites,  the Company does not
expect  those  costs to be material to its  consolidated  financial  position or
results of operations.

Both electric  utilities,  the gas utility,  Progress Ventures and Progress Rail
are  periodically  notified  by  regulators  such as the EPA and  various  state
agencies of their involvement or potential  involvement in sites, other than MGP
sites, that may require investigation and/or remediation. Although the Company's
subsidiaries  may incur costs at the sites about which they have been  notified,
based upon the current status of these sites,  the Company does not expect those
costs to be  material  to the  consolidated  financial  position  or  results of
operations of the Company.

                                       12

<PAGE>

OTHER ENVIRONMENTAL MATTERS

On November 1, 2001,  Progress  Energy  completed  the sale of the Inland Marine
Transportation  business to AEP  Resources,  Inc. In  connection  with the sale,
Progress Energy entered into environmental  indemnification  provisions covering
both  unknown  and known  sites.  Progress  Energy  recorded an accrual to cover
estimated  probable  future  environmental  expenditures.  The  balance  of this
accrual is $9.9 million at December 31, 2002.  Progress  Energy believes that it
is  reasonably  possible  that  additional  costs,  which  cannot  be  currently
estimated,  may  be  incurred  related  to  the  environmental   indemnification
provision beyond the amounts accrued. Progress Energy cannot predict the outcome
of this matter.

Both electric utilities, the gas utility and Progress Ventures have filed claims
with the Company's general liability insurance carriers to recover costs arising
out of actual or  potential  environmental  liabilities.  Some  claims have been
settled  and others are still  pending.  While  management  cannot  predict  the
outcome of these matters,  the outcome is not expected to have a material effect
on the Company's consolidated financial position or results of operations.

EMPLOYEES

As  of  February  28,  2003,  Progress  Energy  and  its  subsidiaries  employed
approximately  15,300 full-time  employees.  Of this total,  approximately 2,100
employees at Florida Power are represented by the  International  Brotherhood of
Electrical Workers (IBEW). Florida Power and the IBEW reached agreement in early
December 2002 on a new three-year labor contract.  The previous contract expired
December 1, 2002.

The Company and some of its subsidiaries have a non-contributory defined benefit
retirement  (pension)  plan for  substantially  all  full-time  employees and an
employee stock purchase plan among other employee benefits. The Company and some
of its subsidiaries also provide contributory postretirement benefits, including
certain health care and life insurance  benefits,  for substantially all retired
employees.

As of February 28, 2003, CP&L employed approximately 5,300 full-time employees.

ELECTRIC - CP&L

GENERAL

CP&L 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.  As of December 31,
2002,  CP&L had a total  summer  generating  capacity  (including  jointly-owned
capacity) of approximately 12,327 MW.

CP&L  distributes  and  sells  electricity  in 57 of the 100  counties  in North
Carolina and 14 counties in northeastern South Carolina. The territory served is
an area of approximately 34,000 square miles, including a substantial portion of
the coastal plain of North Carolina  extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont section of North
Carolina,  an area in  northeastern  South Carolina and an area in western North
Carolina in and around the city of Asheville.  The estimated total population of
the territory  served is more than 4.0 million.  At December 31, 2002,  CP&L was
providing electric services,  retail and wholesale, to approximately 1.3 million
customers.  Major wholesale power sales customers include North Carolina Eastern
Municipal  Power Agency (Power  Agency) and North Carolina  Electric  Membership
Corporation. CP&L is subject to the rules and regulations of the FERC, the North
Carolina Utilities  Commission (NCUC) and the Public Service Commission of South
Carolina (SCPSC).


                                       13
<PAGE>
BILLED ELECTRIC REVENUES

CP&L's electric  revenues billed by customer class, for the last three years, is
shown as a percentage of total CP&L electric revenues in the table below:

                            BILLED ELECTRIC REVENUES

       Revenue Class             2002           2001            2000
       -------------             ----           ----            ----
       Residential                35%            34%             33%
       Commercial                 24%            23%             22%
       Industrial                 18%            21%             23%
       Wholesale (a)              19%            19%             18%
       Other retail                4%             3%              4%

     (a)  These revenues are managed by the Progress  Ventures segment on behalf
          of CP&L.

Major  industries in CP&L's service area include  textiles,  chemicals,  metals,
paper,  food,  rubber and plastics,  wood products and electronic  machinery and
equipment.

FUEL AND PURCHASED POWER

Sources of Generation

CP&L's total system  generation  (including  jointly owned  capacity) by primary
energy source, along with purchased power, for the last three years is set forth
below:

                             ENERGY MIX PERCENTAGES

                                 2002           2001            2000
                                 ----           ----            ----
       Coal                       46%            49%             48%
       Nuclear                    42%            41%             43%
       Hydro                       1%             0%              1%
       Oil/Gas                     3%             2%              1%
       Purchased power             8%             8%              7%

CP&L is generally  permitted to pass the cost of recoverable  fuel and purchased
power to its customers  through fuel adjustment  clauses.  The future prices for
and  availability  of various fuels discussed in this report cannot be predicted
with complete certainty.  However, CP&L believes that its fuel supply contracts,
as described below, will be adequate to meet its fuel supply needs.

CP&L's average fuel costs per million  British  thermal units (Btu) for the last
three years were as follows:

                                AVERAGE FUEL COST
                                (per million Btu)

                                 2002        2001        2000
                                 ----        ----        ----
       Coal (a)                $ 1.93      $ 1.78      $ 1.70
       Nuclear                   0.43        0.44        0.45
       Hydro                        -           -           -
       Oil (a)                   5.48        6.38        5.51
       Gas (a)                   5.31        4.69        5.41
       Weighted average          1.38        1.26        1.21

     (a)  Changes  in the  unit  price  for  oil  and  gas  are  due  to  market
          conditions.  Changes in the unit price for coal are  primarily  due to
          transportation  costs.  Since  these  costs  are  primarily  recovered
          through  recovery clauses  established by regulators,  fluctuations do
          not materially affect net income.

                                       14
<PAGE>

Coal

CP&L  anticipates a requirement  of  approximately  11.8 million to 12.2 million
tons of coal in 2003. Almost all of the coal is expected to be supplied from the
Appalachian  coal fields in the United States.  Most of the coal is delivered by
rail.

For 2003,  CP&L has  short-term,  intermediate  and  long-term  agreements  from
various  sources  for  approximately  95% of its burn  requirements  of its coal
units.  These contracts have price  adjustment  provisions and expiration  dates
ranging  from  2003 to 2008.  All of the coal  that  CP&L  has  purchased  under
intermediate  and  long-term  agreements  is considered to be low sulfur coal by
industry standards.

Nuclear

Nuclear fuel is processed through four distinct stages.  Stages I and II involve
the mining and milling of the natural  uranium ore to produce a concentrate  and
the  conversion of this uranium  oxide  concentrate  into uranium  hexafluoride.
Stages III and IV entail the  enrichment  of the  uranium  hexafluoride  and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

CP&L has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement needs. CP&L reserves a small portion
of its uranium and conversion requirements for spot procurements. CP&L typically
contracts for all of its enrichment services and fabrication needs with contract
durations  ranging  from five to ten years.  Although  CP&L  cannot  predict the
future  availability  of  uranium  and  nuclear  fuel  services,  CP&L  does not
currently expect to have difficulty  obtaining  uranium oxide concentrate or the
services  necessary for its conversion,  enrichment and fabrication into nuclear
fuel.  For a discussion of CP&L's plans with respect to spent fuel storage,  see
PART I, ITEM 1, "Nuclear Matters," for CP&L Electric.

Hydroelectric

Hydroelectric  power is electric energy generated by the force of falling water.
CP&L has three  hydroelectric  generating plants licensed by the FERC:  Walters,
Tillery  and  Blewett.  CP&L also owns the  Marshall  Plant  which has a license
exemption.  The total  maximum  dependable  capacity  for these units is 218 MW.
Record low rainfall in the summer months of 2002 had a  corresponding  effect on
energy  production  from these  facilities.  CP&L is seeking  to  relicense  its
Tillery and Blewett Plants.  These plants'  licenses  currently  expire in April
2008. The Walters plant license will expire in 2034.

Oil & Gas

Oil is purchased under contracts and in the spot market from several  suppliers.
The cost of CP&L's oil and gas is  determined  by market  prices as  reported in
certain industry  publications.  Management  believes that CP&L has access to an
adequate supply of oil for the reasonably foreseeable future. CP&L believes that
the threat of or a war against  Iraq could  negatively  impact the price of oil.
CP&L's natural gas supply and  transportation is purchased under firm supply and
transportation  contracts  as  well  as  spot  market  purchases  from  numerous
suppliers. CP&L believes that existing contracts for oil are sufficient to cover
its  requirements  if natural gas is  unavailable  during the winter  period for
CP&L's combustion turbine peaker fleet.

Purchased Power

CP&L purchased 4,769,194 MWh in 2002, 4,996,645 MWh in 2001 and 4,467,802 MWh in
2000 of its system energy  requirements  (including  jointly-owned capacity) and
had  available  1,737 MW in 2002,  1,756 MW in 2001 and 1,036 MW in 2000 of firm
purchased  capacity  under  contract at the time of peak load.  CP&L may acquire
purchased  power  capacity in the future to  accommodate a portion of its system
load needs.

COMPETITION

Electric Industry Restructuring

CP&L continues to monitor progress toward a more competitive environment and has
actively  participated in regulatory reform  deliberations in North Carolina and
South Carolina.  Movement toward  deregulation in these states has been affected

                                       15

<PAGE>

by recent  developments,  including  developments related to deregulation of the
electric  industry in California  and other  states.  CP&L expects that both the
North Carolina and South Carolina  General  Assemblies  will continue to monitor
the  experiences  of  states  that  have  implemented   electric   restructuring
legislation.

Regional Transmission Organizations

In  October  2000,  as a result of Order  2000,  CP&L,  along  with Duke  Energy
Corporation and South Carolina Electric & Gas Company, filed an application with
the FERC for approval of a GridSouth  RTO. On July 12, 2001,  the FERC issued an
order provisionally approving GridSouth.

See PART II, ITEM 7,  "Other  Matters,"  for  additional  discussion  of current
developments of GridSouth RTO.

Standard Market Design

On July 31, 2002,  the FERC issued its Notice of Proposed  Rulemaking  in Docket
No. RM01-12-000 Remedying Undue Discrimination  through Open Access Transmission
Service and Standard  Electricity  Market Design (SMD NOPR).  The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission owning utilities transfer control of their transmission  facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC-regulated  transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities  be required to meet  minimum  criteria  for  generating  reserves.  If
adopted as proposed,  the rules set forth in the SMD NOPR would materially alter
the manner in which  transmission and generation  services are provided and paid
for.  CP&L filed  comments on November  15,  2002 and  supplemental  comments on
January 10, 2003.  On January 15,  2003,  the FERC  announced  the issuance of a
White  Paper  on SMD  NOPR to be  released  in April  2003.  CP&L  plans to file
comments  on the White  Paper.  The FERC has also  indicated  that it expects to
issue final rules during the summer of 2003.

Franchises

CP&L has  nonexclusive  franchises with varying  expiration dates in most of the
municipalities  in which it  distributes  electric  energy in North Carolina and
South Carolina. Of these 239 franchises,  194 have expiration dates ranging from
2008 to 2061 and 45 of these have no specific  expiration  dates.  All but 13 of
the 194 franchises with expiration dates have a term of 60 years. The exceptions
include  three  franchises  with terms of ten  years,  one with a term of twenty
years,  six with terms of thirty  years,  two with terms of forty  years and one
with a term of fifty  years.  However,  CP&L  also  serves  within  a number  of
municipalities  and  in  all  of  its  unincorporated  areas  without  franchise
agreements.

Wholesale Competition

Since passage of the EPA of 1992,  competition in the wholesale electric utility
industry  has  significantly   increased  due  to  a  greater  participation  by
traditional electricity suppliers, wholesale power marketers and brokers and due
to the trading of energy  futures  contracts on various  commodities  exchanges.
This increased  competition could affect CP&L'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 CP&L 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  previously
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.  CP&L filed its
open access transmission tariff with the FERC in mid-1996. Several wholesale and
retail  customers filed protests  challenging  numerous aspects of CP&L's tariff
and requesting that an evidentiary  proceeding be held. In July 1997, CP&L filed
an offer of settlement in this case which was certified by an administrative law
judge in September  1997. In February  2000,  the FERC issued a basket order for
several  utilities  including CP&L to file a compliance  filing stating  whether
there were any  remaining  undisputed  issues  surrounding  CP&L's  open  access
transmission  tariff.  On May 1, 2000,  CP&L made the compliance  filing setting
forth the remaining  undisputed  issues and a plan for settling those issues. On
August 25, 2000, CP&L filed modifications to its open access transmission tariff
as a result  of  settlement  negotiations  with the  remaining  intervenors.  In
November  2000,  the FERC approved the open access  transmission  tariff of CP&L
with the settlement modifications.

                                       16

<PAGE>

In February  2000,  CP&L filed a joint open access  tariff to reflect the merger
with FPC.  The FERC  approved  the joint  tariff  in July  2000  effective  with
completion  of the merger,  which  occurred on November 30, 2000. In April 2001,
CP&L and FPC each filed  separate  transmission  tariffs as a result of the FERC
Order 614. The FERC approved the CP&L transmission tariff in June 2001. In April
2001, CP&L filed changes to the Energy  Imbalance  provision of the transmission
tariff.  In October  2001,  the FERC  approved  changes to the Energy  Imbalance
provision  of the  transmission  tariff.  The FERC  ordered  CP&L to  develop  a
mechanism  to  credit  Energy   Imbalance   penalty  revenues  to  non-offending
transmission  customers.  In November  2001,  CP&L put in place a  mechanism  to
credit revenues to non-offending transmission customers.

During 2001,  legislation  was  introduced in South Carolina that would impose a
moratorium on the  certification  and construction of merchant plants until 2003
and prohibit the transfer or sale of a merchant plant certificate. Hearings were
held on these bills but no action has been taken. In addition, the Department of
Health and  Environmental  Control of South  Carolina has halted the issuance of
any air  permits  for  merchant  plants  applying  for such  permits.  The SCPSC
contracted  with a consulting  firm to conduct a study on the impact of merchant
plants in South  Carolina  which was completed in the summer of 2002.  The study
concluded  that the proper  approach to merchant  plants should be driven by the
State's  position with regard to what role the market should play in determining
the need for electric  generation as opposed to the  traditional  methodology of
relying  upon the  State's  utilities  to  determine  the  need  for  additional
generation.  No  actions  have  been  taken as a result  of the study and no new
construction  of merchant  plants has begun.  CP&L cannot predict the outcome of
this matter.

REGULATORY MATTERS

General

CP&L 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.  In addition, CP&L is subject to regulation by the FERC with respect
to  transmission  and sales of wholesale  power,  accounting  and certain  other
matters. The underlying concept of utility ratemaking is to set rates at a level
that  allows  the  utility to collect  revenues  equal to its cost of  providing
service  including  a  reasonable  rate  of  return  on  its  equity.  Increased
competition  as a result of  industry  restructuring  may affect the  ratemaking
process.

Electric Retail Rates

The NCUC and the SCPSC  authorize  retail  "base  rates"  that are  designed  to
provide a utility with the  opportunity to earn a specific rate of return on its
"rate base," or investment in utility  plant.  These rates are intended to cover
all  reasonable  and  prudent  expenses  of  utility  operations  and to provide
investors with a fair rate of return.  In CP&L's most recent rate cases in 1988,
the NCUC and the SCPSC each authorized a return on equity of 12.75% for CP&L.

Legislation  enacted in North  Carolina in 2002 freezes CP&L's base retail rates
for five years unless  there are  significant  cost changes due to  governmental
action,  significant  expenditures  due to force majeure or other  extraordinary
events beyond the control of CP&L.

See PART II,  ITEM 8, Note 15C to the  Progress  Energy  consolidated  financial
statements  and  Note  9B to the  CP&L  consolidated  financial  statements  for
additional discussion of CP&L's retail rate developments during 2002.

Wholesale Rate Matters

CP&L 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 FERC determines,  accounting policies and practices. CP&L 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.

                                       17
<PAGE>

Fuel Cost Recovery

CP&L's  operating costs not covered by the utility's base rates include fuel and
purchased  power.  Each state  commission  allows electric  utilities to recover
certain of these costs through various cost recovery clauses,  to the extent the
respective  commission  determines  in an annual  hearing  that  such  costs are
prudent. Costs recovered by CP&L, by state, are as follows:

     o    North Carolina - fuel costs and the fuel portion of purchased power
     o    South  Carolina  - fuel  costs,  certain  purchased  power  costs  and
          emission allowance expense

Each state  commission's  determination  results in the addition of a rider to a
utility's  base rates to reflect the  approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method  allowed  for  recovery,  changes  from year to year have no material
impact on operating results.

NUCLEAR MATTERS

General

CP&L owns and  operates  four  nuclear  units,  which are  regulated by the U.S.
Nuclear Regulatory  Commission (NRC) under the Atomic Energy Act of 1954 and the
Energy  Reorganization  Act of 1974. In the event of noncompliance,  the NRC has
the authority to impose fines, set license conditions, shut down a nuclear unit,
or some  combination of these,  depending upon its assessment of the severity of
the situation,  until compliance is achieved.  NRC operating  licenses currently
expire  in  December  2014  and  September  2016  for  Brunswick  Units 2 and 1,
respectively,  in July 2010 for Robinson  Unit No. 2 and in October 2026 for the
Harris  Plant.  An  application  to extend  the  Robinson  license  20 years was
submitted  in June 2002 and a similar  application  is  expected  to be made for
Brunswick  in December  2004.  An  extension  will also be sought for the Harris
Plant.  On February  20, 2003,  CP&L  notified the NRC of its intent to submit a
license  renewal  application  for the Harris  Plant in 2006. A condition of the
operating  license for each unit requires an approved  plan for  decontamination
and decommissioning.  The nuclear units are periodically removed from service to
accommodate normal refueling and maintenance outages,  repairs and certain other
modifications.

In addition,  the  Independent  Spent Fuel Storage  Installation at the Robinson
plant  will  request to have its  license  extended  20 years with an  exemption
request for an additional  20-year  extension  during the first quarter of 2004.
Its current  license is due to expire in August  2006.  The  Company  expects to
receive this extension.

CP&L is currently  evaluating  and  implementing  power  uprate  projects at its
nuclear facilities to increase electrical  generation output. A power uprate was
completed at the Harris Plant during 2001 and at the Robinson  Nuclear  Plant in
2002. Power uprates are also in progress at the Brunswick Plant.  Brunswick Unit
1 increased  its  capacity  by 52 MW in 2002 and  additional  increases  will be
implemented  in  phases  over  the  next  several  years.  The  total  increased
generation from these projects is estimated to be approximately 250 MW.

The nuclear  power  industry  faces  uncertainties  with respect to the cost and
long-term  availability  of sites for  disposal of spent  nuclear fuel and other
radioactive waste,  compliance with changing  regulatory  requirements,  nuclear
plant operations, increased capital outlays for modifications, the technological
and financial  aspects of  decommissioning  plants at the end of their  licensed
lives and requirements relating to nuclear insurance.

Pressurized Water Reactors

On March 18, 2002,  the NRC sent a bulletin to companies  that hold licenses for
pressurized  water  reactors  (PWRs)  requiring  information  on the  structural
integrity of the reactor vessel head and a basis for concluding  that the vessel
head will continue to perform its function as a coolant pressure  boundary.  The
Company  filed  responses  as required.  Inspections  of the vessel heads at the
Company's  PWR  plants  have been  performed  during  previous  outages.  At the
Robinson  Plant,  an inspection  was completed in April 2001 and no  penetration
nozzle  cracking  was  identified  and there was no  degradation  of the reactor
vessel head. At the Harris Plant,  sufficient  inspections were completed during
the last refueling  outage in the fourth quarter of 2001 to conclude there is no
degradation  of the reactor  vessel head.  The Company's  Brunswick  Plant has a
different design and is not affected by the issue.

On August 9,  2002,  the NRC issued an  additional  bulletin  dealing  with head
leakage due to cracks near the control rod nozzles.  The NRC has asked licensees
to commit to high  inspection  standards to ensure the more  susceptible  plants
have no cracks.  The  Robinson  Plant is in this  category  and had a  refueling
outage in October  2002.  The  Company  completed  a series of  examinations  in
October 2002 of the entire reactor pressure vessel head and found no indications

                                       18

<PAGE>

of control rod drive  mechanism  cracking  and no  corrosion of the head itself.
During the outage, a boric acid leakage walkdown of the reactor coolant pressure
boundary  was also  completed  and no corrosion  was found.  The Harris Plant is
ranked in the lowest susceptibility classification and the Company does not plan
further inspections until its next regularly scheduled outage in spring of 2003.

In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated  penetration nozzles at PWRs.
The Company has  responded  to the Order,  stating  that the Company  intends to
comply with the provisions of the Order. No adverse impact is anticipated.

Security

On February 25, 2002,  the NRC issued an order  requiring  interim  compensatory
measures with regard to security at nuclear plants.  This order  formalized many
of  the  security  enhancements  made  at the  Company's  nuclear  plants  since
September 2001. This order includes additional restrictions on access, increased
security  presence  and  closer  coordination  with the  Company's  partners  in
intelligence,  military,  law enforcement and emergency response at the federal,
state  and  local  levels.   The  Company  completed  the  requirements  by  the
established deadlines. The NRC inspections for compliance are underway.

In addition, in January 2003, the NRC issued a final order with regard to access
control.  This order  requires the Company to enhance its current access control
program  by  January  7,  2004.  The  Company  expects  that  it will be in full
compliance with the order by the established deadline.

As the NRC, other  governmental  entities and the industry  continue to consider
security  issues,  it is possible that more  extensive  security  plans could be
required.

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.  CP&L will continue to maximize the use of spent fuel
storage  capability  within its own  facilities  for as long as  feasible.  With
certain  modifications and additional  approval by the NRC, CP&L's spent nuclear
fuel storage  facilities  will be sufficient to provide  storage space for spent
fuel generated on CP&L's system through the expiration of the current  operating
licenses for all of CP&L's nuclear  generating units.  Subsequent to or prior to
the expiration of these licenses, dry storage may be necessary.

See PART II,  ITEM 8,  Note 24 to the  Progress  Energy  consolidated  financial
statements  and  Note 18 to the CP&L  consolidated  financial  statements  for a
discussion of CP&L's contract with the U.S. Department of Energy (DOE) for spent
nuclear waste.

Decommissioning

In CP&L'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  approved by the FERC.  See PART II,  ITEM 8, Note 1H to the  Progress
Energy  consolidated  financial  statements and Note 1G to the CP&L consolidated
financial statements for a discussion of CP&L's nuclear decommissioning costs.

Enrichment Facilities Decontamination

CP&L filed an action  against the United  States in the U.S.  Court of Claims on
March 21,  1997,  challenging  certain  retroactive  assessments  imposed by the
federal   government   on  domestic   nuclear   power   companies  to  fund  the
decommissioning  and  decontamination  of the  government's  uranium  enrichment
facilities.  The  government is collecting  this  assessment on an annual basis,
which is  levied  upon all  domestic  utilities  that  had  enrichment  services
contracts with the government.  Collection of the special  assessments  began in
1992 and is scheduled to continue for a fifteen-year  period.  A number of other
utilities filed similar actions against the government.

The Claims Court issued a decision granting the government's  motion for summary
judgment on all counts.  The Claims Court  decision was appealed to the Court of

                                       19

<PAGE>

Appeals for the Federal Circuit on December 26, 2000. The Federal Circuit stayed
consideration  of the case pending a decision by the Supreme Court on a petition
for writ of certiorari  that was filed by  Commonwealth  Edison et. al. in their
case against the  government.  The Supreme  Court  refused to accept the case in
favor of the  Government.  Based on a joint  motion,  CP&L's  appeal in the U.S.
Court of Appeals has been dismissed with prejudice.

ENVIRONMENTAL MATTERS

There are 12 former MGP sites and 14 other  active waste sites  associated  with
CP&L that have  required  or are  anticipated  to require  investigation  and/or
remediation  costs. CP&L received insurance proceeds to address costs associated
with  environmental  liabilities  related to its involvement with MGP sites. All
eligible  expenses  related to these waste costs are charged  against a specific
fund containing  these  proceeds.  As of December 31, 2002,  approximately  $8.0
million remains in this  centralized fund with a related accrual of $8.0 million
recorded for the associated expenses of environmental issues. As CP&L's share of
costs for  investigating  and remediating these sites becomes known, the fund is
assessed to determine if  additional  accruals  will be required.  CP&L does not
believe  that it can  provide  an  estimate  of the  reasonably  possible  total
remediation  costs beyond what remains in the environmental  insurance  recovery
fund.  This  is due  to the  fact  that  the  sites  are  at  different  stages:
investigation has not begun at 15 sites, investigation has begun but remediation
cannot be estimated at seven sites and four sites have begun  remediation.  CP&L
measures its liability for these sites based on available evidence including its
experience in investigating and remediating  environmentally impaired sites. The
process often involves assessing and developing  cost-sharing  arrangements with
other  potentially  responsible  parties (PRPs).  Once the  centralized  fund is
depleted,  CP&L will accrue  costs for the sites to the extent its  liability is
probable  and the costs can be  reasonably  estimated.  Presently,  CP&L  cannot
currently  determine the total costs that may be incurred in connection with the
remediation of all sites.  According to current information,  these future costs
at the CP&L sites are not  expected to be material  to the  Company's  financial
condition or results of operations.

ELECTRIC - FLORIDA POWER

GENERAL

Florida Power was  incorporated  in Florida in 1899, and is an operating  public
utility engaged in the generation, purchase, transmission, distribution and sale
of  electricity.  At  December  31,  2002,  Florida  Power  had a  total  summer
generating  capacity (including  jointly-owned  capacity) of approximately 8,024
MW.

Florida Power provided electric service during 2002 to an average of 1.5 million
customers in west central Florida.  Its service area covers approximately 20,000
square miles and includes the densely populated areas around Orlando, as well as
the cities of St.  Petersburg and  Clearwater.  Florida Power is  interconnected
with 20 municipal and nine rural electric cooperative  systems.  Major wholesale
power sales customers  include  Seminole  Electric  Cooperative,  Inc.,  Florida
Municipal  Power  Agency,  Florida  Power & Light  Company  and  Tampa  Electric
Company.  Florida Power is subject to the rules and  regulations of the FERC and
the Florida Public Service Commission (FPSC).

BILLED ELECTRIC REVENUES

Florida  Power's  electric  revenues billed by customer class for the last three
years, is shown as a percentage of total Florida Power electric  revenues in the
table below:

                            BILLED ELECTRIC REVENUES

       Revenue Class             2002           2001           2000(a)
       -------------             ----           ----           -------
       Residential                55%            54%             53%
       Commercial                 24%            24%             24%
       Industrial                  7%             7%              8%
       Others                      6%             6%              5%
       Wholesale (b)               8%             9%             10%

     (a)  These figures reflect Florida Power's billed electric revenues for the
          full year ended December 31, 2000,  which is generally  representative
          of the period Progress Energy owned Florida Power.
     (b)  These revenues are managed by the Progress  Ventures segment on behalf
          of Florida Power.

                                       20

<PAGE>

Important  industries in Florida Power's territory include phosphate rock mining
and processing,  electronics design and manufacturing, and citrus and other food
processing.  Other  important  commercial  activities are tourism,  health care,
construction and agriculture.

FUEL AND PURCHASED POWER

General

Florida Power's consumption of various types of fuel depends on several factors,
the most important of which are the demand for  electricity  by Florida  Power's
customers,  the availability of various  generating  units, the availability and
cost of fuel and the  requirements  of federal  and state  regulatory  agencies.
Florida  Power's  energy  mix for the  last  three  years  is  presented  in the
following table:

                             ENERGY MIX PERCENTAGES

       Fuel Type                 2002           2001           2000 (a)
       ---------                 ----           ----           --------
       Coal (b)                   33%            33%             34%
       Oil                        16%            16%             15%
       Nuclear                    15%            15%             15%
       Gas                        15%            14%             14%
       Purchased power            21%            22%             22%

     (a)  These figures  reflect  Florida Power's energy mix percentages for the
          full year ended December 31, 2000,  which is generally  representative
          of the period Progress Energy owned Florida Power.
     (b)  Amounts  include  synthetic  fuel from  unrelated  third  parties  and
          petroleum coke.

Florida Power is generally  permitted to pass the cost of  recoverable  fuel and
purchased  power to its customers  through fuel adjustment  clauses.  The future
prices for and  availability of various fuels discussed in this report cannot be
predicted with complete certainty. However, Florida Power believes that its fuel
supply  contracts,  as described below, will be adequate to meet its fuel supply
needs.

Florida Power's average fuel costs per million Btu for the last three years were
as follows:

                                AVERAGE FUEL COST
                                (per million Btu)

                                 2002           2001          2000(a)
                               ------         ------          -------
       Coal (b)                $ 2.43         $ 2.16          $ 1.89
       Oil                       3.77           3.81            4.15
       Nuclear                   0.46           0.47            0.47
       Gas                       4.06           4.52            4.32
       Weighted average          2.60           2.59            2.46

     (a)  These figures  reflect  Florida Power's average fuel cost for the year
          ended  December  31,  2000,  which  is  representative  of the  period
          Progress Energy owned Florida Power.
     (b)  Amounts  include  synthetic  fuel from  unrelated  third  parties  and
          petroleum coke.

Changes  in the unit price for coal,  oil and gas are due to market  conditions.
Since these costs are primarily  recovered through recovery clauses  established
by regulators, fluctuations do not materially affect net income.

Coal

Florida Power anticipates a combined requirement of approximately 5.7 million to
6.1  million  tons of coal  and  synthetic  fuel in  2003.  Most of the  coal is
expected to be supplied from the  Appalachian  coal fields of the United States.
Approximately two-thirds of the fuel is expected to be delivered by rail and the
remainder by barge. All of this fuel is supplied by Progress Fuels, a subsidiary
of Progress  Energy,  pursuant to contracts  between  Florida Power and Progress
Fuels.

For 2003,  Progress Fuels has medium-term  and long-term  contracts with various
sources for approximately  100% of the burn requirements of Florida Power's coal
units.  These  contracts have price  adjustment  provisions and have  expiration
dates ranging from 2003 to 2005.  All the coal to be purchased for Florida Power
is considered to be low sulfur coal by industry standards.

                                       21

<PAGE>

Oil and Gas

Oil is  purchased  under term  contracts  and in the spot  market  from  several
suppliers. The majority of the cost of Florida Power's oil and gas is determined
by market  prices as  reported  in  certain  industry  publications.  Management
believes  that  Florida  Power has access to an  adequate  supply of oil for the
reasonably  foreseeable  future.  Florida Power believes that the threat of or a
war  against  Iraq could  negatively  impact the price of oil.  Florida  Power's
natural  gas supply  and  transportation  is  purchased  under  firm  supply and
transportation contracts and in the spot market from numerous suppliers. Florida
Power also uses interruptible transportation contracts on certain occasions when
available. Florida Power believes that existing contracts for oil are sufficient
to cover its  requirements  if natural gas is  unavailable  during  certain time
periods.

Nuclear

Nuclear fuel is processed through four distinct stages.  Stages I and II involve
the mining and milling of the natural  uranium ore to produce a concentrate  and
the  conversion of this uranium  oxide  concentrate  into uranium  hexafluoride.
Stages III and IV entail the  enrichment  of the  uranium  hexafluoride  and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

Florida Power has sufficient  uranium,  conversion,  enrichment and  fabrication
contracts to meet its near-term nuclear fuel requirements  needs.  Florida Power
expects to contract  for all of its future  long-term  uranium,  conversion  and
enrichment service needs with contract durations ranging from five to ten years.
Although  Florida Power cannot  predict the future  availability  of uranium and
nuclear  fuel  services,  Florida  Power  does  not  currently  expect  to  have
difficulty obtaining uranium oxide concentrate or the services necessary for its
conversion, enrichment and fabrication into nuclear fuel.

Purchased Power

Florida Power, along with other Florida  utilities,  buys and sells power in the
wholesale  market on a short-term and long-term  basis. As of December 31, 2002,
Florida  Power had a variety of purchase  power  agreements  for the purchase of
approximately  1,304 MW of firm power.  These  agreements  include (1) long-term
contracts  for the  purchase  of about  473 MW of  purchased  power  with  other
investor-owned  utilities,  including a contract  with The Southern  Company for
approximately  413 MW, and (2)  approximately  831 MW of capacity under contract
with certain qualifying  facilities (QFs). The capacity currently available from
QFs represents about 10% of Florida Power's total installed system capacity.

COMPETITION

Electric Industry Restructuring

Florida  Power  continues  to  monitor   progress  toward  a  more   competitive
environment and has actively  participated in regulatory reform deliberations in
Florida.  Movement toward deregulation in this state has been affected by recent
developments  related to deregulation of the electric industry in California and
other states.

On December 11, 2001, the Florida 2020 Study Commission  issued its final report
to the Florida  Legislature  regarding  possible  changes to the  regulation  of
electric utilities in Florida.  The Florida  legislature did not take any action
on the final report during the 2001 or 2002 session.

In response  to a  legislative  directive,  the FPSC and the FDEP  submitted  by
February 2003 a joint report on renewable electric  generating  technologies for
Florida.  The  report  assessed  the  feasibility  and  potential  magnitude  of
renewable  electric  capacity for Florida,  and summarized the mechanisms  other
states have adopted to encourage  renewable  energy.  The report did not contain
any  policy  recommendations.   The  Company  cannot  anticipate  when,  or  if,
restructuring  legislation  will be enacted or if the  Company  would be able to
support it in its final form.

Regional Transmission Organizations

As a result of Order  2000,  Florida  Power,  along with  Florida  Power & Light
Company  and Tampa  Electric  Company  (the  Applicants)  filed with the FERC in
October 2000 an application  for approval of a GridFlorida  RTO. The GridFlorida
proposal is pending  before both the FERC and the FPSC.  The FERC  provisionally
approved the structure and governance of GridFlorida. In December 2001, the FPSC
found the Applicants were prudent in proactively forming GridFlorida but ordered
the Applicants to modify the proposal in several material respects,  including a
change in structure to a not-for-profit  Independent  System Operator (ISO). The
Commission's   most  recent  order  in  September  2002  ordered  further  state
proceedings.  The issues to be addressed as modifications  include,  but are not
limited  to 1)  pricing/rate  structure;  2)  elimination  of the  pancaking  of
revenues;  3) cost recovery of incremental  costs; 4) demarcation  dates for new

                                       22

<PAGE>

facilities  and long-term  transmission  contracts;  and 6) market  design.  The
Florida  Office of Public  Counsel  appealed  the  September  2002  order to the
Florida  Supreme Court and on October 28, 2002, the FPSC abated its  proceedings
pending the outcome of the appeal. It is unknown what the outcome of this appeal
will be at this time.  It is  unknown  when the FERC or the FPSC will take final
action  with regard to the status of  GridFlorida  or what the impact of further
proceedings will have on the Company's earnings, revenues or pricing.

See PART II, ITEM 7, "Other  Matters," for a discussion of current  developments
of GridFlorida RTO.

Standard Market Design

On July 31, 2002,  the FERC issued its Notice of Proposed  Rulemaking  in Docket
No. RM01-12-000 Remedying Undue Discrimination  through Open Access Transmission
Service and Standard  Electricity  Market Design (SMD NOPR).  The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission owning utilities transfer control of their transmission  facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC-regulated  transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities  be required to meet  minimum  criteria  for  generating  reserves.  If
adopted as proposed,  the rules set forth in the SMD NOPR would materially alter
the manner in which  transmission and generation  services are provided and paid
for. Florida Power filed comments on November 15, 2002 and supplemental comments
on January 10, 2003. On January 15, 2003,  the FERC  announced the issuance of a
White Paper on SMD NOPR to be released  in April  2003.  Florida  Power plans to
file comments on the White Paper. The FERC has also indicated that it expects to
issue final rules during the summer of 2003.

Merchant Plants

There has been no change in the statutory  framework  for siting new  generation
since the Florida Supreme Court's  decision in Tampa Electric Company v. Garcia,
767 So.2d 428 (Fla.  2000) in April 2000.  The Court  reversed a decision of the
FPSC and held that under  Florida's Power Plant Siting Act, an applicant for any
new generation  over 75 MW that includes a steam  generating  facility must be a
load-serving  utility  or the  output of the  proposed  plant must be under firm
contract to a  load-serving  utility.  Thus,  site  certification  for  merchant
generation for large,  non-peaking capacity cannot be independently  undertaken.
At the present time there are no pending legislative proposals for change.

Franchise Agreements

Florida  Power holds  franchises  with  varying  expiration  dates in 104 of the
municipalities  in which it  distributes  electric  energy.  Florida  Power also
serves within a number of  municipalities  and in all its  unincorporated  areas
without  franchise  agreements.  The general  effect of these  franchises  is to
provide  for the  manner  in  which  Florida  Power  occupies  rights-of-way  in
incorporated areas of municipalities for the purpose of constructing,  operating
and maintaining an energy transmission and distribution system.

Approximately  36% of Florida Power's total utility  revenues for 2002 were from
the incorporated areas of the 104 municipalities  that had franchise  ordinances
during the year.  Since 2000,  Florida Power has renewed 27 expiring  franchises
and reached  agreement on a franchise with a city that did not previously have a
franchise. Franchises with eight municipalities have expired without renewal.

All but 26 of the  existing  franchises  cover a  30-year  period  from the date
enacted.  The  exceptions  are 22  franchises,  each with a term of 10 years and
expiring  between 2005 and 2012; two franchises each with a term of 15 years and
expiring in 2017; one 30-year franchise that was extended in 2000 for five years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 104 franchises,  39 expire between January 1, 2003 and December 31, 2012 and
65 expire between January 1, 2013 and December 31, 2031.

Ongoing negotiations are taking place with the municipalities to reach agreement
on franchise terms and to enact new franchise  ordinances.  See PART II, ITEM 8,
Note  24  to  the  Progress  Energy  consolidated  financial  statements  for  a
discussion of Florida Power's franchise litigation.

Stranded Costs

An important  issue  encompassed  by industry  restructuring  is the recovery of
"stranded  costs."  Stranded costs  primarily  include the generation  assets of

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utilities  whose  value in a  competitive  marketplace  would be less than their
current book value, as well as above-market  purchased power commitments to QFs.
Thus far, all states that have passed  restructuring  legislation  have provided
for the opportunity to recover a substantial portion of stranded costs.

Assessing  the  amount  of  stranded  costs  for  a  utility   requires  various
assumptions  about  future  market  conditions,  including  the future  price of
electricity. For Florida Power, the single largest stranded cost exposure is its
commitment to QFs. Florida Power has taken a proactive approach to this industry
issue.  Since 1996, Florida Power has been seeking ways to address the impact of
escalating  payments from contracts it was obligated to sign under provisions of
Public Utility Regulatory Policies Act of 1978 (PURPA).

REGULATORY MATTERS

General

Florida Power is subject to the  jurisdiction of the FPSC with respect to, among
other  things,  retail rates and issuance of  securities.  In addition,  Florida
Power is subject to  regulation  by the FERC with  respect to  transmission  and
sales of wholesale power,  accounting and certain other matters.  The underlying
concept of utility ratemaking is to set rates at a level that allows the utility
to collect  revenues  equal to its cost of  providing  service plus a reasonable
rate of return on its  equity.  Increased  competition  as a result of  industry
restructuring may affect the ratemaking process.

Electric Retail Rates

The FPSC  authorizes  retail "base rates" that are designed to provide a utility
with the  opportunity  to earn a specific  rate of return on its "rate base," or
average  investment  in utility  plant.  These  rates are  intended to cover all
reasonable and prudent expenses of utility  operations and to provide  investors
with a fair rate of return.

On March 27,  2002,  the parties in Florida  Power's  rate case  entered  into a
Stipulation  and  Settlement  Agreement (the  Agreement)  related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The Agreement
is generally effective from May 1, 2002 through December 31, 2005. The Agreement
eliminates the authorized Return on Equity (ROE) range normally used by the FPSC
for the purpose of addressing earning levels; provided, however, that if Florida
Power's base rate earnings fall below a 10% return on equity,  Florida Power may
petition the FPSC to amend its base rates.

The Agreement provides that Florida Power will reduce its retail rates by 9.25%;
resulting in a reduction of retail  revenues from the sale of  electricity by an
annual  amount of $125 million.  The Agreement  also provides that Florida Power
will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and
thereafter until  terminated by the FPSC, that  establishes  annual revenue caps
and sharing thresholds. The Plan provides that retail base rate revenues between
the  sharing  thresholds  and the caps will be  divided  into two shares - a 1/3
share to be  retained  by Florida  Power's  shareholders,  and a 2/3 share to be
refunded to Florida Power's retail customers;  provided,  however,  that for the
year 2002  only,  the  refund to  customers  will be limited to 67.1% of the 2/3
customer share.  The retail base rate revenue sharing  threshold amount for 2002
was $1.296 billion and will increase $37 million each year thereafter.  The Plan
also  provides  that all retail  base rate  revenues  above the retail base rate
revenue caps established for each year will be refunded 100% to retail customers
on an annual basis.  For 2002,  the refund to customers will be limited to 67.1%
of the retail  base rate  revenues  that  exceed the 2002 cap.  The retail  base
revenue cap for 2002 was $1.356  billion and will increase $37 million each year
thereafter.  As of  December  31,  2002,  $4.7  million  was accrued and will be
refunded to  customers in March 2003.  On February 24, 2003,  the parties to the
Agreement  filed a  motion  seeking  an  order  from  the  FPSC to  enforce  the
Agreement.  In this motion,  the parties dispute Florida Power's  calculation of
retail  revenue  subject  to  refund  and  contend  that the  refund  should  be
approximately  $23 million.  Florida  Power  cannot  predict the outcome of this
matter.

The Agreement also provides that  beginning with the in-service  date of Florida
Power's Hines Unit 2 and  continuing  through  December 31, 2005,  Florida Power
will be allowed to recover  through  the fuel cost  recovery  clause a return on
average investment and depreciation expense for Hines Unit 2, to the extent such
costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Hines Unit 2 is a 516 MW  combined-cycle  unit under  construction and currently
scheduled for completion in late 2003.

Additionally,   the  Agreement  provides  that  Florida  Power  would  effect  a
mid-course correction of its fuel cost recovery clause to reduce the fuel factor
by $50  million  for 2002.  The fuel cost  recovery  clause  will  operate as it
normally  does,  including,  but  not  limited  to,  any  additional  mid-course
adjustments  that may become necessary and the calculation of true-ups to actual
fuel clause expenses.

Florida Power will suspend accruals on its reserves for nuclear  decommissioning
and fossil  dismantlement  through  December  31, 2005.  Additionally,  for each
calendar  year  during the term of the  Agreement,  Florida  Power will record a
$62.5 million depreciation expense reduction,  and may, at its option, record up
to an equal annual amount as an offsetting accelerated  depreciation expense. In

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<PAGE>

addition,  Florida Power is  authorized,  at its  discretion,  to accelerate the
amortization of certain regulatory assets over the term of the Agreement.  There
was no accelerated  depreciation or amortization  expense  recorded for the year
ended December 31, 2002.

Under  the  terms  of the  Agreement,  Florida  Power  agreed  to  continue  the
implementation  of its four-year  Commitment to Excellence  Reliability Plan and
expects to achieve a 20%  improvement in its annual System Average  Interruption
Duration Index by no later than 2004. If this improvement  level is not achieved
for  calendar  years 2004 or 2005,  Florida  Power  will  provide a refund of $3
million  for each year the  level is not  achieved  to 10% of its  total  retail
customers served by its worst performing distribution feeder lines.

Per the Agreement, Florida Power was required to refund to customers $35 million
of revenues  collected during the interim period of March 13, 2001 through April
30, 2002.  This one-time  retroactive  revenue  refund was recorded in the first
quarter of 2002 and was returned to retail customers over an eight-month  period
ended December 31, 2002.

Fuel and Other Cost Recovery

Florida Power's  operating costs not covered by the utility's base rates include
fuel,   purchased   power  and  energy   conservation   expenses   and  specific
environmental  costs. The state commission allows electric  utilities to recover
certain of these costs through various cost recovery clauses,  to the extent the
respective  commission  determines  in an annual  hearing  that  such  costs are
prudent. In addition,  in December 2002, the FPSC approved an Environmental Cost
Recovery  Clause which will permit the Company to recover the costs of specified
environmental  projects to the extent these  expenses are found to be prudent in
an annual  hearing  and not  otherwise  included  in base  rates.  Costs will be
recovered  through this recovery clause in the same manner as the other existing
clause mechanisms.

The state  commission's  determination  results in the  addition of a rider to a
utility's  base rates to reflect the  approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method  allowed  for  recovery,  changes  from year to year have no material
impact on operating results.

NUCLEAR MATTERS

Florida Power has one nuclear generating plant,  Crystal River Unit No. 3 (CR3),
which is subject to  regulation by the NRC. The NRC's  jurisdiction  encompasses
broad  supervisory and regulatory  powers over the construction and operation of
nuclear   reactors,   including   matters  of  health  and   safety,   antitrust
considerations and environmental impact.  Florida Power has a license to operate
the nuclear plant through December 3, 2016.  Florida Power currently has a 91.8%
ownership  interest in CR3. On February 20, 2003, Florida Power notified the NRC
of its intent to submit an  application to extend the plant license in the first
quarter of 2009.

In late 2002, CR3 received a license  amendment  authorizing a small power level
increase.  The power level  increase of  approximately  8 MW was  implemented in
February 2003.

On March 18, 2002,  the NRC sent a bulletin to companies  that hold licenses for
PWRs requiring  information  on the  structural  integrity of the reactor vessel
head and a basis for  concluding  that the vessel head will  continue to perform
its function as a coolant  pressure  boundary.  The Company  filed  responses as
required.  Inspections  of the vessel heads at the Company's PWR plant have been
performed during previous outages. In October 2001, at CR3, one nozzle was found
to have a crack and was repaired;  however, no degradation of the reactor vessel
head was identified.  Current plans are to replace the vessel head at CR3 during
its next regularly scheduled refueling outage in the fall of 2003.

On August 9,  2002,  the NRC issued an  additional  bulletin  dealing  with head
leakage due to cracks near the control rod nozzles.  The NRC has asked licensees
to commit to high  inspection  standards to ensure the more  susceptible  plants
have no cracks.  For CR3,  the Company has  responded  to the NRC that  previous
inspections  are  sufficient  until the reactor  head is replaced in the fall of
2003.

In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated  penetration nozzles at PWRs.
The Company has  responded  to the Order,  stating  that the Company  intends to
comply with the provisions of the Order. No adverse impact is anticipated.

Enrichment Facilities Decontamination

Florida  Power filed an action  against the United  States in the U.S.  Court of
Claims on November 1, 1996 challenging certain  retroactive  assessments imposed
by the  federal  government  on domestic  nuclear  power  companies  to fund the
decommissioning  and  decontamination  of the  government's  uranium  enrichment
facilities.  The  government is collecting  this  assessment on an annual basis,
which is  levied  upon all  domestic  utilities  that  had  enrichment  services

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<PAGE>

contracts with the government.  Collection of the special  assessments  began in
1992 and is  scheduled  to  continue  for a  15-year  period.  A number of other
utilities have filed similar actions against the government.

The Claims Court issued a decision  granting the  government's  summary judgment
motion.  That decision was appealed to the U.S. Court of Appeals for the Federal
Circuit,  which stayed its  consideration  of the case pending a decision by the
U.S.  Supreme  Court on a  petition  for writ of  certiorari  that was  filed by
Commonwealth  Edison et al. in their case against the  government.  This Supreme
Court refused to accept that case for review,  effectively resolving the case in
favor of the  government.  Based on a joint motion,  Florida  Power's appeal has
been dismissed with prejudice.

ENVIRONMENTAL MATTERS

There are two former MGP sites and 11 other active waste sites or  categories of
sites  associated  with Florida Power that have required or are  anticipated  to
require  investigation  and/or  remediation  costs.  As of December 31, 2002 and
2001,  Florida Power has accrued  approximately  $10.9 million and $8.5 million,
respectively,  for  probable  and  reasonably  estimable  costs at these  sites.
Florida Power does not believe that it can provide an estimate of the reasonably
possible total remediation costs beyond what it has currently accrued.  In 2002,
Florida  Power filed a petition  for recovery of  approximately  $4.0 million in
environmental  costs through the  Environmental  Cost  Recovery  Clause with the
FPSC.  Florida  Power was  successful  with this filing and will  recover  costs
through rates for investigation and remediation associated with transmission and
distribution  substations  and  transformers.  As more activity  occurs at these
sites, Florida Power will assess the need to adjust the accruals. These accruals
have  been  recorded  on an  undiscounted  basis.  Florida  Power  measures  its
liability for these sites based on available  evidence  including its experience
in investigating  and remediating  environmentally  impaired sites. This process
often includes  assessing and developing  cost-sharing  arrangements  with other
potentially responsible parties.

PROGRESS VENTURES

GENERAL

The Progress  Ventures  business  segment was created in 2000 to manage Progress
Energy's  wholesale energy marketing and trading,  non-regulated  generation and
fuel properties,  as well as an ocean barge  partnership.  The operations of the
Progress  Ventures  business segment can be broken down into three key areas: 1)
fuel extraction,  manufacturing and delivery;  2) merchant generation ownership;
and 3) energy marketing and trading.

FUEL EXTRACTION, MANUFACTURING AND DELIVERY

The Progress  Ventures  business  segment owns an array of assets that  produce,
transport and deliver fuel and provide related services for the open market. The
Progress Ventures business segment has subsidiaries that produce natural gas and
oil products,  mine coal and others that produce  synthetic  coal-based fuel, an
alternative fuel product made from waste coal and coal byproducts.  This product
has been  classified as a synthetic fuel within the meaning of Section 29 of the
Internal  Revenue  Code.  Sales of  synthetic  fuel  therefore  qualify  for tax
credits.  See PART II, ITEM 7, "Other Matters" for a discussion of the synthetic
fuel tax credits.

The current  combined  assets of Progress  Ventures  which are  involved in fuel
extraction, manufacturing and delivery include:

     o    Three coal-mining complexes,  expected to produce about 3 million tons
          per year;
     o    Seven synthetic fuel plants capable of producing up to 18 million tons
          per year;
     o    Natural gas  properties  in Colorado,  Texas and  Louisiana  producing
          about 21 net billion cubic feet per year;
     o    Six  terminals  on the Ohio  River  and its  tributaries,  part of the
          trucking, rail and barge network for coal delivery;
     o    Majority-ownership  in a barge  partnership  that moves coal  products
          from the mouth of the Mississippi  River to the Crystal River facility
          in Florida.

Progress  Fuels,  a business  unit of the Progress  Ventures  segment,  acquired
approximately   162  natural   gas-producing   wells  with  proven  reserves  of
approximately  195 billion cubic feet from Republic  Energy,  Inc. and two other
privately-owned companies during the first quarter of 2003.

                                       26
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NONREGULATED GENERATION OWNERSHIP

Nonregulated  generation  represents  power plants whose capacity and energy are
sold  on the  wholesale  market  outside  the  realm  of  retail  regulation.  A
cornerstone  of  Progress  Ventures'  business  plan  is to own a  portfolio  of
approximately  3,100 MW of merchant  generation  capacity by 2003.  Much of this
portfolio  is being  built by  Progress  Ventures.  The  Company  has  contracts
representing  63%, 69% and 25% of planned  production  capacity for 2003 through
2005, respectively.

On March 20, 2003, PVI entered into a definitive  agreement with Williams Energy
Marketing  and  Trading,  a  subsidiary  of  Williams,  to  acquire a  long-term
full-requirements power supply agreement with Jackson Electric Membership Corp.,
located in Jefferson, Georgia. The agreement calls for a $188 million payment to
Williams in exchange for assignment of the Jackson supply  agreement.  The power
supply  agreement  runs  through  2015 and includes the use of 640 MW of Georgia
system  generation  comprised of nuclear,  coal,  gas and  pumped-storage  hydro
resources. Progress Energy expects to supplement the acquired resources with its
own  intermediate  and peaking assets in Georgia to serve  Jackson's  forecasted
1,100 MW peak demand in 2005  growing to a 1,700 MW demand by 2015.  The sale is
expected to close in the second  quarter of 2003,  subject to customary  closing
conditions.

Progress  Ventures had  approximately  1,554 MW of  nonregulated  generation  in
commercial operation as of December 31, 2002.  Construction of generating assets
at three  locations will increase this to  approximately  3,100 MW by the end of
2003.  See PART I, ITEM 2,  "Properties,"  for  additional  information on these
planned additions.

ENERGY MARKETING AND TRADING

Within this business  function,  the energy  produced by the merchant  plants as
well as some energy  produced by the utilities is sold under term  contracts and
in the  spot  market.  This  area is  divided  into two  departments:  Regulated
Wholesale Marketing and Trading and Competitive Marketing and Trading. Regulated
Wholesale  Marketing  and Trading  manages  approximately  5,000 MW of wholesale
power  contracts  that  primarily  include  those  for CP&L and  Florida  Power.
Competitive  Marketing  and Trading  markets the  nonregulated  plants not under
contract into the nonregulated  market and engages in limited  financial trading
activities.

In addition to power contracts,  this business area also purchases fuel for both
utility and merchant  generation,  and trades other  sources of energy,  such as
natural gas and oil. Progress Ventures also uses financial instruments to manage
the risks associated with fluctuating commodity prices and increase the value of
the Company's power generation assets.

COMPETITION

Progress  Ventures  does  not  operate  in the  same  environment  as  regulated
utilities.  It  operates  specifically  in the  wholesale  market,  which  means
competition is its primary driver. Progress Ventures' synthetic fuel operations,
coal  operations  and merchant  generation  plants compete in the eastern United
States utility and industrial coal markets.  Factors contributing to the success
in these markets include a competitive  cost structure and strategic  locations.
See PART II, ITEM 7, "Other  Matters," for a discussion of risks associated with
synthetic fuel tax credits. There are, however,  numerous competitors in each of
these markets, although no one competitor is dominant in any industry.

ENVIRONMENTAL MATTERS

Progress  Ventures'  environmental  matters  primarily  relate  to air and water
quality matters.  However,  certain historical waste sites exist which are being
addressed  voluntarily.  Environmental  costs cannot be determined.  The Company
does not expect future costs to be material to Progress Ventures.

RAIL SERVICES

The largest  component of the Rail Services  business segment is led by Progress
Rail Services Corporation  (Progress Rail).  Progress Rail is one of the largest
integrated and diversified suppliers of railroad and transit system products and
services in North America and is  headquartered  in Albertville,  Alabama.  Rail
Services'  principal  business  functions include the Mechanical Group, Rail and
Trackwork Group, and Recycling Group.

The  Mechanical  Group is  primarily  focused  on  railroad  rolling  stock that
includes freight cars, transit cars and locomotives,  the repair and maintenance
of these units, and the  manufacturing or reconditioning of major components for
these  units.  The Rail and  Trackwork  Group  focuses  on rail and other  track
components, the infrastructure which supports the operation of rolling stock, as
well as the  equipment  used in  maintaining  the  railroad  infrastructure  and
right-of-way. The Recycling Group supports the Mechanical and Rail and Trackwork
Groups through its reclamation of  reconditionable  material.  In addition,  the
Recycling Group is a major supplier of recyclable  scrap metal to North American
steel mills and foundries through its processing  locations as well as its scrap
brokerage operations.

Rail Services' key railroad industry  customers are Class 1 railroads,  regional
and shortline railroads, major North American transit systems, major railcar and
locomotive builders,  and major railcar lessors. The U.S. operations are located
in 26 states and include further  geographic  coverage through mobile crews on a
selected  basis.  This coverage  allows for Rail  Services'  customer base to be
dispersed throughout the U.S., Canada and Mexico.

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During 2003,  the Company  intends to sell the assets of Railcar Ltd., a leasing
subsidiary,  included in the Rail Services segment,  and has therefore  reported
these assets as assets held for sale.  On March 12, 2003,  the Company  signed a
letter of intent to sell Railcar Ltd. to The Andersons, Inc. The proceeds of the
sale will be used to pay off Railcar Ltd. lease obligations.  The transaction is
still subject to various closing conditions including  financing,  due diligence
and the completion of a definitive purchase agreement.

ENVIRONMENTAL MATTERS

Progress Rail is voluntarily  addressing  certain  historical  waste sites.  The
Company does not anticipate future costs to be material to Progress Rail.

OTHER

GENERAL

The Other segment  primarily  includes the  operations  of Progress  Telecom and
Caronet,  Inc.  (Caronet).  The  operations  of Caronet  are managed by Progress
Telecom.  NCNG  has  been  excluded  from  the  Other  segment  because  of  its
classification  as a  discontinued  operation.  This segment also includes other
nonregulated operations of CP&L and FPC.

PROGRESS TELECOM AND CARONET

Progress Telecom has data fiber network transport capabilities that stretch from
New York to  Miami,  Florida,  with  gateways  to  Latin  America  and  conducts
primarily a carrier's  carrier  business.  Progress  Telecom  markets  wholesale
fiber-optic-based capacity service in the Eastern United States to long-distance
carriers,  internet service  providers and other  telecommunications  companies.
Progress  Telecom  also  markets  wireless  structure  attachments  to  wireless
communication   companies  and   governmental   entities.   Caronet  serves  the
telecommunications   industry  by   providing   fiber-optic   telecommunications
services.  As of December  31,  2002,  Progress  Telecom  and Caronet  owned and
managed  approximately  8,400 route miles and more than  130,000  fiber miles of
fiber-optic cable.

Progress  Telecom  and  Caronet  compete  with other  providers  of  fiber-optic
telecommunications  services,  including local exchange carriers and competitive
access providers, in the Eastern United States.

Lease revenue for dedicated  transport and data services is generally  billed in
advance on a fixed rate basis and  recognized  over the period the  services are
provided.   Revenues   relating   to  design  and   construction   of   wireless
infrastructure  are recognized upon completion of services (i.e., as the revenue
is earned) for each completed phase of design and construction.

For additional information regarding asset and investment impairments,  see PART
II, ITEM 8, Note 7 to the Progress Energy consolidated financial statements, and
Note 5 to the CP&L consolidated financial statements.

NCNG

General

NCNG transports,  distributes and sells natural gas to over 108,400  residential
customers,  over 14,300 commercial and agricultural customers and 472 industrial
and electric  utility  customers  located in 110 towns and cities,  primarily in
eastern and south central North Carolina. NCNG also sells and transports natural
gas to four municipal gas distribution systems that serve over 55,600 end users.
Natural gas operations are subject to the rules and regulations of the NCUC.

In  2002,  the  Company  approved  the  sale of NCNG  and the  Company's  equity
investment in Eastern  North  Carolina  Natural Gas Company  (ENCNG) to Piedmont
Natural Gas Company,  Inc. As a result of this action,  the operating results of
NCNG were reclassified to discontinued operations for all reportable periods.

                                       28
<PAGE>

Natural Gas Supply

NCNG has long-term firm gas supply  contracts with major  producers and national
natural gas marketers.  During 2002, NCNG purchased 11.9 million dekatherms (dt)
of natural gas under its firm sales contracts with Transcontinental Gas Pipeline
Corporation (Transco). NCNG also purchased 31.1 million dt in the spot market or
under long-term contracts with producers or natural gas marketers. Additionally,
NCNG transported 27.5 million dt of customer-owned  gas in 2002. The outlook for
natural gas supplies in NCNG's service area remains favorable,  and many sources
of gas are available on a firm basis.

Competition

The  natural  gas  industry   continues  to  evolve  into  a  more   competitive
environment.  NCNG has competed  successfully with other forms of energy such as
electricity,  residual fuel oil,  distillate fuel oil,  propane and, to a lesser
extent,  coal.  The  principal  competitive  considerations  have been price and
accessibility.  With the exception of four municipalities that operate municipal
gas  distribution  systems  within  its  service  territory,  NCNG  is the  sole
distributor of natural gas in our franchised service territory.

Currently,  NCNG's residential and commercial customers receive services under a
bundled rate,  which includes  charges for both the cost of gas and its delivery
to the  customer.  Unbundling  of the  services to  commercial  and  residential
customers could increase  competition for commodity sales services,  but not for
the  distribution  of natural gas. Since NCNG does not earn any margin or income
from the commodity sale of natural gas, separating the cost of gas from the cost
of its delivery will not impact the operations. NCNG does not expect the NCUC to
require  further  unbundling in the near future.  NCNG has adopted a policy that
requires that it have a balanced gas supply portfolio that provides  security of
supply at the lowest  reasonable  cost,  as determined by the NCUC in all of the
prior annual prudency reviews.

Franchises

NCNG holds a certificate of public convenience and necessity granted by the NCUC
to provide service to NCNG's current service area.  Under North Carolina law, no
company may  construct or operate  properties  for the sale or  distribution  of
natural gas without such a  certificate,  except that no certificate is required
for  construction  in the ordinary course of business or for  construction  into
territory  contiguous  to that already  occupied by a company and not  receiving
similar service from another utility.

NCNG  has  nonexclusive   franchises  from  72   municipalities  in  which  NCNG
distributes  natural gas. The  expiration  dates of those  franchises  that have
specific  expiration  provisions range from 2004 to 2020.  Franchise  agreements
with the towns of Kinston and  Wilmington  will expire in 2004;  new  agreements
will be presented to the towns in advance of the expiration date. The franchises
are  substantially  uniform  in  nature.  They  contain  no  restrictions  of  a
materially  burdensome nature and are adequate for NCNG's business. In addition,
NCNG serves 36 communities from which no franchises are required.

Regulatory Matters

The NCUC  regulates  NCNG's  rates,  service area,  adequacy of service,  safety
standards, acquisition,  extension and abandonment of facilities, accounting and
sales of securities.  NCNG operates only in North Carolina and is not subject to
federal regulation as a "natural gas company" under the Natural Gas Act.

Retail Rates

On October 27, 1995, the NCUC issued an order that provides for a rate of return
of 10.09%,  but did not state  separately the rate of return on common equity or
the  capital  structure  used  to  calculate  revenue  requirements.  The  order
established several new rate schedules,  including an economic  development rate
to assist in  attracting  new  industry  to  NCNG's  service  area and a rate to
provide  standby,  on-peak gas supply service to industrial and other  customers
whose gas service would otherwise be interrupted.

In conjunction  with CP&L's  acquisition of NCNG on July 15, 1999, NCNG signed a
joint  stipulation  agreement  with the NCUC in which NCNG  agreed to cap margin
rates  for gas sales  and  transportation  services,  with  limited  exceptions,
through November 1, 2003. The Company believes that this agreement will not have
a material adverse effect on the results of operations,  financial  condition or
cash  flows.  In  February  2002,  NCNG filed a general  rate case with the NCUC
requesting  an annual  rate  increase  of $47.6  million.  On May 3, 2002,  NCNG
withdrew the application,  based upon the NCUC Public Staff's and other parties'
interpretation  of the order  approving  the merger of CP&L and NCNG that such a
case was not  permitted  until 2003.  On May 16,  2002,  NCNG filed a request to
increase its margin rates and rebalance  its rates with the NCUC,  requesting an
annual rate increase of $4.1 million to recover costs  associated  with specific
system improvements.  On September 23, 2002, the NCUC issued its order approving

                                       29

<PAGE>

the $4.1 million rate increase. The rate increase was effective October 1, 2002.
NCNG plans to file  another  general  rate case with the NCUC in spring of 2003.
NCNG  anticipates  that new rates, if approved,  will go into effect in November
2003, after the terms of the joint stipulation agreement expire.

Environmental Matters

There  are  five  former  MGP  sites  associated  with  NCNG  that  have  or are
anticipated to have  investigation or remediation costs associated with them. As
of December 31, 2002, NCNG has accrued  approximately  $2.8 million for probable
and reasonably  estimable  remediation costs at these sites. These accruals have
been recorded on an  undiscounted  basis.  NCNG measures its liability for these
sites based on available  evidence including its experience in investigation and
remediation of contaminated  sites, which also involves assessing and developing
cost-sharing  arrangements with other potentially responsible parties. NCNG does
not  believe  it can  provide  an  estimate  of the  reasonably  possible  total
remediation  costs beyond the accrual  because two of the five sites  associated
with  NCNG have not  begun  investigation  activities.  Therefore,  NCNG  cannot
currently  determine the total costs that may be incurred in connection with the
investigation  and/or remediation of all sites. Based upon current  information,
the Company does not expect the future costs at the NCNG sites to be material to
the Company's financial condition or results of operations. On October 16, 2002,
the Company  announced plans to sell NCNG to Piedmont Natural Gas Company,  Inc.
See PART II,  ITEM 8,  Note 3A to the  Progress  Energy  consolidated  financial
statements.  The Company will retain the environmental liability associated with
the five former MGP sites.

OTHER

Expansion Projects

In October 1999, CP&L and the Albemarle Pamlico Economic Development Corporation
(APEC) announced its intention to build an 850-mile, $197.5 million, natural gas
transmission  and distribution  system to 14 unserved  counties in eastern North
Carolina. In furtherance of this project, Progress Energy and APEC formed ENCNG.
Progress  Energy and APEC are joint owners of ENCNG,  which is a public  utility
subject to the rules and regulations of the NCUC.  ENCNG contracted with CP&L to
construct,  operate and maintain both the transmission and distribution systems.
ENCNG  contracted with APEC to provide various  services as well,  including but
not limited to, managing all municipal and county  franchise  issues,  marketing
and economic  development  and ensuring that the new facilities are built in the
most advantageous  locations to promote  development of the economic base in the
region.  In conjunction  with this project,  ENCNG filed a request with the NCUC
for $186 million of a $200 million  state bond package  established  for natural
gas  infrastructure  to pay for the portion of the project that likely could not
be recovered from future gas customers through rates. On June 15, 2000, the NCUC
issued an order awarding ENCNG an exclusive franchise to all 14 counties and, in
a further  order issued on July 12, 2000,  granted  $38.7  million in state bond
funding  for phase one of the  project.  Phase  one,  which will cost a total of
$50.5  million,  extends gas service to six of the 14 counties.  By order issued
June 7, 2001 the NCUC approved  construction  of phases two through seven of the
project  which  addresses  the  remaining  eight  counties and awarded  ENCNG an
additional  $149.6  million  to  finance  the  construction  of  the  facilities
associated with these phases. ENCNG has substantially completed phase one of the
project and has begun  construction of phase two and a portion of phase seven of
the  project  and  expects to  complete  that work in the spring of 2003.  ENCNG
expects to begin  construction of a portion of phase three of the project in the
spring of 2003 and to begin  construction of phases four and five before the end
of 2003 and phase six in early 2004. ENCNG expects to begin  construction of the
remaining  portions  of  phases  three  and  seven in 2004 and to  complete  all
construction  work in early  2005.  ENCNG has also begun  marketing  natural gas
service to prospective  customers in phases one and two and has begun  providing
natural gas service to more than 225 customers in the phase one area.

Progress  Energy  agreed to fund a portion of the  project,  which is  currently
estimated to be approximately $22 million.  On October 16, 2002, Progress Energy
announced  plans to sell its interest in ENCNG to Piedmont  Natural Gas Company,
Inc. Upon closing of the sale,  Progress Energy would have no further obligation
to fund a portion of the project and any funding  obligations  then  outstanding
would transfer to Piedmont  Natural Gas Company,  Inc. See PART II, ITEM 8, Note
3A to the Progress Energy  Financial  Statements.  CP&L's contract to construct,
operate and maintain ENCNG's  transmission and distribution system would also be
assigned to Piedmont upon closing of the sale.

                                       30
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

ELECTRIC UTILITY OPERATING STATISTICS - PROGRESS ENERGY

                                                                               Years Ended December 31
                                                            2002          2001         2000 (d)         1999          1998
                                                         ------------   ----------    -----------    -----------   -----------
Energy supply (millions of kWh)
  Generated - Steam                                           49,734       48,732         31,132         28,260        27,576
              Nuclear                                         30,126       27,301         23,857         22,451        22,014
              Hydro                                              491          245            441            520           790
              Combustion Turbines/Combined Cycle               8,522        6,644          1,337            435           386
  Purchased                                                   14,305       14,469          5,724          5,132         5,675
                                                         ------------   ----------    -----------    -----------   -----------
     Total energy supply (Company share)                     103,178       97,391         62,491         56,798        56,441
  Jointly-owned share (a)                                      5,258        4,886          4,505          4,353         4,349
                                                         ------------   ----------    -----------    -----------   -----------
     Total system energy supply                              108,436      102,277         66,996         61,151        60,790
                                                         ============   ==========    ===========    ===========   ===========
Average fuel cost (per million Btu)
  Fossil                                               $        2.62  $      2.46  $        1.96  $        1.75  $       1.71
  Nuclear fuel                                         $        0.44  $      0.45  $        0.45  $        0.46  $       0.46
  All fuels                                            $        1.84  $      1.77  $        1.30  $        1.16  $       1.14
Energy sales (millions of kWh)
Retail
  Residential                                                 33,993       31,976         15,365         13,348        13,207
  Commercial                                                  23,887       23,033         12,221         11,068        10,646
  Industrial                                                  16,924       17,204         14,762         14,568        14,899
  Other Retail                                                 4,287        4,149          1,626          1,359         1,357
Wholesale                                                     19,204       17,715         15,012         14,526        14,461
Unbilled                                                         276       (1,045)         1,098           (110)          (94)
                                                         ------------   ----------    -----------    -----------   -----------
     Total energy sales                                       98,571       93,032         60,084         54,759        54,476
     Company uses and losses                                   3,604        3,478          2,286          2,039         1,964
                                                         ------------   ----------    -----------    -----------   -----------
     Total energy requirements                               102,175       96,510         62,370         56,798        56,440
                                                         ============   ==========    ===========    ===========   ===========

Electric revenues (in thousands)
  Retail                                               $   5,515,306  $ 5,461,469  $   2,799,422  $   2,530,562  $  2,536,693
  Wholesale                                                  880,583      922,719        664,847        556,079       548,137
  Miscellaneous revenue                                      204,800      172,373         81,425         59,517        65,099
                                                         ------------   ----------    -----------    -----------   -----------
     Total electric revenues                           $   6,600,689  $ 6,556,561  $   3,545,694  $   3,146,158  $  3,149,929
                                                         ============   ==========    ===========    ===========   ===========
Peak demand of firm load (thousands of kW)
  System (b)                                                  20,365       19,166         18,874         10,948        10,529
  Company                                                     19,746       18,564         18,272         10,344         9,875
Total regulated capability at year-end (thousands of kW)
  Fossil plants                                               16,006       15,826  (e)    14,747          6,736         6,571
  Nuclear plants                                               4,127  (f)   4,008          4,008          3,174         3,174
  Hydro plants                                                   218          218            218            218           218
  Purchased                                                    2,929        2,890          2,278          1,088         1,538
                                                         ------------   ----------    -----------    -----------   -----------
     Total system capability                                  23,280       22,942         21,251         11,216        11,501
Less jointly-owned portion (c)                                   682          668            662            593           593
                                                         ------------   ----------    -----------    -----------   -----------
     Total Company capability - regulated                     22,598       22,274         20,589         10,623        10,908
                                                         ============   ==========    ===========    ===========   ===========
</TABLE>

(a)  Amounts  represent  co-owner's  share of the energy  supplied  from the six
     generating facilities that are jointly owned.
(b)  For 2002, 2001 and 2000, this represents the combined summer non-coincident
     system net peaks for CP&L and Florida. Power.
(c)  For CP&L, this represents  Power Agency's  retained share of  jointly-owned
     facilities  per the Power  Coordination  Agreement  between  CP&L and Power
     Agency.
(d)  Amounts include  information for Florida Power since November 30, 2000, the
     date of acquisition.
(e)  Amount includes Rowan units that were transferred to PVI in February 2002.
(f)  Amount  includes power upgrades for Harris,  Brunswick 1 and Robinson.  The
     Maximum  Dependable  Capability (MDC) for Harris was restated January 2002;
     the MDCs for Brunswick 1 and Robinson were restated January 2003.

                                       31
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

OPERATING STATISTICS - CAROLINA POWER & LIGHT COMPANY

                                                                               Years Ended December 31
                                                             2002           2001          2000           1999          1998
                                                          -----------    -----------   -----------    -----------   -----------
Energy supply (millions of kWh)
  Generated - Steam                                           28,547        27,913        29,520         28,260        27,576
              Nuclear                                         23,425        21,321        23,275         22,451        22,014
              Hydro                                              491           245           441            520           790
              Combustion Turbines/Combined Cycle               1,934           802           733            435           386
  Purchased                                                    5,213         5,296         4,878          5,132         5,675
                                                          -----------   -----------   -----------    -----------   -----------
      Total energy supply (Company share)                     59,610        55,577        58,847         56,798        56,441
  Power Agency share (a)                                       4,659         4,348         4,505          4,353         4,349
                                                          -----------   -----------   -----------    -----------   -----------
      Total system energy supply                              64,269        59,925        63,352         61,151        60,790
                                                          ===========   ===========   ===========    ===========   ===========
Average fuel cost (per million Btu)
  Fossil                                                $       2.16  $       1.91  $       1.83  $        1.75  $       1.71
  Nuclear fuel                                          $       0.43  $       0.44  $       0.45  $        0.46  $       0.46
  All fuels                                             $       1.38  $       1.26  $       1.21  $        1.16  $       1.14
Energy sales (millions of kWh)
Retail
  Residential                                                 15,239        14,372        14,091         13,348        13,207
  Commercial                                                  12,468        11,972        11,432         11,068        10,646
  Industrial                                                  13,089        13,332        14,446         14,568        14,899
  Other Retail                                                 1,437         1,423         1,423          1,359         1,357
Wholesale                                                     15,024        12,996        14,582         14,526        14,461
Unbilled                                                         270          (534)          679           (110)          (94)
                                                          -----------   -----------   -----------    -----------   -----------
     Total energy sales                                       57,527        53,561        56,653         54,759        54,476
     Company uses and losses                                   2,081         2,017         2,194          2,039         1,964
                                                          -----------   -----------   -----------    -----------   -----------
     Total energy requirements                                59,608        55,578        58,847         56,798        56,440
                                                          ===========   ===========   ===========    ===========   ===========

Electric revenues (in thousands)
  Retail                                                $  2,795,788  $  2,665,857  $  2,608,727  $   2,530,562  $  2,536,693
  Wholesale                                                  650,884       634,009       577,279        556,079       548,137
  Miscellaneous revenue                                       92,285        43,854       122,209         59,518        65,099
                                                          -----------   -----------   -----------    -----------   -----------
     Total electric revenues                            $  3,538,957  $  3,343,720  $  3,308,215  $   3,146,159  $  3,149,929
                                                          ===========   ===========   ===========    ===========   ===========
Peak demand of firm load (thousands of kW)
  System                                                      11,977        11,376        11,157         10,948        10,529
  Company                                                     11,358        10,774        10,555         10,344         9,875
Total capability at year-end (thousands of kW)
  Fossil plants                                                8,816         8,648  (c)    7,569          6,891         6,571
  Nuclear plants                                               3,293 (d)     3,174         3,174          3,174         3,174
  Hydro plants                                                   218           218           218            218           218
  Purchased                                                    1,617         1,586           978          1,088         1,538
                                                          -----------   -----------    ----------    -----------   -----------
     Total system capability                                  13,944        13,626        11,939         11,371        11,501
Less Power Agency-owned portion (b)                              613           599           593            593           593
                                                          -----------   -----------    ----------    -----------   -----------
     Total Company capability                                 13,331        13,027        11,346         10,778        10,908
                                                          ===========   ===========    ==========    ===========   ===========
</TABLE>

(a)  Amounts represent Power Agency's share of the energy supplied from the four
     generating facilities that are jointly owned.
(b)  Amounts represent Power Agency's retained share of jointly-owned facilities
     per the Power Coordination Agreement between CP&L and Power Agency.
(c)  Amount includes Rowan units that were transferred to PVI in February 2002.
(d)  Amount  includes power upgrades for Harris,  Brunswick 1 and Robinson.  The
     MDC for Harris was  restated  January  2002;  the MDCs for  Brunswick 1 and
     Robinson were restated January 2003.


                                       32
<PAGE>

ITEM 2. PROPERTIES

The Company believes that its physical  properties and those of its subsidiaries
are adequate to carry on its and their  businesses as currently  conducted.  The
Company and its subsidiaries  maintain property insurance against loss or damage
by fire or other perils to the extent that such property is usually insured.

ELECTRIC - CP&L

As of December 31, 2002, CP&L's eighteen  generating plants represent a flexible
mix of fossil,  nuclear,  hydroelectric,  combustion turbines and combined cycle
resources,  with a total summer  generating  capacity  (including Power Agency's
share) of 12,327 MW. At December 31,  2002,  CP&L had the  following  generating
facilities:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

---------------------------------------------------------------------------------------------------------------
                                                                            CP&L          Summer Net
                                       No. of   In-Service               Ownership        Capability (a)
   Facility          Location          Units       Date         Fuel       (in %)            (in MW)
---------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Asheville          Skyland, NC           2      1964-1971       Coal         100             392
Cape Fear          Moncure, NC           2      1956-1958       Coal         100             316
Lee                Goldsboro, NC         3      1952-1962       Coal         100             407
Mayo               Roxboro, NC           1         1983         Coal        83.83            745      (b)
Robinson           Hartsville, SC        1         1960         Coal         100             174
Roxboro            Roxboro, NC           4      1966-1980       Coal        96.32    (f)    2,462     (b)
Sutton             Wilmington, NC        3      1954-1972       Coal         100             613
Weatherspoon       Lumberton, NC         3      1949-1952       Coal         100             176
                                      --------                                           ------------
                   Total                19                                                  5,285
COMBINED CYCLE
Cape Fear          Moncure, NC           2         1969          Oil         100              84
Richmond           Hamlet, NC            1         2002        Gas/Oil       100             472
                                      --------                                           ------------
                   Total                 3                                                    556
COMBUSTION TURBINES
Asheville          Skyland, NC           2      1999-2000      Gas/Oil       100             330
Blewett            Lilesville, NC        4         1971          Oil         100              52
Darlington         Hartsville, SC       13      1974-1997      Gas/Oil       100             812
Lee                Goldsboro, NC         4      1968-1971        Oil         100              91
Morehead City      Morehead City,  NC    1         1968          Oil         100              15
Richmond           Hamlet, NC            5      2001-2002      Gas/Oil       100             775
Robinson           Hartsville, SC        1         1968        Gas/Oil       100              15
Roxboro            Roxboro, NC           1         1968          Oil         100              15
Sutton             Wilmington, NC        3      1968-1969        Oil         100              64
Wayne County       Goldsboro, NC         4         2000        Gas/Oil       100             668
Weatherspoon       Lumberton, NC         4      1970-1971        Oil         100             138
                                      --------                                           ------------
                   Total                42                                                  2,975
NUCLEAR
Brunswick          Southport, NC         2      1975-1977      Uranium      81.67           1,683     (b)(c)
Harris             New Hill, NC          1         1987        Uranium      83.83            900      (b)(d)
Robinson           Hartsville, SC        1         1971        Uranium       100             710      (e)
                                      --------                                           ------------
                   Total                 4                                                  3,293
HYDRO
Blewett            Lilesville, NC        6         1912         Water        100             22
Marshall           Marshall, NC          2         1910         Water        100              5
Tillery            Mount Gilead, NC      4      1928-1960       Water        100             86
Walters            Waterville, NC        3         1930         Water        100             105
                                      --------                                           ------------
                   Total                15                                                   218

TOTAL                                   83                                                 12,327
---------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts  represent  CP&L's net summer peak  rating,  gross of  co-ownership
     interest in plant capacity.
(b)  Facilities are jointly owned by CP&L and Power Agency. The capacities shown
     include Power Agency's share.
(c)  During 2002, a power uprate  increased the summer net  capability of Unit 1
     to 872 MW. The MDC was restated in January 2003.
(d)  During 2001, a power uprate  increased  the summer net  capability  of this
     facility to 900 MW. The MDC was restated in January 2002.
(e)  During 2002, a power uprate  increased  the summer net  capability  of this
     facility to 710 MW. The MDC was restated January 2003.
(f)  CP&L and Power Agency are co-owners of Unit 4 at the Roxboro Plant.  CP&L's
     ownership interest in this 700 MW turbine is 87.06%.

                                       33

<PAGE>

As of December 31, 2002,  including both the total generating capacity of 12,327
MW and the total firm contracts for purchased power of  approximately  1,617 MW,
CP&L had total capacity resources of approximately 13,944 MW.

The  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 the
Harris Plant and Mayo Unit No. 1. Otherwise,  CP&L 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.  CP&L also owns certain easements
over private property on which transmission and distribution lines are located.

As of December 31, 2002, CP&L had approximately 6,000 pole miles of transmission
lines including about 300 miles of 500 kilovolt (kV) lines and about 3,000 miles
of 230 kV lines. CP&L had distribution lines of approximately  45,000 pole miles
of overhead lines and about 16,000 miles of underground lines.  Distribution and
transmission  substations in service had a transformer capacity of approximately
47,000,000   kilovolt-ampere  (kVA)  in  823  transformers.   Distribution  line
transformers  numbered  495,501 with an aggregate  capacity of about  20,000,000
kVA.

ELECTRIC - FLORIDA POWER

As of December  31,  2002,  Florida  Power's 14  generating  plants  represent a
flexible mix of fossil, nuclear, combustion turbine and combined cycle resources
with a total summer generating  capacity (including  jointly-owned  capacity) of
8,024 MW. At December  31,  2002,  Florida  Power had the  following  generating
facilities:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

-----------------------------------------------------------------------------------------------------------
                                                                          Florida    Summer Net
                                         No. of  In-Service              Ownership   Capability (a)
   Facility          Location            Units      Date       Fuel        (in %)      (in MW)
-----------------------------------------------------------------------------------------------------------
STEAM TURBINES
Anclote            Holiday, FL            2      1974-1978    Gas/Oil       100          993
Bartow             St. Petersburg, FL     3      1958-1963    Gas/Oil       100          444
Crystal River      Crystal River, FL      4      1966-1984      Coal        100         2,302
Suwannee River     Live Oak, FL           3      1953-1956    Gas/Oil       100          143
                                        -------                                     ---------------
                   Total                 12                                             3,882
COMBINED CYCLE
Hines              Bartow, FL             1        1999       Gas/Oil       100          482
Tiger Bay          Fort Meade, FL         1        1997         Gas         100          207
                                        -------                                     ---------------
                   Total                  2                                              689
COMBUSTION TURBINES
Avon Park          Avon Park, FL          2        1968       Gas/Oil       100          52
Bartow             St. Petersburg, FL     4      1958-1972    Gas/Oil       100          187
Bayboro            St. Petersburg, FL     4        1973         Oil         100          184
DeBary             DeBary, FL            10      1975-1992    Gas/Oil       100          667
Higgins            Oldsmar, FL            4      1969-1970      Gas         100          122
Intercession City  Intercession   City,  14      1974-2000    Gas/Oil       100 (c)     1,041       (b)
                   FL
Rio Pinar          Rio Pinar, FL          1        1970         Oil         100          13
Suwannee River     Live Oak, FL           3        1980       Gas/Oil       100          164
Turner             Enterprise, FL         4      1970-1974      Oil         100          154
University of      Gainesville, FL        1        1994         Gas         100          35
   Florida
   Cogeneration
                                        -------                                     ---------------
                   Total                 47                                             2,619
NUCLEAR
Crystal River      Crystal River, FL      1        1977       Uranium      91.78         834        (b)
                                        -------                                     ---------------
                   Total                  1                                              834

TOTAL                                    62                                             8,024
-----------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts  represent  Florida  Power's  net  summer  peak  rating,  gross  of
     co-ownership interest in plant capacity.
(b)  Facilities  are jointly owned.  The capacities  shown include joint owners'
     share.
(c)  Florida Power and Georgia Power Company  ("Georgia Power") are co-owners of
     a  143  MW  advanced   combustion   turbine   located  at  Florida  Power's
     Intercession City site (P11).  Georgia Power has the exclusive right to the
     output of this unit during the months of June  through  September.  Florida
     Power has that right for the  remainder of the year.  Additionally,  during
     2002,  power  uprates on units P12,  P13 and P14  increased  the summer net
     capability of this facility to 1,041 MW.

As of December 31, 2002,  including both the total generating  capacity of 8,024
MW and the total firm  contracts for purchased  power of 1,304 MW, Florida Power
had total capacity resources of approximately 9,328 MW. Hines Unit 2 is a 516 MW
combined-cycle unit under construction and currently scheduled for completion in
late 2003.

                                       34

<PAGE>

Several  entities  have  acquired  undivided  ownership  interests in CR3 in the
aggregate amount of 8.22%. The joint ownership participants are: City of Alachua
- 0.08%,  City of  Bushnell  - 0.04%,  City of  Gainesville  - 1.41%,  Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New  Smyrna  Beach - 0.56%,  City of Ocala -  1.33%,  Orlando  Utilities
Commission  - 1.60% and Seminole  Electric  Cooperative,  Inc. - 1.70%.  Florida
Power and Georgia  Power are  co-owners of a 143 MW advance  combustion  turbine
located at Florida Power's  Intercession City site (P11).  Georgia Power has the
exclusive  right to the output of this unit  during  the months of June  through
September.  Florida  Power  has  that  right  for  the  remainder  of the  year.
Otherwise,  Florida Power 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.  Florida Power also owns certain  easements over private  property on
which transmission and distribution lines are located.

As of December 31,  2002,  Florida  Power  distributed  electricity  through 370
substations with an installed  transformer capacity of approximately  45,000,000
kVA.  Of  this  capacity,  about  31,000,000  kVA  is  located  in  transmission
substations and about 14,000,000 kVA in distribution substations.  Florida Power
has the second  largest  transmission  network  in  Florida.  Florida  Power has
approximately  5,000 circuit miles of  transmission  lines, of which about 2,600
circuit  miles are  operated  at 500,  230 or 115 kV, and the  balance at 69 kV.
Florida Power has  approximately  28,000  circuit miles of  distribution  lines,
which operate at various voltages ranging from 2.4 to 25 kV.

PROGRESS VENTURES

The Progress  Ventures  business  segment  controls,  either directly or through
business  units,  coal  reserves  located in eastern  Kentucky and  southwestern
Virginia. Progress Ventures owns properties that contain estimated coal reserves
of  approximately  12  million  tons  and  controls,   through  mineral  leases,
additional  estimated  coal  reserves  of  approximately  18 million  tons.  The
reserves controlled include substantial  quantities of high quality,  low sulfur
coal that is appropriate for use at Florida Power's existing  generating  units.
Progress  Ventures' total production of coal during 2002 was  approximately  2.6
million tons.

In connection with its coal operations,  Progress  Ventures'  business units own
and operate an underground  mining complex located in southeastern  Kentucky and
southwestern   Virginia.   Other   subsidiaries  own  and  operate  surface  and
underground  mines,  coal  processing and loadout  facilities,  a river terminal
facility  in eastern  Kentucky,  a  railcar-to-barge  loading  facility  in West
Virginia and two bulk commodity  terminals on the Kanawha River near Charleston,
West Virginia.  Progress  Ventures and its subsidiaries  employ both company and
contract miners in their mining activities.

The Progress Ventures business segment,  through its business units, owns all of
the interests in five  entities and a minority  interest in one entity that owns
facilities  that  produce  synthetic  fuel.  These  entities own a total of nine
facilities in seven different locations in West Virginia, Virginia and Kentucky.

A business  unit of  Progress  Ventures  has oil and gas leases on about  20,000
acres in Garfield and Mesa counties in Colorado,  containing  proven natural gas
net reserves of 98 billion cubic feet. This subsidiary currently operates 96 gas
wells on the properties. Another subsidiary of Progress Ventures has oil and gas
leases on about  35,000  acres  concentrated  within a 25-mile  radius along the
Texas and  Louisiana  border,  containing  proven  natural  gas  reserves of 125
billion  cubic feet.  This  subsidiary  currently  operates 234 gas wells on the
properties.  Progress  Ventures' natural gas production in 2002 was 11.8 billion
cubic  feet.  The  Company  is  exploring  opportunities  to  divest of its Mesa
properties in 2003.

Another  business unit of Progress  Ventures  owns and operates a  manufacturing
facility at the Florida  Power Energy  Complex in Crystal  River,  Florida.  The
manufacturing  process  utilizes the fly ash generated by the burning of coal as
the major raw  material  in the  production  of  lightweight  aggregate  used in
construction building blocks.


                                       35
<PAGE>

As of December 31, 2002, PVI had the following nonregulated generation plants in
service or planned for construction.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

----------------------------------------------------------------------------------------------------------
                             Construction     Commercial Operation  Configuration/Number
           Project            Start Date             Date                of Units            MW (a)
----------------------------------------------------------------------------------------------------------
Monroe Units 1 and 2        4Q 1998/1Q 2000     4Q 1999/2Q 2001       Simple-Cycle, 2           315
                                                                                         -----------------
            Total                                                                               315

Rowan Phase I (b)               1Q 2000             2Q 2001           Simple-Cycle, 3           459
Walton (c)                      2Q 2000             2Q 2001           Simple-Cycle, 3           460
DeSoto Units 1 and 2            2Q 2001             2Q 2002           Simple-Cycle, 2           320
                                                                                         -----------------
            Total                                                                             1,239

Effingham                       1Q 2001           3Q 2003 (d)        Combined-Cycle, 1          480
Rowan Phase II (b)              4Q 2001           2Q 2003 (d)        Combined-Cycle, 1          466
Washington (c)                  2Q 2002           2Q 2003 (d)         Simple-Cycle, 4           600
                                                                                         -----------------
            Total                                                                             1,546

            TOTAL                                                                             3,100
----------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts represent PVI's summer rating.
(b)  This project was transferred from CP&L to PVI in February 2002.
(c)  This project was purchased from LG&E Energy Corp. in February 2002.
(d)  Date represents the expected commercial operation date.

RAIL SERVICES

Progress Rail is one of the largest integrated  processors of railroad materials
in the United States, and is a leading supplier of new and reconditioned freight
car  parts;  rail,  rail  welding  and track  work  components;  railcar  repair
facilities;  railcar and locomotive  leasing;  maintenance-of-way  equipment and
scrap metal recycling. It has facilities in 26 states, Mexico and Canada.

Progress  Rail  owns  and/or  operates  approximately  5,300  railcars  and  100
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.

OTHER

PROGRESS TELECOM AND CARONET

Progress  Telecom  and Caronet  provide  wholesale  telecommunications  services
throughout  the  Southeastern  United  States.   Progress  Telecom  and  Caronet
incorporate  more than  130,000  fiber miles in its network  including  over 160
Points-of-Presence,  or physical  locations  where a presence for network access
exists.

NCNG

NCNG owns and  operates a liquefied  natural gas  storage  plant which  provides
97,200 dt per day to NCNG's peak-day delivery capability.

NCNG owns  approximately  1,329  miles of  transmission  pipelines  of two to 30
inches in diameter which connect its distribution  systems with the Texas-to-New
York  transmission  system  of  Transco  and  the  southern  end  of  Columbia's
transmission system. Transco delivers gas to NCNG at various points conveniently
located  with respect to its  distribution  area.  Columbia  delivers gas to one
delivery  point  near the North  Carolina - Virginia  border.  NCNG  distributes
natural gas through its 3,096 miles of distribution  mains.  These  transmission
pipelines and distribution  mains are located  primarily on  rights-of-way  held
under easement, license or permit on lands owned by others.

                                       36
<PAGE>

ITEM 3    LEGAL PROCEEDINGS

Legal and regulatory proceedings are included in the discussion of the Company's
business  in PART I,  ITEM 1 under  "Environmental,"  "Regulatory  Matters"  and
"Nuclear Matters" and incorporated by reference herein.

1.   The People of the State of California  v.  Strategic  Resource  Solutions ,
     Inc., San Francisco Superior Court, SCN 187328 Court No. 2072965

     Strategic  Resource  Solutions  Corp.  (SRS)  was  charged  in  a  criminal
     complaint filed on October 9, 2002 by the San Francisco District Attorney's
     office.  Working with the San Francisco District Attorney's office, SRS has
     pled guilty to two charges, taking responsibility for the misconduct of one
     of its former employees. This proceeding concluded on October 15, 2002.

     SRS agreed to pay a fine of  $500,000.  Although  SRS did not  receive  any
     funds,  because of the involvement of a former  employee,  SRS has accepted
     corporate criminal  responsibility and agreed to pay an additional $500,000
     as a  restitution.  SRS was also  placed  on  probation  and will  continue
     cooperating with the District  Attorney's  investigation and prosecution of
     other defendants.

     This  proceeding  no longer meets the  disclosure  standards for this item,
     thus the Company will no longer report on it.

2.   Strategic  Resource Solutions Corp. ("SRS") v. San Francisco Unified School
     District, et al., Sacramento Superior Court, Case No. 02AS033114

     In November of 2001,  SRS filed a claim against the San  Francisco  Unified
     School District ("the District") and other defendants  claiming that SRS is
     entitled to approximately $10 million in unpaid contract payments and delay
     and impact damages related to the District's $30 million contract with SRS.
     On March 4, 2002, the District filed a counterclaim,  seeking  compensatory
     damages  and  liquidated  damages in excess of $120  million,  for  various
     claims,  including breach of contract and demand on a performance bond. SRS
     has asserted defenses to the District's claims.

     On March 13, 2003, the City Attorney's  office  announced the filing of new
     claims by the City Attorney and the District against SRS,  Progress Energy,
     Inc., Progress Energy Solutions,  Inc., and certain  individuals,  alleging
     fraud,  false  claims,  violations  of  California  statutes,  and  seeking
     compensatory damages, punitive damages, liquidated damages, treble damages,
     penalties,  attorneys'  fees and  injunctive  relief.  The City  Attorney's
     announcement  states  that the City and the  District  seek "more than $300
     million in damages and penalties."

     The Company has reviewed the District's  earlier pleadings against SRS, and
     believes  that  those  claims  are not  meritorious.  The  Company  has not
     reviewed the new pleadings in detail, but the Company believes that the new
     claims are not  meritorious  and the  Company  will  vigorously  defend and
     litigate all of these  claims.  The Company  cannot  predict the outcome of
     this matter,  but the Company  believes that it and its  subsidiaries  have
     good defenses to all claims asserted by both the District and the City.


ITEM 4    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS


             NONE

                                       37
<PAGE>

                     EXECUTIVE OFFICERS OF THE REGISTRANTS

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Name                        Age                          Recent Business Experience

William Cavanaugh III       64    Chairman and Chief Executive Officer,  Progress Energy, Inc., August 1999
                                  to  present,  also  President,  Progress  Energy,  Inc.,  August  1999 to
                                  October 2002; Chairman,  President and Chief Executive Officer,  Carolina
                                  Power  &  Light  Company,  May  1999  to  present;  President  and  Chief
                                  Executive  Officer,  Carolina Power & Light Company,  October 1996 to May
                                  1999;  Chairman,  Progress  Energy Service  Company,  LLC, August 2000 to
                                  present;  Chairman,  Florida  Power  Corporation,  November  30,  2000 to
                                  present;  Chairman,  President  and CEO,  Florida  Progress  Corporation,
                                  November 2000 to present;  Chairman,  Progress Ventures, Inc., March 2000
                                  to present;  Chairman,  North Carolina Natural Gas  Corporation,  1999 to
                                  present; Chairman,  Progress Capital Holdings, Inc., November 30, 2000 to
                                  present;  Chairman,  Progress  Fuels  Corporation,  November  30, 2000 to
                                  present; Chairman, Progress Telecommunications Corporation,  November 30,
                                  2000 to present;  Chairman,  Strategic Resource Solutions Corp,  November
                                  1997 to  December  31,  2002.  Member  of the Board of  Directors  of the
                                  Company since 1993.

Robert B. McGehee           60    President and Chief Operating  Officer,  Progress Energy,  Inc.,  October
                                  2002  to  present;  Executive  Vice  President,  Progress  Energy,  Inc.,
                                  December  2000 to September  2002;  Executive  Vice  President,  Carolina
                                  Power & Light Company and Florida Progress Corporation,  December 2000 to
                                  present;  President and Chief Executive Officer,  Progress Energy Service
                                  Company,   LLC,   December  2000  to  September   2002;   Executive  Vice
                                  President,  General Counsel and Chief  Administrative  Officer,  Carolina
                                  Power  & Light  Company,  March  1999 to  September,  2000;  Senior  Vice
                                  President and General Counsel,  Carolina Power & Light Company,  May 1997
                                  to March 1999.  Prior to joining the Company,  was a practicing  attorney
                                  with Wise Carter  Child & Caraway,  a law firm in  Jackson,  Mississippi.
                                  He  primarily  handled  corporation,  contract,  nuclear  regulatory  and
                                  employment matters.

William S. Orser            58    Group  President,  Carolina  Power  & Light  Company  and  Florida  Power
                                  Corporation,   November  2000  to  present;   Executive  Vice  President,
                                  Carolina  Power & Light  Company,  Energy  Supply,  June 1998 to November
                                  2000; Executive Vice President and Chief Nuclear Officer,  Carolina Power
                                  & Light Company, December 1996 to June 1998.

William D. Johnson          49    President, CEO and Corporate Secretary,  Progress Energy Service Company,
                                  LLC,  October 2002 to present  (served as Executive  Vice  President  and
                                  Corporate  Secretary,  2000 to October 2002);  Executive Vice  President,
                                  and Corporate  Secretary,  Progress Energy,  Inc., August 1999 to present
                                  (and General Counsel February 2001 to present);  Executive Vice President
                                  and Corporate Secretary,  Florida Progress Corporation,  Carolina Power &
                                  Light  Company and Florida Power  Corporation,  November 2000 to present;
                                  General  Counsel,  Florida Progress  Corporation,  Carolina Power & Light
                                  Company,   Progress  Energy  Service  Company,   LLC  and  Florida  Power
                                  Corporation,  November  2000 to October 2002;  Senior Vice  President and
                                  Corporate  Secretary,  Carolina  Power & Light  Company,  Legal  and Risk
                                  Management,  March 1999 to November 2000; Vice President-Legal Department
                                  and Corporate Secretary, Carolina Power & Light Company, 1997 to 1999.

                                       38

<PAGE>

Peter M. Scott III          53    Executive Vice President and Chief Financial  Officer,  Progress  Energy,
                                  Inc.,  May 2000 to present;  Executive  Vice  President and CFO,  Florida
                                  Power  Corporation  and Florida  Progress  Corporation,  November 2000 to
                                  present;  Executive  Vice  President  and CFO,  Progress  Energy  Service
                                  Company,  LLC, August 2000 to present;  Executive Vice President and CFO,
                                  Carolina  Power & Light  Company,  May 2000 to  present;  Executive  Vice
                                  President and CFO, North Carolina Natural Gas Corporation,  December 2000
                                  to present.  Before  joining the  Company,  Mr.  Scott was  President  of
                                  Scott,  Madden  &  Associates,  Inc.,  a  management  consulting  firm he
                                  founded  in  1983.   The  firm  advises   companies   on  key   strategic
                                  initiatives for growing shareholder value.


Robert H. Bazemore, Jr.     48    Chief  Accounting  Officer and Controller,  Progress  Energy,  Inc., June
                                  2000 to  present;  Controller,  Florida  Power  Corporation  and  Florida
                                  Progress  Corporation,   November  2000  to  present;   Chief  Accounting
                                  Officer,  Florida  Progress  Corporation,  November  30, 2000 to present;
                                  Vice President and  Controller,  Progress  Energy Service  Company,  LLC,
                                  August  2000  to  present;   Chief  Accounting  Officer  and  Controller,
                                  Carolina Power & Light  Company,  May 2000 to present;  Chief  Accounting
                                  Officer,  North  Carolina  Natural  Gas  Corporation,  December  2000  to
                                  present;  Controller,  North Carolina Natural Gas  Corporation,  November
                                  2000  to  December  2001;  Director,  Carolina  Power  &  Light  Company,
                                  Operations  &  Environmental  Support  Department,  December  1998 to May
                                  2000;  Manager,  Carolina Power & Light  Company,  Financial & Regulatory
                                  Accounting, September 1995 to December 1998.

*Brenda F. Castonguay       50    Senior Vice President,  Progress Energy Service  Company,  LLC, July 2002
                                  to  present;  Vice  President,  Progress  Energy  Service  Company,  LLC,
                                  November 2000 to July 2002; Vice  President,  Human  Resources,  Carolina
                                  Power & Light Company, April 1996 to July 2002.

Donald K. Davis             57    Executive Vice  President,  Carolina  Power & Light Company,  May 2000 to
                                  present;  President and Chief Executive  Officer,  North Carolina Natural
                                  Gas  Corporation,  July 2000 to present;  President  and Chief  Executive
                                  Officer,  Strategic Resource Solutions Corp., June 2000 to December 2002;
                                  Executive Vice  President,  Florida Power  Corporation,  February 2001 to
                                  present.  Before joining the Company,  Mr. Davis was Chairman,  President
                                  and Chief  Executive  Officer  of Yankee  Atomic  Electric  Company,  and
                                  served as Chairman,  President and Chief Executive Officer of Connecticut
                                  Atomic Power Company from 1997 to May 2000.

Fred N. Day, IV             59    Executive  Vice  President,  Carolina  Power & Light  Company and Florida
                                  Power  Corporation,  November  2000 to present;  Senior  Vice  President,
                                  Carolina Power & Light Company,  Energy  Delivery,  July 1997 to November
                                  2000;  Vice  President,  Carolina Power & Light Company,  Western Region,
                                  1995 to July 1997.

*H. William Habermeyer, Jr. 60    President  and  Chief  Executive   Officer,  Florida  Power  Corporation,
                                  November 2000 to present; Vice President, Carolina Power & Light Company,
                                  Western Region, July 1997 to November 2000.

                                       39

<PAGE>

*Bonnie V. Hancock          41    President, Progress Fuels Corporation,  September 2002 to present, Senior
                                  Vice President,  Progress Energy Service Company,  LLC,  November 2000 to
                                  September  2002;   Vice  President,   Carolina  Power  &  Light  Company,
                                  Strategic  Planning,  February 1999 to November 2000;  Vice President and
                                  Controller,  Carolina  Power & Light  Company,  February 1997 to February
                                  1999.

C.S. Hinnant                58    Senior Vice President and Chief Nuclear  Officer,  Carolina Power & Light
                                  Company,  June 1998 to present;  Senior  Vice  President,  Florida  Power
                                  Corporation,  December 2000 to present; Vice President,  Carolina Power &
                                  Light Company, Brunswick Nuclear Plant, April 1997 to June 1998.

Tom D. Kilgore              55    Group  President,  Carolina  Power  &  Light  Company,  November  2000 to
                                  present;  President  and CEO,  Progress  Ventures,  Inc.,  March  2000 to
                                  present;  President and CEO,  Progress Fuels  Corporation,  March 2000 to
                                  September 2002;  Senior Vice  President,  Carolina Power & Light Company,
                                  Power  Operations,  August 1998 to  November  2000;  President  and Chief
                                  Executive  Officer,  Oglethorpe  Power  Corporation,  July 1991 to August
                                  1998.  This  company  provides  power  generation  to 39 of  Georgia's 42
                                  customer-owned Electric Membership Corporations.

*John R. McArthur           47    Senior Vice President,  Progress Energy Service  Company,  LLC,  December
                                  2002 to present;  Vice President,  Progress Energy Service Company,  LLC,
                                  December 2001 to December  2002;  Senior Advisor to Governor Mike Easley,
                                  January  2001 to November  2001;  Manager,  Government  State  Relations,
                                  General Electric, October 1997 to December 2000.

E. Michael Williams         54    Senior  Vice  President,  Florida  Power  Corporation,  November  2000 to
                                  present;  Senior Vice  President,  Carolina Power & Light  Company,  June
                                  2000 to  present.  Before  joining the  Company,  Mr.  Williams  held the
                                  position of Vice  President,  Fossil  Generation,  Central and South West
                                  Corp., an investor-owned utility from March 1994 to June 2000.


*Indicates individual is an executive officer of Progress Energy, Inc., but not Carolina Power & Light Company.

                                       40
<PAGE>

                                     PART II

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

</TABLE>

Progress  Energy's  Common Stock is listed on the New York Stock  Exchange.  The
high and low intra-day  stock sales prices for Progress  Energy for each quarter
for the past two years, and the dividends declared per share are as follows:

2002                  High          Low       Dividends Declared
----                  ----          ---       ------------------

First Quarter        $50.86       $43.01           $0.545
Second Quarter        52.70        47.91            0.545
Third Quarter         51.97        36.54            0.545
Fourth Quarter        44.82        32.84            0.560

2001                  High          Low       Dividends Declared
----                  ----          ---       ------------------

First Quarter        $49.25       $38.78           $0.530
Second Quarter        45.00        40.36            0.530
Third Quarter         45.79        39.25            0.530
Fourth Quarter        45.60        40.50            0.545

The December 31 closing price of the Company's  Common Stock was $43.35 for 2002
and $45.03 for 2001.

As of February  28,  2003,  the  Company had 72,380  holders of record of Common
Stock.

Progress  Energy holds all 159,608,055  shares  outstanding of CP&L common stock
and, therefore, no public trading market exists for the common stock of CP&L.

Neither  Progress  Energy's  Articles  of  Incorporation  nor  any of  its  debt
obligations  contain  any  restrictions  on the  payment of  dividends.  Certain
documents restrict the payment of dividends by Progress Energy's subsidiaries.

RESTRICTED STOCK AWARDS:

(a)  Securities Delivered. On December 11, 2002, 23,700 restricted shares of the
     Company's  Common Shares were granted to certain key employees  pursuant to
     the terms of the Company's  2002 Equity  Incentive  Plan (Equity  Incentive
     Plan),  which was approved by the  Company's  shareholders  on May 8, 2002.
     Section  9 of the  Equity  Incentive  Plan  provides  for the  granting  of
     Restricted  Stock by the  Organization  and  Compensation  Committee of the
     Company's  Board of  Directors  (the  Committee)  to key  employees  of the
     Company,  including  its  Affiliates  or  any  successor,  and  to  outside
     directors  of the  Company.  The Common  Shares  delivered  pursuant to the
     Equity Incentive Plan were acquired in market transactions directly for the
     accounts of the recipients and do not represent  newly issued shares of the
     Company.

(b)  Underwriters and Other Purchasers.  No underwriters were used in connection
     with the delivery of Common Shares  described above. The Common Shares were
     delivered to certain key  employees of the  Company.  The Equity  Incentive
     Plan defines "key  employee" as an officer or other employee of the Company
     who is selected for participation in the Equity Incentive Plan.

(c)  Consideration.  The Common Shares were delivered to provide an incentive to
     the  employee  recipients  to exert their utmost  efforts on the  Company's
     behalf and thus  enhance  the  Company's  performance  while  aligning  the
     employee's interest with those of the Company's shareholders.

(d)  Exemption from  Registration  Claimed.  The Common Shares described in this
     Item were  delivered on the basis of an exemption from  registration  under
     Section 4(2) of the  Securities  Act of 1933.  Receipt of the Common Shares
     required no investment  decision on the part of the  recipients.  All award
     decisions  were  made  by  the  Committee,   which  consists   entirely  of
     non-employee directors.


                                       41
<PAGE>

ITEM 6.    SELECTED CONSOLIDATED FINANCIAL DATA

PROGRESS ENERGY, INC.

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>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                               Years Ended December 31

                                            2002 (a)       2001 (a)          2000 (a)(b)          1999 (a)           1998
                                          -------------   ------------       -------------      --------------    -----------

                                              (dollars in thousands, except per share data)
Operating results
  Operating revenues                    $   7,945,120  $   8,085,380     $     3,768,922     $     3,264,957   $  3,211,552
  Income from continuing
     operations                         $     552,169  $     540,396     $       477,922     $       383,299   $    396,271
Net Income                              $     528,386  $     541,610     $       478,361     $       379,288   $    396,271

Per share data
  Basic earnings
     Income from continuing
        operations                      $        2.54  $        2.64     $          3.04     $          2.58   $       2.75
  Net income                            $        2.43  $        2.65     $          3.04     $          2.56   $       2.75

  Diluted
     Income from continuing
        operations                      $        2.53  $        2.63     $          3.03     $          2.58   $       2.75
     Net income                         $        2.42  $        2.64     $          3.03     $          2.55   $       2.75
  Dividends declared per common
     share                              $       2.195  $       2.135     $         2.075     $         2.015   $      1.955

Assets                                  $  21,352,704  $  20,890,701     $    20,222,792     $     9,493,866   $  8,401,406

Capitalization
  Common stock equity                   $   6,677,009  $   6,003,533     $     5,424,201     $     3,412,647   $  2,949,305
  Preferred stock - redemption
     not required                              92,831         92,831              92,831              59,376         59,376
  Long-term debt, net                       9,747,293      8,618,960           4,903,803           2,161,761      2,126,414
  Current portion of long-term debt           275,397        688,052             184,037             197,250         53,172
  Short-term obligations                      694,850        942,314           4,958,971           1,035,040        488,000
                                          ------------   ------------      --------------      --------------    -----------
    Total capitalization and total debt $  17,487,380  $  16,345,690     $    15,563,843     $     6,866,074   $  5,676,267
                                          ============   ============      ==============      ==============    ===========
</TABLE>


(a)  Operating   results  and  balance   sheet  data  have  been   restated  for
     discontinued operations.
(b)  Operating results and balance sheet data includes information for FPC since
     November 30, 2000, the date of acquisition.

                                       42
<PAGE>

CAROLINA POWER & LIGHT COMPANY

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>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                             Years Ended December 31

                                           2002             2001            2000 (a)(b)         1999 (b)            1998
                                        -----------      ------------      --------------     -------------      -----------

                                                                     (dollars in thousands)
Operating results
  Operating revenues                  $  3,553,820     $   3,360,161     $     3,528,446    $     3,364,927    $  3,211,552
  Net income                          $    430,932     $     364,231     $       461,028    $       382,255    $    399,238
  Earnings for common stock           $    427,968     $     361,267     $       458,062    $       379,288    $    396,271

Assets                                $  8,974,684     $   9,258,685     $     9,239,486    $     9,494,019    $  8,401,406

Capitalization
  Common stock equity                 $  3,089,115     $   3,095,456     $     2,852,038    $     3,412,647    $  2,949,305
  Preferred stock - redemption
     not required                           59,334            59,334              59,334             59,376          59,376
  Long-term debt, net                    3,048,466         2,698,318           3,133,687          2,161,761       2,126,414
  Current portion of long-term debt              -           600,000                   -            197,250          53,172
  Short-term obligations (c)               437,750           308,448             486,297          1,035,040         488,000
                                        -----------      ------------      --------------     --------------     -----------
  Total capitalization and total debt $  6,634,665     $   6,761,556     $     6,531,356    $     6,866,074    $  5,676,267
                                        ===========      ============      ==============     ==============     ===========
</TABLE>


(a)  Operating  results and balance  sheet data do not include  information  for
     NCNG,  SRS,  Monroe Power or PVI  subsequent to July 1, 2000, the date CP&L
     distributed  its  ownership  interest  in the stock of these  companies  to
     Progress Energy.
(b)  Operating results include NCNG results for the period July 15, 1999 to July
     1, 2000. Balance sheet data includes NCNG for December 31, 1999.
(c)  Includes notes payable to affiliated companies of $47.9 million at December
     31, 2001.


                                       43
<PAGE>

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

The following  Management's  Discussion  and Analysis  contains  forward-looking
statements that involve estimates,  projections, goals, forecasts,  assumptions,
risks and  uncertainties  that could cause actual  results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
the "Risk Factors" section and "SAFE HARBOR FOR FORWARD-LOOKING  STATEMENTS" for
a discussion of the factors that may impact any such forward-looking  statements
made herein.

RESULTS OF OPERATIONS
For 2002 as compared to 2001 and 2001 as compared to 2000

In this section,  earnings and the factors affecting earnings are discussed. The
discussion begins with a general overview, then separately discusses earnings by
business segment.

Overview

Progress Energy,  Inc.  (Progress Energy or the Company) is a registered holding
company  under the  Public  Utility  Holding  Company  Act of 1935  (PUHCA),  as
amended.  Progress  Energy and its  subsidiaries  are subject to the  regulatory
provisions   of  PUHCA.   Progress   Energy  was  formed  as  a  result  of  the
reorganization  of Carolina Power & Light Company (CP&L) into a holding  company
structure  on June 19, 2000.  All shares of common stock of CP&L were  exchanged
for an equal number of shares of CP&L Energy,  Inc., the newly  created  holding
company.  On December 4, 2000,  CP&L Energy,  Inc.  changed its name to Progress
Energy, Inc.

The Company acquired Florida  Progress  Corporation  (FPC) on November 30, 2000.
The acquisition was accounted for using the purchase method of accounting.  As a
result,  the  consolidated  financial  statements only reflect FPC's  operations
subsequent to November 30, 2000.

Through  its  wholly  owned  regulated  subsidiaries,  CP&L  and  Florida  Power
Corporation  (Florida  Power),  Progress  Energy  is  primarily  engaged  in the
generation,  transmission,  distribution  and sale of electricity in portions of
North  Carolina,  South  Carolina  and Florida.  Through the  Progress  Ventures
business  segment,  Progress  Energy  is  involved  in  nonregulated  generation
operations;  natural  gas  exploration  and  production;  coal fuel  extraction,
manufacturing and delivery; and energy marketing and trading activities. Through
the Rail Services business segment,  Progress Energy engages in various rail and
railcar related services.  Through the Other business  segment,  Progress Energy
engages in other nonregulated  business areas including  telecommunications  and
holding company operations.

Effective January 1, 2003, CP&L, Florida Power and Progress Ventures, Inc. (PVI)
began doing business under the names Progress Energy Carolinas,  Inc.,  Progress
Energy Florida,  Inc., and Progress Energy  Ventures,  Inc.,  respectively.  The
legal names of these entities have not changed and there is no  restructuring of
any kind related to the name change.  The current  corporate  and business  unit
structure remains unchanged.

In 2002,  the  operations  of North  Carolina  Natural Gas  Corporation  (NCNG),
previously  reported in the Other segment,  were  reclassified  to  discontinued
operations  and  therefore  were not  included  in the results  from  continuing
operations  during the  periods  reported.  See Note 3A to the  Progress  Energy
consolidated financial statements for discussion of the planned divestiture.

Progress  Energy is an integrated  energy  company  located  principally  in the
southeast  region  of the  United  States.  The  Company  has more  than  21,900
megawatts of generation  capacity and serves  approximately 3.0 million electric
and natural gas  customers  in portions of North  Carolina,  South  Carolina and
Florida.  CP&L's and Florida Power's utility  operations are  complementary,  as
CP&L has a summer  peaking  demand,  while  Florida  Power has a winter  peaking
demand.  In addition,  CP&L's  greater  proportion of commercial  and industrial
customers  combined  with Florida  Power's  greater  proportion  of  residential
customers  creates a more balanced  customer  base.  The Company is dedicated to
delivering reliable, competitively priced energy.

In 2002,  Progress Energy's net income was $528.4 million,  a 2.4% decrease from
$541.6 million in 2001. Income from continuing operations was $552.2 million and
$540.4  million for 2002 and 2001,  respectively.  The decrease in net income in
2002 is primarily due to:
o   $288.7 million of after-tax impairments and other charges (Progress Telecom,
    Caronet and Interpath Communications,  Inc.), estimated impairment on assets
    held for sale (Railcar Ltd.), and discontinued operations (NCNG) in 2002;
o   the rate  case  settlement  of  Florida  Power  (one-time  retroactive  rate
    reduction of $21.0 million after tax combined with a 9.25%  prospective rate
    reduction);

                                       44
<PAGE>

o   increased  operating  expenses of $16.7 million after tax at CP&L related to
    the ice storm in December  2002,  and
o   increased  benefit  costs  and a  lower  pension  credit,  primarily  at the
    electric utilities.

Partially offsetting these items were:
o   continued  retail customer growth and usage  (including  weather impacts) at
    the electric utilities;
o   lower depreciation expense related to the Florida rate case settlement;
o   $152.8 million of after-tax  impairments  and other charges  attributable to
    Strategic Resource Solutions Corp. (SRS) and Interpath Communications,  Inc.
    (Interpath) in 2001;
o   impact of the change in market  value of  contingent  value  obligations  of
    $28.1 million;
o   lower interest charges primarily at CP&L, and
o   the elimination of goodwill amortization in 2002.

Basic earnings per share from net income  decreased from $2.65 per share in 2001
to $2.43 per share in 2002 due to the  factors  outlined  above and also from an
increase in the number of shares  outstanding  resulting  from the common  stock
issuances  in 2001 and 2002.  See Note 14 to the  Progress  Energy  consolidated
financial statements for more information on the Company's common stock.

Net income in 2001 rose $63.2  million  or 13.2% when  compared  to the 2000 net
income of $478.4 million. The increase in net income in 2001 is due primarily to
a full year of FPC's  operations  being  included  in the 2001  results,  as FPC
contributed  net income of $398.3  million for the year ended December 31, 2001.
Other  factors  contributing  to the  increase  in net  income in 2001  included
increases  in tax  credits  from  Progress  Energy's  share  of  synthetic  fuel
facilities, continued customer growth at the electric utilities and decreases in
depreciation  expense  related  to CP&L's  accelerated  cost  recovery  program.
Partially offsetting these increases were impairment and other after-tax charges
totaling  $152.8  million,  primarily  attributable  to SRS  and  the  Company's
investment  in  Interpath,  as well as increases in interest  expense,  goodwill
amortization  related  to the FPC  acquisition  and the  impact  of  unfavorable
weather.  Basic  earnings  per share  decreased  from $3.04 per share in 2000 to
$2.65  per  share in 2001 due to the  factors  outlined  above  and also from an
increase in the number of shares outstanding  resulting from the FPC acquisition
and an additional common stock issuance in August 2001.

Electric Segments

The electric  segments are primarily  engaged in the  generation,  transmission,
distribution  and sale of  electricity  in portions of North  Carolina and South
Carolina by CP&L  Electric,  and since November 30, 2000, in portions of Florida
by Florida Power Electric.  CP&L Electric serves an area of approximately 34,000
square  miles,  with a population  of more than 4.0 million.  As of December 31,
2002, CP&L Electric provided electricity to approximately 1.3 million customers.
Florida Power Electric serves an area of approximately 20,000 square miles, with
a population  of more than 5.0 million.  As of December 31, 2002,  Florida Power
Electric provided electricity to approximately 1.5 million customers.

The  operating  results of both electric  utilities are primarily  influenced by
customer  demand for  electricity,  the ability to control costs and  regulatory
return on  equity.  Annual  demand  for  electricity  is based on the  number of
customers and their annual usage,  with usage  largely  impacted by weather.  In
addition,  the current economic conditions in the service territories may impact
the annual demand for electricity.

CP&L Electric

CP&L  Electric  contributed  net income of $513.1  million,  $468.3  million and
$373.8 million in 2002, 2001 and 2000,  respectively.  Included in these amounts
are wholesale energy  marketing  activities and immaterial  trading  activities,
which  are  managed  by  Progress  Ventures  on behalf  of CP&L  Electric,  that
contributed  net income of $60.0 million,  $62.7  million,  and $84.0 million in
2002, 2001 and 2000, respectively.

                                       45
<PAGE>

Revenues

CP&L's electric revenues for the years ended December 31, 2002, 2001 and 2000
and the percentage change by year and by customer class are as follows (in
millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ---------------------------------------------------------------------------------------------------
     Customer Class                       2002       % Change       2001       % Change        2000
     ---------------------------------------------------------------------------------------------------
     Residential                          $1,241       7.7%         $1,152        3.5%        $1,113
     Commercial                              832       6.0             785        5.9            741
     Industrial                              645      (1.4)            654       (3.7)           679
     Governmental                             78       4.0              75       (1.3)            76
                                      -------------             -------------              -------------
         Total Retail Revenues             2,796       4.9           2,666        2.2          2,609
     Wholesale                               651       2.7             634        9.9            577
     Unbilled                                 15        -             (32)         -              51
     Miscellaneous                            77       1.3              76        7.0             71
                                      -------------             -------------              -------------
         Total Electric Revenues          $3,539       5.8%         $3,344        1.1%        $3,308
     ---------------------------------------------------------------------------------------------------
</TABLE>

CP&L's electric  energy sales for 2002, 2001 and 2000 and the percentage  change
by year and by customer class are as follows (in thousands of mWh):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ---------------------------------------------------------------------------------------------------
              Customer Class              2002       % Change       2001        % Change       2000
     ---------------------------------------------------------------------------------------------------
     Residential                          15,239       6.0%          14,372       2.0%        14,091
     Commercial                           12,468       4.1           11,972       4.7         11,432
     Industrial                           13,089      (1.8)          13,332      (7.7)        14,446
     Governmental                          1,437       1.0            1,423        -           1,423
                                      -------------             --------------             -------------
         Total Retail Energy Sales        42,233       2.8           41,099      (0.7)        41,392
     Wholesale                            15,024      15.6           12,996     (10.9)        14,582
     Unbilled                                270        -              (534)       -             679
                                      -------------             --------------             -------------
         Total mWh sales                  57,527       7.4%          53,561      (5.5%)       56,653
     ---------------------------------------------------------------------------------------------------
</TABLE>

CP&L's  electric  revenues  increased  $195.2 million from 2001 to 2002.  During
2002,  residential and commercial sales reflected continued growth in the number
of customers served by CP&L Electric, with approximately 26,000 new customers in
2002.  Sales of energy and revenue  increased  in 2002  compared to 2001 for all
customer classes except industrial.  Increases in retail sales of $129.9 million
and  wholesale  sales of $16.9  million  were also driven by  favorable  weather
during 2002 when compared to 2001.  Wholesale sales growth was partially  offset
by price declines in the wholesale market.

Downturns in the economy  during 2001 and continuing  into 2002 impacted  energy
usage throughout most of the industrial customer class. Total industrial revenue
declined  during 2002 by $9.1  million  and during 2001 by $25.0  million as the
number of  industrial  customers  decreased  due to a  slowdown  in the  textile
industry, as well as a decrease in usage in the chemical industry.

Compared to 2000, 2001 residential and commercial  revenues reflected  continued
growth in the number of customers  served by CP&L Electric  partially  offset by
milder  weather in 2001.  CP&L Electric added over 30,500 new customers in 2001.
Milder  weather  in 2001  accounted  for a decrease  in retail  revenue of $63.0
million for the year  compared to 2000.  Total kWh sales to wholesale  customers
decreased in 2001 from 2000  primarily  due to mild weather.  However,  revenues
from wholesale customers increased in 2001 over 2000 due to the establishment of
new long-term  contracts and the receipt of a termination payment on a long-term
contract in December 2001.

Expenses

CP&L Electric's fuel expense  increased $114.1 million in 2002, when compared to
$647.3 million in 2001,  primarily due to an 8.2% increase in generation  with a
higher  percentage of generation  being produced by combustion  turbines,  which
have higher fuel costs.  CP&L Electric's fuel expense increased $19.8 million in
2001 compared to $627.5  million in 2000 primarily due to increases in the price
of coal, partially offset by decreases in generation.

For 2002,  purchased  power  decreased  $6.1  million,  when  compared to $353.6
million in 2001,  mainly due to  decreases  in price and volume  purchased.  For
2001, purchased power increased $28.2 million when compared to $325.4 million in
2000 mainly due to favorable market conditions in the first quarter of 2001.

                                       46
<PAGE>

Fuel expenses are  recovered  primarily  through cost  recovery  clauses and, as
such, have no material impact on operating results.

CP&L  Electric's  total  operations and  maintenance  expenses  increased  $91.0
million in 2002 when compared to $701.7  million in 2001  primarily due to storm
costs of $27.2 million (see below), a lower pension credit of $6.0 million,  the
establishment  of an inventory  reserve of $10.5 million for materials that have
no future  benefit,  increased  salaries  and  benefits  and other  increases in
maintenance  and outage  support.  CP&L  Electric's  operations and  maintenance
expenses  decreased  $24.6  million in 2001 when  compared to $726.3  million in
2000,  primarily due to the absence of  restoration  costs  associated  with the
severe  winter storm and  record-breaking  snowfall in January  2000, as well as
cost  control  efforts.  These  amounts  were  partially  offset by increases in
planned nuclear outage costs and transmission expenses in 2001.

A major ice storm struck central North Carolina on December 4, 2002. As a result
of the storm, up to 464,000 (35%) customers in CP&L Electric's service area were
without  power.  Restoration  included  more than 3,500  line,  service and tree
personnel  from 19 states.  The outages  resulted in $27.2  million of increased
operations and maintenance costs and $27.8 million of increased capital costs.

Depreciation  and  amortization  expense  increased  $1.9  million  in 2002 when
compared to $521.9  million in 2001 and  decreased  $176.7  million in 2001 when
compared to $698.6 million in 2000.  CP&L Electric's  accelerated  cost recovery
program  for  nuclear   generating   assets  allows   flexibility  in  recording
accelerated  depreciation  expense.  CP&L  Electric  recorded  $52.8  million of
accelerated  depreciation  expense  in 2002  and  $75.0  million  in  2001.  The
year-over-year  favorability was offset by additional depreciation recognized in
2002,  as  compared to 2001,  on new assets  that were placed in service  during
2002. In 2000, as approved by regulators,  CP&L Electric recorded $275.0 million
of depreciation expense under the accelerated cost recovery program. See Note 1G
to  the  Progress  Energy  consolidated   financial  statements  for  additional
information about this program.

Net interest  expense  decreased  $29.9 million in 2002, when compared to $241.4
million in 2001,  due primarily to reduced debt and lower  interest  rates.  Net
interest  expense  increased  $19.6  million in 2001,  when  compared  to $221.9
million in 2000, primarily due to higher debt balances used to fund construction
programs.

In accordance with an SEC order under PUHCA, effective in 2002, tax benefits not
related to acquisition interest expense that were previously held unallocated at
the holding  company  must be  allocated to the  profitable  subsidiaries.  As a
result, $34.1 million of the tax benefit that was previously held at the holding
company,  included in the Other segment, was allocated to CP&L Electric in 2002.
The  allocation has no impact on the Company's  consolidated  tax expense or net
income.  Other  fluctuations  in income  taxes are  primarily  due to changes in
pre-tax income.

Florida Power Electric

The results shown in the Progress Energy consolidated  financial  statements for
the Florida Power Electric segment include  operating  results since the date of
acquisition,  November 30, 2000. Therefore,  2002 and 2001 include full years of
operations, while 2000 includes only one month. As a result, the 2000 results of
operations are not comparable to 2001.

Florida Power Electric  contributed  income of $322.6 million and $309.6 million
for the years ended December 31, 2002 and 2001, respectively,  and $21.8 million
for the month of December 2000.  Included in these amounts are wholesale  energy
marketing  activities and immaterial  trading  activities,  which are managed by
Progress  Ventures on behalf of Florida Power  Electric,  that  contributed  net
income of $13.0 million and $24.0 million for the years ended  December 31, 2002
and 2001, respectively, and $1.7 million for the month of December 2000.

Florida  Power  Electric's  earnings in 2002 were affected by the outcome of the
Florida  Power rate case  settlement,  which  included  a  one-time  retroactive
revenue  refund of $35.0 million ($21.0 million after tax), a decrease in retail
rates of 9.25%  (effective May 1, 2002),  which resulted in an additional  $79.5
million  decline in revenues,  and an estimated  revenue  sharing refund of $4.7
million.  These revenue declines were partially offset by $78.2 million of lower
depreciation  and amortization  pursuant to the rate case and increased  service
revenue  rates.  See  Note 15B to the  Progress  Energy  consolidated  financial
statements for further discussion of the rate case settlement.

                                       47
<PAGE>

A comparison of the results of operations of Florida Power Electric for the past
three years follows.

Revenues

Florida  Power's  electric  revenues for the years ended December 31, 2002, 2001
and 2000 and the percentage change by year and by customer class, as well as the
impact of the rate case settlement on revenue, are as follows (in millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------
     Customer Class                         2002      % Change       2001      % Change    2000 (a)
     ------------------------------------------------------------------------------------------------
     Residential                             $1,645      0.1%          $1,643    11.3%        $1,476
     Commercial                                 731     (3.1)             754    13.9            662
     Industrial                                 211     (5.4)             223     5.2            212
     Governmental                               173     (1.7)             176    15.8            152
     Revenue Sharing Refund                      (5)      -                 -      -               -
     Retroactive Retail Rate Refund             (35)      -                 -      -               -
                                          ----------              ------------            -----------
         Total Retail Revenues                2,720     (2.7)           2,796    11.8          2,502
     Wholesale                                  230    (20.1)             288     4.3            276
     Unbilled                                    (3)      -              (22)      -              18
     Miscellaneous                              115    (23.8)             151    98.7             76
                                          ----------              ------------            -----------
         Total Electric Revenues             $3,062     (4.7)%         $3,213    11.9%        $2,872
     ------------------------------------------------------------------------------------------------
          (a)  Florida  Power  electric  revenues are included in the  Company's
               results  of  operations  since  November  30,  2000,  the date of
               acquisition.  Florida  Power  Electric's  full year of revenue is
               included for comparative purposes only.
</TABLE>

Florida  Power's  electric  energy sales for the years ended  December 31, 2002,
2001 and 2000 and the  percentage  change by year and by  customer  class are as
follows (in thousands of mWh):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------
     Customer Class                         2002      % Change       2001      % Change    2000 (b)
     ------------------------------------------------------------------------------------------------
     Residential                             18,754      6.5%          17,604     2.9%        17,116
     Commercial                              11,420      3.2           11,061     2.3         10,813
     Industrial                               3,835     (1.0)           3,872    (8.9)         4,249
     Governmental                             2,850      4.5            2,726     2.7          2,654
                                          ----------              ------------            -----------
         Total Retail Energy Sales           36,859      4.5           35,263     1.2         34,832
     Wholesale                                4,180    (11.4)           4,719    (9.4)         5,209
     Unbilled                                     5       -              (511)      -            344
                                          ----------              ------------            -----------
         Total mWh sales                     41,044      4.0%          39,471    (2.3%)       40,385
     ------------------------------------------------------------------------------------------------
          (b)  Florida Power electric energy sales are included in the Company's
               results  of  operations  since  November  30,  2000,  the date of
               acquisition.  Florida  Power  Electric's  full  year of  sales is
               included for comparative purposes only.
</TABLE>

Florida Power electric revenues  decreased $151.1 million from 2001 to 2002. The
revenue  declines  were  driven by the $119.2  million  impact of the rate case,
mentioned previously.  Additionally,  wholesale revenues declined $58.1 million,
driven primarily by a contract that was not renewed.  Year-over-year comparisons
were also  unfavorably  impacted by the  recognition of $63.0 million of revenue
deferred from 2000 to 2001. Partially offsetting the unfavorable revenue impacts
was growth in the residential  (approximately  29,000 additional  customers) and
commercial   (approximately   4,000  additional   customers)  customer  classes.
Additional offsets included weather  conditions,  primarily a warmer than normal
summer in 2002, and an increase in other service  revenue,  resulting  primarily
from increased rates allowed under the rate case  settlement,  along with higher
transmission wheeling revenues.

Residential and commercial sales increased in 2001 and reflect  continued growth
in the number of customers served by Florida Power Electric, partially offset by
milder weather and a downturn in the economy.  Florida Power Electric added over
35,000 new customers in 2001.  Industrial sales declined in 2001 due to weakness
in the manufacturing  sector and phosphate industry,  which were affected by the
economic downturn.  Sales to wholesale customers  decreased for 2001,  primarily
due to the mild weather.

Expenses

Fuel used in generation and purchased power was $1.37 billion for the year ended
December  31,  2002,  a decrease of $58.8  million  from 2001.  The  decrease is
primarily  due  to a  lower  recovery  of  fuel  expense  that  resulted  from a
mid-course  correction of Florida Power Electric's fuel cost recovery clause, as
part of the rate settlement,  and lower purchased power costs,  partially offset
by an increase in coal prices and volume from high system requirements. Fuel and
purchased power expenses are recovered  primarily  through cost recovery clauses
and,  as such,  have no  material  impact  on  operating  results.  Fuel used in
generation and purchased power was $1.43 billion for the year ended December 31,
2001 and $94.8 million for the one month of 2000.

                                       48
<PAGE>

Operations and maintenance expense increased $85.1 million in 2002 when compared
to $487.1  million in 2001,  due primarily to a reduced  pension credit of $30.8
million,  increased  costs related to the  Commitment  to Excellence  program of
$11.3  million,  and an  increase  in other  salary and  benefit  costs of $21.5
million  related  partially  to  increased  medical  costs.  The  Commitment  to
Excellence  program was  initiated in 2002 to improve  service and  reliability.
Operations and maintenance  expense was $152.7 million for the one month of 2000
and included merger-related charges.

Depreciation  and  amortization  expense  decreased  $158.1 million in 2002 when
compared  to  $453.0  million  in 2001.  In  addition  to the  depreciation  and
amortization  reduction of approximately $79.0 million related to the rate case,
depreciation  declined  an  additional  $97.0  million  related  to  accelerated
amortization on the Tiger Bay regulatory asset, which was created as a result of
the early termination of certain long-term cogeneration contracts.  See Note 15B
to the Progress Energy consolidated  financial  statements for further detail on
the rate case.  Florida Power Electric  amortizes the regulatory asset according
to a plan approved by the Florida Public Service Commission in 1997 and plans to
fully  amortize  the  asset  by the end of  2003.  In  2001,  $97.0  million  of
accelerated  amortization  was recorded on the Tiger Bay  regulatory  asset,  of
which $63.0 million was  associated  with deferred  revenue from 2000 and had no
impact on 2001 earnings. Depreciation and amortization expense was $28.9 million
for the one month of 2000.

In 2002,  $19.9  million  of the tax  benefit  that was  previously  held at the
Company's holding company (see earlier discussion in the CP&L Electric segment),
was allocated to Florida Power Electric.  Other fluctuations in income taxes are
primarily due to changes in pretax income.

Diversified Businesses

The Company's diversified  businesses consist primarily of the Progress Ventures
segment,  the Rail Services  segment,  and Progress  Telecom,  Caronet,  SRS and
holding company operations,  which are in the Other segment and are explained in
more detail below.

Progress Ventures

Progress  Ventures  contributed  segment  income of $271.1  million  and  $288.7
million for 2002 and 2001, respectively. These amounts included wholesale energy
marketing and  immaterial  trading net income of $73.0 million and $86.7 million
in 2002 and 2001, respectively,  that Progress Ventures managed on behalf of the
utilities.  Due to the creation of Progress Ventures in 2000 and the acquisition
of Progress  Fuels'  subsidiaries  through the FPC  acquisition,  the results of
operations for the Progress Ventures segment are not comparable between 2001 and
2000.

The  Progress  Ventures  segment  operations  include  nonregulated   generation
operations;  natural  gas  exploration  and  production;  coal fuel  extraction,
manufacturing and delivery;  and energy marketing and limited trading activities
on behalf of the utility  operating  companies  as well as for its  nonregulated
plants.  Progress  Ventures'  results for 2002 were impacted  unfavorably by the
weak  energy  market  and  lower  synthetic  fuel  sales,  offset  partially  by
additional earnings from placing in service additional  nonregulated  generation
plants and the purchase of Westchester Gas Company.

Progress Ventures'  nonregulated  generation  operations generated net income of
$34.7  million and $4.3  million in 2002 and 2001,  respectively.  In 2001,  the
operations included one merchant plant with a 315-megawatt  capacity. In 2002, a
plant was  transferred  from the CP&L  Electric  regulated  segment to  Progress
Ventures,  one  operational  plant was  purchased  from LG&E Energy  Corporation
(LG&E. See Note 2A to the Progress Energy  consolidated  financial  statements),
and  one   additional   plant  was  placed  into  service  upon   completion  of
construction.  At the end of 2002,  plants with 1,554 megawatts of capacity were
operational.  This  increase in capacity  drove the increase in net income.  The
earnings potential of the increased capacity was partially offset by the general
softness in the energy market in 2002.  The Company has  contracts  representing
63%,  69%,  and 25% of  planned  production  capacity  for  2003  through  2005,
respectively.  The 2005 decline  results from the expiration of four  contracts.
The Company is actively  pursuing  opportunities  with the current customers and
other potential customers.

Progress Ventures' subsidiary,  MPC Generating,  LLC, had two tolling agreements
for  output on one of its  units  with  Dynegy,  Inc.  through  June  2008.  The
contracts with Dynegy were  terminated in December 2002. The Company  expects to
recognize a gain in connection with the termination in the first quarter of 2003
if certain  related  contingencies  are resolved,  but does not currently have a
customer for the output of the 160 megawatt unit.

                                       49
<PAGE>

In 2001,  Progress  Ventures' natural gas exploration and production  operations
included the operations of Mesa  Hydrocarbons,  Inc. (Mesa),  which owns natural
gas reserves and operates  wells in Colorado and sells  natural gas. In 2002, it
also included similar operations of Westchester Gas Company.  See Note 2B to the
Progress  Energy  consolidated   financial  statements  for  discussion  of  the
Westchester Gas Company  acquisition.  These gas operations generated net income
of $9.6 million and $5.3 million in 2002 and 2001, respectively. Westchester Gas
Company produced 5.8 million cubic feet of gas in 2002, which represented 49% of
the  combined  production  for the year.  This  increased  production  drove the
earnings increase from 2001 to 2002.

Progress Ventures' coal fuel extraction,  manufacturing and delivery  operations
generated  net income of $166.4  million  and  $198.4  million in 2002 and 2001,
respectively.  The Progress  Ventures coal group  produced and sold 11.2 million
and 13.3 million tons of synthetic  fuel in 2002 and 2001.  The  production  and
sale of the synthetic fuel from these facilities  generate operating losses, but
qualify for tax credits  under Section 29 of the Internal  Revenue  Code,  which
more than offset the effects of such losses.  See "Synthetic Fuels " under OTHER
MATTERS below for additional discussion of these tax credits. The sales resulted
in tax credits of $291.0 million and $349.3 million being recognized in 2002 and
2001,  respectively.  The Company is pursuing selling a portion of the synthetic
fuel operations.

Progress Ventures' energy marketing and trading operations  generated net income
of $69.1  million and $86.7 million in 2002 and 2001,  respectively.  This group
focuses on marketing and selling wholesale power and limited financial  trading.
Wholesale  marketing  generated  $77.2  million and $90.2 million of the group's
earnings in 2002 and 2001,  respectively.  The earnings  reductions from 2001 to
2002 are mainly  attributable to reduced  margins for wholesale  electric sales.
This group also manages  financial  trades of power.  Financial trades generated
net losses of $8.1  million  and $3.5  million  in 2002 and 2001,  respectively,
including associated overhead costs. The primary driver of the increased loss in
2002 was the higher overhead  associated with the plan to grow the marketing and
trading  activities; however, the Company recently announced plans to reduce the
scope of its trading activities.

Rail Services

Rail  Services'  operations  represent the  activities of Progress Rail Services
Corporation   (Progress  Rail)  and  include  railcar  and  locomotive   repair,
trackwork,  rail parts reconditioning and sales, scrap metal recycling,  railcar
leasing and other rail related  services.  Rail  Services'  results for the year
ended  December 31, 2001,  included Rail Services'  cumulative  revenues and net
loss from the date of acquisition,  November 30, 2000, because Rail Services had
been held for sale from the date of  acquisition  through the second  quarter of
2001.

Rail Services  contributed net losses of $41.7 million and $12.1 million for the
years  ended  December  31,  2002 and 2001,  respectively.  The net loss in 2002
includes a $40.1 million after-tax estimated  impairment on assets held for sale
related to Railcar  Ltd., a leasing  subsidiary  of Progress  Rail.  The Company
intends to sell the assets of Railcar Ltd. in 2003 and has reported these assets
as  assets  held for  sale.  See  Note 3B to the  Progress  Energy  consolidated
financial statements for discussion of this planned divestiture.  Rail Services'
results  for both years were  affected  by a downturn  in the  overall  economy,
decreases in rail service  procurement by major  railroads and a downturn in the
domestic scrap market.  Rail  Services' 2002 results were favorably  impacted by
aggressive  cost  cutting,   new  business   opportunities   and   restructuring
initiatives.

An SEC order  approving the merger of FPC requires the Company to divest of Rail
Services by November 30, 2003.  The Company is actively  pursuing  alternatives,
but does not  expect to find the right  divestiture  opportunity  by that  date.
Therefore, the Company plans to seek an extension from the SEC.

Other

Progress  Energy's  Other  segment  primarily  includes the  operations  of SRS,
Progress  Telecom and Caronet.  The results of NCNG have been  excluded from the
Other segment because of its  classification as a discontinued  operation.  This
segment also includes other nonregulated  operations of CP&L and FPC, as well as
holding company results and consolidation and elimination adjustments. The Other
segment had a net loss from  continuing  operations of $439.9 million and $427.4
million  in  2002  and  2001,  respectively,  and  net  income  from  continuing
operations  of $42.6  million in 2000.  The increase in the net loss in 2002 was
primarily  related to  impairments  and other charges in the  telecommunications
group and the  reallocation of favorable  income tax benefits to other segments.
These charges are partially  offset by the elimination of goodwill  amortization
of $89.7 million and the favorable impact of the contingent  value  obligations,
which are  discussed  below.  The decrease in earnings for 2001 when compared to
2000 is primarily due to after-tax charges of $148.1 million from the assessment
of the recoverability of the Interpath  investment and certain assets in the SRS
subsidiary,  increases in after-tax interest expense for holding company debt of
$159.0  million and goodwill  amortization  of $82.7 million  resulting from the
acquisition of FPC. In addition, the Other segment net income in 2000 includes a
$121.1 million after-tax gain on sale of assets, as described more fully below.

                                       50
<PAGE>

SRS was  engaged in  software  sales and  energy  services  to help  industrial,
commercial  and  institutional  customers  manage  energy  costs.  In 2002,  SRS
refocused the business on energy services in the southeastern  United States and
consolidated remaining operations with other retail activities.  SRS net losses,
excluding  after-tax  impairments and other charges  discussed below, were $13.3
million,  $7.2 million and $0.8 million for 2002,  2001 and 2000,  respectively.
The earnings  decline from 2001 to 2002 resulted from a $3.8 million loss on the
sale of the assets of several  divisions and from  increased  legal fees. Due to
the historical  losses at SRS and the decline of the market value for technology
companies,  a valuation study was obtained to help assess the  recoverability of
SRS's long-lived  assets in 2001.  Based on this assessment,  an after-tax asset
impairment and other charges  (primarily legal expenses)  totaling $40.7 million
were recorded in 2001. See Note 7 to the Progress Energy consolidated  financial
statements  for further  information on this  impairment  and other charges.  In
addition,  the Company recorded after-tax investment impairments of $4.9 million
for other-than-temporary declines in certain investments of SRS in 2001.

Progress  Telecom  and  Caronet had  combined  net losses of $229.0  million and
$110.4 million for 2002 and 2001,  respectively.  In 2000, Caronet combined with
one month of Progress Telecom contributed net income of $79.9 million.

Progress Telecom and Caronet provide broadband capacity services, dark fiber and
wireless  services in Florida and the eastern United States.  Due to the decline
of the  telecommunications  industry and continued operating losses, the Company
obtained a  valuation  study in 2002 to assess the  recoverability  of  Progress
Telecom's and Caronet's long-lived assets. Based on these valuation studies, the
Company  recorded an after-tax  impairment  of $190.4  million and other related
after-tax charges,  primarily inventory adjustments,  of $18.1 million. See Note
7A  to  the  Progress  Energy  consolidated  financial  statements  for  further
information on this impairment and other charges.

Effective  June  28,  2000,  Caronet  contributed  the  net  assets  used in its
application  service provider business to a newly formed company named Interpath
Communications,  Inc.  (Interpath).  In May 2002,  Interpath merged with a third
party,  diluting  Caronet's  ownership  interest from 35% to 19% and reduced the
voting interest from 15% to 7%. The Company obtained  valuation  studies in 2001
and again in 2002, after the merger of Interpath. As a result of these valuation
studies, the Company recorded impairments for  other-than-temporary  declines in
the fair  value of its  investment  in  Interpath  of $16.3  million  and $102.4
million  in 2002 and  2001,  respectively.  See Note 7B to the  Progress  Energy
consolidated financial statements for further information on this impairment.

In  2000,  Caronet  sold  its 10%  limited  partnership  interest  in  BellSouth
Carolinas PCS, resulting in an after-tax gain of $121.1 million.  See Note 3D to
the Progress Energy consolidated financial statements for further details on the
sale.

Excluding the impairments, other charges and the gain on the sale of the limited
partnership interest discussed above,  Progress Telecom and Caronet had combined
remaining losses of $4.2 million,  $8.0 million and $41.2 million for 2002, 2001
and 2000,  respectively.  Lower  depreciation  resulting  from the write-down of
impaired  assets  contributed to the decrease in the remaining loss from 2002 to
2001.  The  reduction  in the  remaining  loss in 2001,  when  compared to 2000,
results from the removal of the Interpath operations.

The Other segment also includes  Progress  Energy's holding company results.  As
part of the  acquisition  of FPC,  goodwill of  approximately  $3.6  billion was
recorded, and amortization of $89.7 million in 2001 and $7.0 million in 2000 was
included in the Other segment.  In accordance  with SFAS No. 142,  "Goodwill and
Other  Intangible  Assets,"  effective  January 1, 2002,  the  Company no longer
amortizes  goodwill.  At December 31, 2002, the Company had  approximately  $3.7
billion of unamortized goodwill.  See Note 6 to the Progress Energy consolidated
financial statements for more details on goodwill.

Net pre-tax  interest  charges in the Other segment were $270.2 million,  $253.1
million and $5.2 million, for 2002, 2001 and 2000, respectively. The increase in
2002, when compared to 2001, was primarily  related to increased debt associated
with the  purchase of  generating  plants.  This was  partially  offset by lower
interest rates and $18.9 million of interest  capitalization  in 2002 related to
the building of the  nonregulated  generating  plants.  The increase in interest
from  2000 to 2001  was  primarily  related  to the  debt  used to  finance  the
acquisition of FPC.

According to an SEC order under PUHCA, Progress Energy's tax benefit not related
to acquisition  interest expense is to be allocated to profitable  subsidiaries.
Therefore,  the tax benefit  that was  previously  held in the holding  company,
included in the Other  segment,  was  allocated to the  profitable  subsidiaries
effective with 2002. The allocation has no impact on consolidated tax expense or
earnings.  However,  in 2002, the allocation  increased the Other  segment's tax
expense $55.4 million with  offsetting  decreases in other  segments  (primarily
CP&L Electric and Florida Power Electric).

                                       51
<PAGE>

Progress  Energy  issued 98.6 million  contingent  value  obligations  (CVOs) in
connection  with the FPC  acquisition.  Each CVO represents the right to receive
contingent  payments based on the  performance of four synthetic fuel facilities
owned by Progress Energy.  The payments,  if any, are based on the net after-tax
cash flows the  facilities  generate.  At December 31, 2002,  2001 and 2000, the
CVOs had a fair market value of approximately  $13.8 million,  $41.9 million and
$40.4 million,  respectively.  Progress  Energy  recorded an unrealized  gain of
$28.1 million for the year ended  December 31, 2002, an unrealized  loss of $1.5
million  for the year ended  December  31, 2001 and an  unrealized  gain of $8.9
million for the month ended  December  31,  2000,  to record the changes in fair
value of CVOs,  which had  average  unit  prices  of  $0.14,  $0.43 and $0.41 at
December 31, 2002, 2001 and 2000, respectively.

Discontinued Operations

In 2002, the Company  approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. As a result of this action, the operating results of NCNG were reclassified
to discontinued  operations for all reportable periods.  Progress Energy expects
to sell NCNG for net proceeds of approximately $400 million, which results in an
estimated  after-tax loss on the sale of the assets of $29.4 million,  including
the impact of interest expense allocated to NCNG, as discussed in Note 3A to the
Progress Energy consolidated financial statements.

Application of Critical Accounting Policies and Estimates

The Company  prepared its consolidated  financial  statements in accordance with
accounting  principles  generally  accepted in the United  States.  In doing so,
certain  estimates  were made that were  critical  in nature to the  results  of
operations.  The following discusses those significant estimates that may have a
material  impact on the financial  results of the Company and are subject to the
greatest amount of subjectivity. Senior management has discussed the development
and selection of these critical  accounting policies with the Audit Committee of
the Company's Board of Directors.

Utility Regulation

The Company's  regulated  utilities segments are subject to regulation that sets
the prices  (rates) the Company is  permitted to charge  customers  based on the
costs that regulatory agencies determine the Company is permitted to recover. At
times,  regulators  permit the future recovery through rates of costs that would
be  currently  charged to expense by a  nonregulated  company.  This  ratemaking
process  results  in  deferral  of  expense  recognition  and the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing  regulatory  framework in each state in which the Company  operates,  a
significant  amount  of  regulatory  assets  has  been  recorded.   The  Company
continually reviews these assets to assess their ultimate  recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially  adverse  legislative,  judicial or regulatory actions in
the  future.   Additionally,   the  state  regulatory   agencies  often  provide
flexibility in the manner and timing of the  depreciation  of property,  nuclear
decommissioning  costs and amortization of the regulatory assets. Note 15 to the
Progress  Energy   consolidated   financial   statements   provides   additional
information related to the impact of utility regulation on the Company.

Asset Impairments

The Company  evaluates the carrying  value of long-lived  assets for  impairment
whenever  indicators exist.  Examples of these indicators include current period
losses combined with a history of losses, or a projection of continuing  losses,
or a significant decrease in the market price of a long-lived asset group. If an
indicator exists,  the asset group held and used is tested for recoverability by
comparing the carrying  value to the sum of  undiscounted  expected  future cash
flows  directly  attributable  to the asset  group.  If the  asset  group is not
recoverable  through  undiscounted  cash  flows or if the  asset  group is to be
disposed of, an impairment  loss is recognized  for the  difference  between the
carrying  value and the fair value of the asset group. A high degree of judgment
is required in developing  estimates  related to these  evaluations  and various
factors  are  considered,  including  projected  revenues  and costs and  market
conditions.

During 2002, the Company recorded pre-tax long-lived asset impairments of $305.0
million related to its telecommunications  business. See Note 7A to the Progress
Energy  consolidated  financial  statements  for  further  information  on  this
impairment  and other  charges.  The fair value of these  assets was  determined
using an external  valuation  study heavily  weighted on a discounted  cash flow
methodology and using market approaches as supporting  information.  However, if
the   telecommunications   market   continues  to  deteriorate,   the  Company's
telecommunications-related assets may be further adversely affected.

The Company also  continually  reviews its  investments  to determine  whether a
decline in fair value below the cost basis is other-than-temporary.  During 2002
and 2001, the Company recorded pre-tax impairments to the cost method investment
in Interpath of $25.0 million and $156.7 million,  respectively.  The fair value
of this  investment was  determined  using an external  valuation  study heavily
weighted on a discounted cash flow  methodology  and using market  approaches as
supporting information.  These cash flows include numerous assumptions including
the pace at which the  telecommunications  market  will  rebound.  In the fourth
quarter of 2002,  the Company sold its  remaining  interest in  Interpath  for a
nominal amount.

                                       52
<PAGE>

Goodwill

Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible  Assets,"  which  requires that goodwill be tested for  impairment at
least annually and more frequently when indicators of impairment exist. See Note
6 to the Progress Energy consolidated financial statements for further detail on
goodwill.  Accounting standards require a two step goodwill impairment test. The
first step, used to identify  potential  impairment,  compares the fair value of
the reporting  unit with its carrying  amount,  including  goodwill.  The second
step,  used to measure the amount of the impairment loss if step one indicates a
potential  impairment,  compares  the implied fair value of the  reporting  unit
goodwill with the carrying amount of the goodwill.

The Company completed the initial  transitional  goodwill impairment test, which
indicated that the Company's goodwill was not impaired as of January 1, 2002. In
addition,  the Company  performed the annual  goodwill  impairment test for CP&L
Electric and Florida  Power  Electric  during  2002,  which  indicated  that the
Company's  goodwill was not  impaired.  In  connection  with the pending sale of
NCNG, the Company reviewed the carrying value of NCNG,  including  goodwill,  as
discussed in Note 3A to the Progress Energy consolidated financial statements.

During 2002, the Company  completed the  acquisition of two electric  generating
projects,  Walton  County  Power,  LLC and  Washington  County  Power,  LLC. The
acquisitions  resulted in goodwill of $64.1  million.  The Company has completed
the purchase price  allocation and will perform the annual  goodwill  impairment
test in the first  quarter of 2003.  During  2002,  the  Company  also  acquired
Westchester Gas Company. The purchase price has been preliminarily  allocated to
fixed assets  including oil and gas properties,  based on the  preliminary  fair
values  of  the  assets  acquired.   The  purchase  price  allocation  for  this
acquisition  will be finalized in the second  quarter of 2003, and if any of the
purchase  price  is  ultimately  allocated  to  goodwill,   an  annual  goodwill
impairment test will be performed at that time.

Synthetic Fuels Tax Credits

Progress Energy, through the Progress Ventures business unit, produces synthetic
fuel from coal fines.  The  production  and sale of the synthetic fuel qualifies
for tax credits  under  Section 29 of the Internal  Revenue Code (Section 29) if
certain  requirements are satisfied,  including a requirement that the synthetic
fuel differs  significantly  in chemical  composition from the feedstock used to
produce such synthetic  fuel. Any synthetic fuel tax credit amounts not utilized
are carried  forward  indefinitely  and are  included  in deferred  taxes on the
accompanying  Consolidated  Balance  Sheet.  See Note 20 to the Progress  Energy
consolidated  financial statements for further information on the synthetic fuel
tax credits.  All of Progress  Energy's  synthetic fuel facilities have received
private letter rulings from the Internal  Revenue  Service (IRS) with respect to
their  operations.  These tax credits  are subject to review by the IRS,  and if
Progress  Energy fails to prevail through the  administrative  or legal process,
there could be a significant tax liability owed for previously  taken Section 29
credits, with a significant impact on earnings and cash flows.

Pension and Other Postretirement Benefits

The  Company's  reported  costs of  providing  pension and other  postretirement
benefits  (described in Note 18 to the Progress  Energy  consolidated  financial
statements),  primarily  health  benefits,  are  dependent  on numerous  factors
resulting from actual plan experience and assumptions of future experience.  For
example, such costs are impacted by employee demographics,  changes made to plan
provisions,  and key  actuarial  assumptions  such as  rates of  return  on plan
assets,  discount rates used in determining benefit obligations and annual costs
and, for other postretirement benefits, medical trend rates.

Due to a  decline  in  market  interest  rates for  high-quality  (AAA/AA)  debt
securities,  which are used as the benchmark for setting the discount  rate, the
Company  lowered the discount  rate to 6.60% at December  31,  2002,  which will
increase the 2003 benefit costs recognized. In addition, the continuing declines
in the equity  markets  have  adversely  affected the fair value of plan assets,
which will also increase the benefit costs  recognized in 2003.  Evaluations  of
the effects of these factors has not been completed,  but the Company  estimates
that 2003 total cost for pension and other postretirement benefits will increase
by approximately $40 million over the amount recorded in 2002, due in large part
to these  factors.  The  majority  of that  increase  has been  anticipated  and
reflected in the  Company's  budgeting/forecasting  process.  Recoveries  in the
level of interest rates and equity markets would, correspondingly, have positive
effects on future years' benefit cost recognition.

                                       53
<PAGE>

The  Company  has  substantial  pension  plan  assets,  with  a  fair  value  of
approximately  $1.4 billion at December 31, 2002. The Company's expected rate of
return  on  pension  plan  assets  has  been,  and will  continue  to be for the
foreseeable future, 9.25%. Under the accounting standard for pension accounting,
the expected rate of return used in pension cost recognition is a long-term rate
of  return;  therefore,  the  Company  would  only  adjust  that  return  if its
fundamental  assessment of the debt and equity markets changes or its investment
policy changes significantly.  The Company continues to believe that its pension
plan's  investment  mix supports  the  long-term  rate of 9.25% being used.  The
Company did not increase the  expected  long-term  rate of return in response to
the  abnormally  high  market  return  levels of the latter  1990's and does not
believe it is appropriate  to adjust the rate downward  because of recent market
declines.  A 0.25%  change in the  expected  rate of return  for 2002 would have
changed 2002 pension cost by approximately $4.5 million.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Progress Energy is a registered  holding company and, as such, has no operations
of its own. The ability to meet its  obligations  is primarily  dependent on the
earnings and cash flows of its two electric  utilities  and the ability of those
subsidiaries to pay dividends or repay funds to Progress Energy.

The  cash   requirements   of  Progress   Energy   arise   primarily   from  the
capital-intensive  nature  of its  electric  utility  operations  as well as the
expansion  of its  diversified  businesses,  primarily  those  of  the  Progress
Ventures segment.

Progress Energy relies upon its operating cash flow,  generated primarily by its
two regulated electric utility subsidiaries, commercial paper facilities and its
ability to access  long-term  capital markets for its liquidity  needs.  Since a
substantial majority of Progress Energy's operating costs are related to its two
regulated electric utilities, a significant portion of these costs are recovered
from customers through fuel and energy cost recovery clauses.

During 2003, the Company  expects to realize  approximately  $400 million of net
cash proceeds from the sale of NCNG. The Company also expects to receive between
$100  million  and $300  million of proceeds  through  the sale of common  stock
issued   through  the  Progress   Energy  Direct  Stock  Purchase  and  Dividend
Reinvestment Plan, and its 401(k) Savings and Stock Ownership Plan.

Progress  Energy's cash from  operations and common stock  issuance  proceeds in
2003 are expected to fund its capital  expenditures.  Progress Energy expects to
use the proceeds from the sale of NCNG to reduce  indebtedness then outstanding.
To the extent  necessary,  incremental  borrowings or commercial paper issuances
may also be used as a source of liquidity.

Progress Energy  forecasts its liquidity  resources to be sufficient to fund its
current  business plans.  Risk factors  associated with commercial  paper backup
credit  facilities  and credit  ratings  are  discussed  below as well as in the
Company's SEC filings.

The following discussion of Progress Energy's liquidity and capital resources is
on a consolidated basis.

Cash Flows from Operations

Cash from  operations is the primary source used to meet operating  requirements
and capital expenditures.  Total cash from operations for 2002 was $1.6 billion,
up $175 million from 2001.

The increase in cash from operating  activities for 2001 when compared with 2000
is largely the result of the  November 30,  2000,  acquisition  of FPC. The 2000
results reflected one month's cash from operations of FPC.

Progress  Energy's  two  electric  utilities  produced   approximately  112%  of
consolidated  cash from operations in 2002. It is expected that the two electric
utilities  will  continue to produce a majority of the  consolidated  cash flows
from  operations  over the next several years as its  nonregulated  investments,
primarily  generation  assets,  are placed  into  service  and begin  generating
operating cash flows. In addition,  Progress Ventures' synthetic fuel operations
do not  currently  produce  positive  operating  cash flow  primarily due to the
difference in timing of when tax credits are recognized for financial  reporting
purposes and when tax credits are realized for tax purposes.

Total cash from  operations  provided the funding for  approximately  72% of the
Company's property additions, nuclear fuel expenditures and diversified business
property  additions  during 2002. The remaining funds were obtained through debt
and equity  issuances by Progress  Energy as discussed  below.  Progress  Energy
expects its  operating  cash flow to exceed its projected  capital  expenditures
beginning in 2004.

                                       54
<PAGE>

Investing Activities

Cash used in investing  activities  was $2.2 billion in 2002,  up  approximately
$556  million when  compared  with 2001.  The  increase is due  primarily to the
expansion of PVI's  generation  portfolio.  In February  2002, PVI purchased two
generating projects from LG&E Energy Corp. for approximately $350 million.

Cash used in investing  was $1.7 billion in 2001,  up $663 million when compared
with 2000 after adjusting for the acquisition of Florida Progress.  The increase
is due primarily to the expansion of PVI's generation  portfolio and the absence
of  proceeds  from  the  sale in 2000 of the  BellSouth  Carolinas  PCS  limited
partnership interest.

Capital  expenditures for Progress Energy's regulated  electric  operations were
$1.2 billion or approximately 55% of consolidated  capital expenditures in 2002.
As shown in the table below,  the Company  anticipates  that the  proportion  of
nonregulated  capital  spending  to total  capital  expenditures  will  decrease
substantially  in 2003 when  compared  with  2002.  The  decrease  reflects  the
expected completion of PVI's nonregulated  generation portfolio by the summer of
2003.  Progress  Energy expects the majority of its capital  expenditures  to be
incurred at its regulated operations.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

         (Dollars in millions):
                                            Actual                           Forecasted
                                         -----------      ------------------------------------------------
                                            2002             2003              2004               2005
                                         -----------      ------------     --------------      -----------
    Regulated capital expenditures          $ 1,174           $ 1,100            $ 1,050          $ 1,040
    Nuclear fuel expenditures                    81               120                100              120
    AFUDC - borrowed funds                       (8)              (20)               (20)             (20)
    Nonregulated capital expenditures           935               290                110              110
                                         -----------      ------------     --------------      -----------
         Total                              $ 2,182           $ 1,490            $ 1,240          $ 1,250
                                         ===========      ============     ==============      ===========
</TABLE>

Regulated  capital  expenditures  in the table above include total  expenditures
from 2003 through 2005 of approximately  $147 million expected to be incurred at
regulated  fossil-fueled  electric generating  facilities to comply with Section
110 of the Clean Air Act, referred to as the NOx SIP Call.

On June 20,  2002,  legislation  was  enacted in North  Carolina  requiring  the
state's electric  utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from  coal-fired  power  plants.  CP&L expects its capital costs to meet
these emission targets will be approximately $813 million by 2013. For the years
2003 through 2005, the Company  expects to incur  approximately  $258 million of
total capital costs associated with this  legislation,  which is included in the
table  above.  See  Note  24  to  the  Progress  Energy  consolidated  financial
statements and "Current  Regulatory  Environment"  under OTHER MATTERS below for
more information on this legislation.

CP&L has  determined  that its  external  funding  levels do not fully  meet the
nuclear decommissioning  financial assurance levels required by the U.S. Nuclear
Regulatory  Commission.  The funding levels have been adversely  affected by the
recent declines in the equity markets.  The total shortfall is approximately $95
million (2010  dollars) for Robinson Unit No. 2, $82 million (2016  dollars) for
Brunswick  Unit No. 1 and $99 million (2014  dollars) for Brunswick  Unit No. 2.
CP&L  is  currently  evaluating  the  alternatives  for  meeting  the  financial
assurance  requirements,  which primarily include  increasing annual deposits to
the external trust by an estimated $18.8 million  annually or obtaining a parent
company  guarantee.  The funding status for these facilities would be positively
affected  by a recovery  in the equity  markets  and by the  approval of license
extension  applications.  See  Note  1H  to  the  Progress  Energy  consolidated
financial statements for further discussion.

All projected capital and investment expenditures are subject to periodic review
and  revision  and may  vary  significantly  depending  on a number  of  factors
including,  but not limited to, industry restructuring,  regulatory constraints,
market volatility and economic trends.

Financing Activities

Cash provided by financing  activities  increased  approximately  $433.8 million
over 2001,  primarily due to issuances of long-term debt and common stock equity
by Progress Energy.

Cash provided by financing  activities  decreased by $3.4 billion when comparing
2001 to 2000.  This  decrease was due to the November 30, 2000,  acquisition  of
FPC, which was funded from the sale of short-term commercial paper. This funding
was  converted  to  long-term  debt  during  2001.  Excluding  the effect of the
acquisition financing, cash from financing activities increased slightly in 2001
when  compared with 2000,  primarily  due to the expansion of Progress  Energy's
nonregulated operations.

                                       55
<PAGE>

In  February  2002,  $50  million  of  Progress  Capital  Holdings,  Inc.  (PCH)
medium-term notes, 5.78% Series,  matured.  Progress Energy funded this maturity
through the issuance of commercial  paper. As of December 31, 2002, PCH had $223
million of fixed rate medium-term  notes.  The final  medium-term note is due in
May  2008.  Progress  Energy  intends  to  fund  these  maturing  notes  through
internally generated funds and the issuance of commercial paper.

In April 2002, Progress Energy issued $350 million of senior unsecured notes due
2007 with a coupon of 6.05% and $450 million of senior  unsecured notes due 2012
with a coupon  of  6.85%.  Proceeds  from  this  issuance  were used to pay down
commercial  paper,  which had been used in part to fund the  expansion  of PVI's
nonregulated  generation  portfolio,  including  the  acquisition  of generating
assets from LG&E.

In November  2002,  Progress  Energy issued 14.7 million shares of common stock.
Total net proceeds  from the issuance were  approximately  $600 million and were
used to pay down commercial paper.

The Company issued 2.1 million shares representing  approximately $86 million in
proceeds  from its  Dividend  Reinvestment  and  Stock  Purchase  Plan,  and its
employee benefit plans.

During 2002,  both CP&L and Florida  Power took  advantage of  historically  low
interest  rates and  refinanced  several  issues of  tax-exempt  debt as well as
certain taxable issues.

In February 2002, CP&L issued $48.5 million  principal  amount of First Mortgage
Bonds,  Pollution  Control  Series  W, Wake  County  Pollution  Control  Revenue
Refunding Bonds, 5.375% Series 2002 due February 1, 2017. On March 1, 2002, CP&L
redeemed $48.5 million principal amount of Pollution Control Revenue Bonds, Wake
County due April 1, 2019, at 101.5% of the principal amount of such bonds.

In July 2002,  Florida  Power  issued  approximately  $241  million of Pollution
Control Revenue Refunding Bonds, secured by First Mortgage Bonds.  Proceeds from
this  issuance  were used to redeem $241  million of Pollution  Control  Revenue
Bonds in August.  Also in July, $30 million of medium-term  notes, 6.54% Series,
matured.  Florida Power funded this maturity  through the issuance of commercial
paper.

In July 2002, CP&L issued $500 million of senior unsecured notes due 2012 with a
coupon of 6.5%.  Proceeds from this  issuance  were used to pay down  commercial
paper,  which had been used to redeem $500 million of CP&L Extendible  Notes due
October 28, 2009,  at 100% of the  principal  amount of such notes.  These notes
were redeemed July 29, 2002.

In September  2002,  CP&L redeemed $150 million of First  Mortgage  Bonds,  8.2%
Series,  due July 1, 2022 at 103.55% of the principal amount of such bonds. CP&L
redeemed these notes through the issuance of commercial paper.

In March 2002, Progress Genco Ventures, LLC (Genco), a PVI subsidiary,  obtained
a $440 million bank  facility  that is  restricted  for the use of expanding its
nonregulated  generation  portfolio,  which is expected to be  completed  by the
summer of 2003.  Borrowings  under this facility will be nonrecourse to Progress
Energy;  however,  the  Company  entered  into  certain  support  and  guarantee
agreements to ensure  performance  under  generation  construction and operating
agreements. In September 2002, $130 million of the bank facility was terminated,
reducing it to $310 million.  This amount includes a $50 million working capital
facility. The reduction was due to PVI's decision to reduce the expansion of its
nonregulated  generation  portfolio.  As of December 31, 2002,  $225 million was
outstanding under this facility.

As a registered  holding company under PUHCA,  Progress Energy obtains  approval
from  the  SEC  for  the  issuance  and  sale  of  securities  as  well  as  the
establishment of intracompany  extensions of credit.  In January 2002,  Progress
Energy requested an increase of $2.5 billion in its authority to issue long-term
securities,  increasing  the limit from $5.0  billion to $7.5  billion.  The SEC
approved the request on March 15, 2002. As of December 31, 2002, Progress Energy
has  regulatory  authority  to  issue  approximately  $1  billion  of  long-term
securities.

                                       56
<PAGE>

At December 31, 2002, the Company and its  subsidiaries  had committed  lines of
credit totaling $1.74 billion, for which there were no loans outstanding.  These
lines of credit support the Company's commercial paper borrowings. The following
table summarizes the Company's credit facilities (in millions):

                  Company                     Description           Total
      --------------------------------------------------------------------------

      Progress Energy         364-Day (expiring 11/11/03)           $   430.2
      Progress Energy         3-Year (expiring 11/13/04)                450.0
      CP&L                    364-Day (expiring 7/30/03)                285.0
      CP&L                    3-Year (expiring 7/31/05)                 285.0
      Florida Power           364-Day (expiring 4/01/03)                 90.5
      Florida Power           5-Year  (expiring 11/30/03)               200.0
                                                                 ---------------
          Total credit facilities                                   $ 1,740.7
                                                                 ===============

During 2002, in connection with renewals,  the Progress Energy and Florida Power
364-day   facilities  were  decreased  by  $120.0  million  and  $79.5  million,
respectively.

The Company's  financial policy precludes issuing  commercial paper in excess of
its  supporting  lines of credit.  At December  31,  2002,  the total  amount of
commercial paper outstanding was $695 million,  leaving approximately $1 billion
available for issuance. The Company is required to pay minimal annual commitment
fees to maintain its credit facilities.

In addition,  these  credit  agreements  and Genco's $310 million bank  facility
contain various terms and conditions that could affect the Company's  ability to
borrow under these  facilities.  These  include  maximum  debt to total  capital
ratios,   interest  coverage  tests,  a  material  adverse  change  clauses  and
cross-default provisions.

All of the credit facilities and Genco's bank facility include a defined maximum
total debt to total capital ratio.  Progress Energy's maximum  consolidated debt
ratio  reduces to 68%  effective  June 30, 2003.  As of December  31, 2002,  the
calculated  ratio  for  these  four  companies,  pursuant  to the  terms  of the
agreements, was as follows:

       Company                         Maximum Ratio    Actual Ratio (b)
       ------------------------------------------------------------------
       Progress Energy, Inc.                 70% (a)          62.4%
       Carolina Power & Light Company        65%              52.7%
       Florida Power Corporation             65%              48.6%
       Progress Genco Ventures, LLC          40%              24.8%

       (a)  Progress  Energy's  maximum debt ratio reduces to 68% effective June
            30, 2003.
       (b)  Indebtedness  as defined  by the bank  agreements  includes  certain
            letters  of credit  and  guarantees  which are not  recorded  on the
            Consolidated Balance Sheets.

In November 2002, Progress Energy's 364-day credit facility was amended to add a
financial  covenant for  interest  coverage.  This  covenant  requires  Progress
Energy's EBITDA to interest  expense to be at least 2.5 to 1. As of December 31,
2002, this ratio was 3.43 to 1. Genco's bank facility requires a minimum 1.25 to
1 debt service  coverage  ratio.  As of December 31, 2002,  Genco's debt service
coverage ratio was 7.65 to 1.

The credit facilities of Progress Energy,  CP&L, Florida Power and Genco include
a provision  under which lenders could refuse to advance funds in the event of a
material adverse change in the borrower's financial condition.

Each of these credit agreements contains  cross-default  provisions for defaults
of  indebtedness  in excess  of $10  million.  Under  these  provisions,  if the
applicable borrower or certain subsidiaries fail to pay various debt obligations
in excess of $10 million the lenders could accelerate payment of any outstanding
borrowing and  terminate  their  commitments  to the credit  facility.  Progress
Energy's  cross-default  provision  only  applies  to  Progress  Energy  and its
significant  subsidiaries (i.e. CP&L, Florida Progress,  Florida Power, PCH, PVI
and Progress Fuels).

Additionally,  certain of Progress  Energy's  long-term debt indentures  contain
cross-default  provisions for defaults of indebtedness in excess of $25 million;
these  provisions only apply to other  obligations of Progress  Energy,  not its
subsidiaries.  In the event that these  indenture  cross-default  provisions are
triggered,  the debt holders  could  accelerate  payment of  approximately  $4.8
billion  in  long-term  debt.  Certain   agreements   underlying  the  Company's
indebtedness  also  limit its  ability  to incur  additional  liens or engage in
certain types of sale and leaseback transactions.

The Company has on file with the SEC a shelf registration  statement under which
senior notes,  junior  debentures,  common and  preferred  stock and other trust
preferred  securities are available for issuance by the Company.  As of December
31, 2002, the Company had  approximately  $1 billion  available under this shelf
registration.

                                       57
<PAGE>

Progress  Energy and Florida  Power each have an  uncommitted  bank bid facility
authorizing each of them to borrow and re-borrow,  and have loans outstanding at
any time,  up to $300 million and $100  million,  respectively.  At December 31,
2002, there were no outstanding loans against these facilities.

CP&L  currently has on file with the SEC a shelf  registration  statement  under
which it can issue up to $500 million of various long-term  securities.  Florida
Power currently has filed  registration  statements  under which it can issue an
aggregate of $50 million of various long-term debt securities.  CP&L and Florida
Power expect to increase their shelf capacity in the second or third quarters of
2003.

The following table shows Progress Energy's capital structure as of December 31,
2002 and 2001:

                                          2002                       2001
                                  ---------------------       ------------------
      Common Stock                       38.2%                       36.7%
      Preferred Stock                     0.5%                        0.6%
      Total Debt                         61.3%                       62.7%

The amount  and timing of future  sales of  company  securities  will  depend on
market  conditions,  operating cash flow,  asset sales 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.

Credit Rating Matters

As of February 7, 2003,  the major credit  rating  agencies  rated the Company's
securities as follows:

                                                Moody's             Standard &
                                           Investors Service          Poor's
      Progress Energy, Inc.
      Corporate Credit Rating               Not Applicable             BBB+
      Senior Unsecured                           Baa2                  BBB
      Commercial Paper                           P-2                   A-2
      Carolina Power & Light Company
      Corporate Credit Rating               Not Applicable             BBB+
      Commercial Paper                           P-2                   A-2
      Senior Secured Debt                        A3                    BBB+
      Senior Unsecured Debt                      Baa1                  BBB+
      Subordinate Debt                           Baa2                  BBB
      Preferred Stock                            Baa3                  BBB-
      Florida Power Corporation
      Corporate Credit Rating               Not Applicable             BBB+
      Commercial Paper                           P-1                   A-2
      Senior Secured Debt                        A1                    BBB+
      Senior Unsecured Debt                      A2                    BBB+
      Preferred Stock                            Baa1                  BBB-
      FPC Capital I
      Preferred Stock*                           Baa1                  BBB-
      Progress Capital Holdings, Inc.
      Senior Unsecured Debt*                     A3                    BBB

         *Guaranteed by Florida Progress Corporation

These  ratings  reflect  the  current  views of  these  rating  agencies  and no
assurances can be given that these ratings will continue for any given period of
time.  However,  the Company monitors its financial  condition as well as market
conditions that could ultimately affect its credit ratings.

The Company and its  subsidiaries'  debt indentures and credit agreements do not
contain any "ratings  triggers"  which would cause the  acceleration of interest
and  principal  payments in the event of a ratings  downgrade.  However,  in the
event of a  downgrade  the  Company  and/or its  subsidiaries  may be subject to
increased  interest  costs on the credit  facilities  backing up the  commercial
paper programs.  The Company and its subsidiaries  have certain  contracts which
have  provisions  that are  triggered by a ratings  downgrade.  These  contracts
include counterparty trade agreements,  derivative  contracts,  certain Progress
Energy guarantees and various types of third party purchase agreements.  None of
these  contracts  would require any action on the part of Progress Energy or its
subsidiaries  unless the ratings  downgrade results in a rating below investment
grade.

The power supply agreement with Jackson Electric Membership Corporation that PVI
expects to acquire from Williams Energy  Marketing and Trading Company (See PART
I,  ITEM  1,  General,   Wholesale  Energy  Contract   Acquisition)  includes  a
performance  guarantee  that  Progress  Energy  will  assume.  In the event that
Progress  Energy's credit ratings fall below investment  grade,  Progress Energy
will be required to provide additional  security  for its  guarantee in form and
amount  acceptable  to Jackson.  See  Progress  Energy,  Inc.  Risk  Factors for
additional discussion.

                                       58
<PAGE>

In March 2002,  Standard & Poor's (S&P)  affirmed  Progress  Energy's  corporate
credit  rating of BBB+ and the ratings of Florida Power and CP&L but revised the
outlook  for all three  entities to negative  from  stable.  S&P stated that its
change  in  outlook   reflected   the   increased   business  risk  at  PVI  and
lower-than-projected  credit  protection  measures.  S&P  stated  that  Progress
Energy's  plan to divest of  non-core  assets and use the  proceeds  to pay down
acquisition-related debt is moving slower than S&P had expected. On September 4,
2002,  S&P  reaffirmed  Progress  Energy's  credit  ratings and  maintained  the
negative outlook.  The Company expects S&P to make a decision within the next 30
to 60 days. The Company cannot predict the outcome of this matter.

On February 7, 2003,  Moody's Investors Service (Moody's)  announced that it was
lowering Progress Energy, Inc.'s senior unsecured debt rating from Baa1 to Baa2,
and changing the outlook of the rating from  negative to stable.  Moody's  cited
the slower than planned pace of the Company's  efforts to pay down debt from its
acquisition of Florida  Progress as the primary  reason for the ratings  change.
Moody's  also  changed  the  outlook of  Florida  Power  Corporation  (A1 senior
secured) and Progress Capital  Holdings,  Inc. (A3 senior unsecured) from stable
to negative and lowered the trust  preferred  rating of FPC Capital I from A3 to
Baa1 with a negative outlook.

The  change in  outlook  by the  rating  agencies  has not  materially  affected
Progress Energy's access to liquidity or the cost of its short-term borrowings.

Fitch Ratings Service announced on February 14, 2003 it was assigning an initial
rating to Progress  Energy's senior unsecured debt of BBB-. No short-term rating
was  assigned.  Fitch also  announced  that it was  downgrading  the  ratings of
Florida Power and CP&L. The ratings outlook for the three entities is stable.

Florida  Power's senior secured rating was changed to A- from AA- and its senior
unsecured rating was changed to BBB+ from A+. Florida Power's  short-term rating
was changed to F-2 from F-1+.  CP&L's  senior  secured  rating was changed to A-
from A+ and its  senior  unsecured  rating was  changed  to BBB+ from A.  CP&L's
short-term rating was changed to F-2 from F-1.

Interest Rate Derivatives

Progress  Energy uses interest rate  derivative  instruments to manage the fixed
and variable rate debt components of its debt portfolio. The Company's long-term
objective is to maintain a debt portfolio mix of approximately 30% variable rate
debt,  with the balance  being fixed rate.  As of December  31,  2002,  Progress
Energy's variable rate and fixed rate debt comprised 18% and 82%,  respectively,
including the effects of interest rate derivatives.

During March,  April and May 2002,  Progress  Energy  converted  $1.0 billion of
fixed rate debt into  variable rate debt by executing  interest rate  derivative
agreements with a group of five banks. Under the terms of the agreements,  which
were  scheduled to mature in 2006 and 2007 and coincide with the maturity  dates
of the related debt issuances,  Progress Energy received a fixed rate and paid a
floating rate based on three-month  LIBOR.  These instruments were designated as
fair value  hedges  for  accounting  purposes.  In June  2002,  Progress  Energy
terminated  these  agreements.  The  terminations  resulted  in a $21.2  million
deferred  hedging gain reflected in long-term debt,  which will be amortized and
recorded as a reduction  to interest  expense  over the life of the related debt
issuances.

In August 2002,  Progress Energy  converted $800 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of four banks. Under the terms of the agreements, which were scheduled to mature
in 2006 and  coincide  with the  maturity  date of the  related  debt  issuance,
Progress  Energy  received  a fixed  rate  and  paid a  floating  rate  based on
three-month  LIBOR.  These  instruments were designated as fair value hedges for
accounting  purposes.   In  November  2002,  Progress  Energy  terminated  these
agreements.  The  terminations  resulted in a $14 million  deferred hedging gain
reflected in long-term debt, which will be amortized and recorded as a reduction
to interest expense over the life of the related debt issuance.

In December 2002, Progress Energy converted $350 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of two banks.  Under the terms of the agreements,  which are scheduled to mature
in 2007 and  coincide  with the  maturity  date of the  related  debt  issuance,
Progress  Energy  receives  a fixed  rate  and  pays a  floating  rate  based on
three-month  LIBOR.  These  instruments  are designated as fair value hedges for
accounting purposes.  At December 31, 2002, the value of these derivatives was a
$5.2 million asset position.

In December  2002,  Florida Power  entered into a Treasury Rate Lock  agreement,
with a notional  amount of $35 million,  to hedge the  interest  rate risk on an
anticipated  debt issuance.  At December 31, 2002, the value of this hedge was a
$0.5 million liability  position.  In January 2003, Florida Power entered into a
Treasury Rate Lock agreement,  with a notional  amount of $20 million,  to hedge
the  on an  anticipated  debt  issuance.  These  contracts are
designated as cash flow hedges for accounting purposes.

                                       59
<PAGE>

In January 2003,  Progress Energy converted $500 million of fixed rate debt into
variable rate by executing  interest  rate  derivative  contracts,  bringing its
variable rate percentage to 22.7%.  Under the terms of the agreements,  Progress
Energy  will  receive  a fixed  rate  and  will  pay a  floating  rate  based on
three-month  LIBOR.  These  instruments were designated as fair value hedges for
accounting purposes.

Progress Genco Ventures,  LLC has a floating rate credit facility that requires,
as part of the loan terms,  a cash flow hedge  against  floating  interest  rate
exposure.  In order to satisfy this  requirement,  Progress Genco Ventures,  LLC
entered into a series of interest rate collars during 2002 with notional amounts
up to a maximum of $195 million and a final  maturity date of March 20, 2007. At
December  31,  2002,  the  value of this  hedge  was a $12.3  million  liability
position.  See Note 16 to the Progress Energy consolidated  financial statements
for further discussion of interest rate derivatives.

Future Commitments

The following tables reflect Progress Energy's  contractual cash obligations and
other commercial commitments in the respective periods in which they are due.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)
--------------------------------------------------------------------------------------------------------------------
Contractual Cash
Obligations                     Total            2003        2004         2005        2006         2007  Thereafter
--------------------------------------------------------------------------------------------------------------------
Long-term debt                  $ 10,082        $ 275       $ 869        $ 355       $ 909        $ 899     $ 6,775
Capital lease                         45            3           3            3           3            3          30
  obligations
Operating leases                     293           76          59           35          25           20          78
Fuel                               5,439        1,681       1,070          914         908          851          15
Purchased power                    7,148          396         405          418         406          415       5,108
--------------------------------------------------------------------------------------------------------------------
Total                           $ 23,007      $ 2,431     $ 2,406      $ 1,725     $ 2,251      $ 2,188    $ 12,006

Other Commercial
Commitments                     Total            2003        2004         2005        2006         2007  Thereafter
--------------------------------------------------------------------------------------------------------------------
Standby letters of                  $ 48         $ 48         $ -          $ -         $ -          $ -         $ -
  credit
Guarantees and                       569           52          41           30          20           19         407
  other commitments
--------------------------------------------------------------------------------------------------------------------
Total                              $ 617        $ 100        $ 41         $ 30        $ 20         $ 19       $ 407
</TABLE>

Information  on the Company's  contractual  obligations  at December 31, 2002 is
included in the notes to the Progress Energy consolidated  financial statements.
Future debt maturities and lease  obligations are included in Note 8 and Note 12
to the Progress Energy  consolidated  financial  statements,  respectively.  The
Company's fuel and purchased power obligations are included in Note 24A and Note
24B to the Progress  Energy  consolidated  financial  statements.  The Company's
guarantees and other commitments are included in Note 24C to the Progress Energy
consolidated financial statements.

FUTURE OUTLOOK

The  results  of  continuing  operations  for  the  past  three  years  are  not
necessarily  indicative  of future  earnings  potential.  The level of  Progress
Energy's  future  earnings  depends on  numerous  factors.  See SAFE  HARBOR FOR
FORWARD-LOOKING  STATEMENTS  for a discussion of factors to be  considered  with
regard to forward-looking statements.

Regulatory   issues  facing  Progress  Energy  are  discussed  in  the  "Current
Regulatory Environment" discussion under OTHER MATTERS below.

General Strategy

Progress  Energy is an  integrated  energy  company,  with primary  focus on the
end-use electricity market. This focus includes the generation, transmission and
distribution  of  electricity in both regulated and  competitive  markets.  This
model  includes the  operations  of the  regulated  utilities,  CP&L and Florida
Power, and the competitive generation and fuels businesses of Progress Ventures.

                                       60
<PAGE>

Regulated Utilities

The  regulated  utility  operations  of  CP&L  and  Florida  Power  include  the
transmission and  distribution of over 20,350  megawatts of generation  capacity
within  the  traditional  service  areas.  Additional  generation  capacity  and
capacity  uprates  are  planned to serve the growth  expected  in the  Company's
service  territories  and to increase  capacity  reserve margins at the electric
utilities. CP&L and Florida Power will continue to grow their customer bases and
focus  on   value-added   services   and   technologies   to  enhance   customer
relationships.  These companies will focus on achieving top quartile results for
customer  satisfaction,  operational  excellence  and cost control  (expense and
capital).

Progress Ventures

The  competitive  energy  businesses of Progress  Ventures  include  natural gas
exploration and production;  coal fuel extraction,  manufacturing  and delivery,
which includes synthetic fuels operations;  nonregulated generation;  and energy
marketing and limited trading  activities on behalf of its nonregulated  plants.
Progress  Ventures is  scheduled  to complete the  remaining  approximate  1,545
megawatts of  nonregulated  generation in 2003 for a total of 3,100 megawatts of
nonregulated  generation in its portfolio by the end of 2003.  Progress Ventures
is  actively  marketing  this  additional  generation  to  serve  demand  in the
Southeast.

Progress Energy expects the wholesale  electric energy market to remain soft for
at least the next several years.  Through its Progress Ventures'  business,  the
Company will continue to search for opportunities to secure long-term  contracts
with load serving  entities.  Future  expansion of the  nonregulated  generating
portfolio,  if it occurs,  will depend upon  achieving  confidence in profitable
long-term sales from acquired assets.  In the meantime,  Progress  Ventures will
continue to develop its  natural gas  production  asset base both as an economic
hedge for nonregulated generation and as a profitable business in its own right.
Also, Progress Ventures will continue to leverage its coal blending, storage and
transportation assets in the Ohio River Valley area.

Diversified Subsidiaries

Progress  Energy plans to divest its Progress  Rail  subsidiary  at an opportune
time. The Company  expects to accomplish the  divestiture  within the next three
years.

Progress  Energy expects its Progress  Telecom  subsidiary to break even in 2003
and to fund its capital needs from internally  generated  funds.  The Company is
open to opportunities for divestiture or business  combination,  but it does not
see  this  as a  high  probability  due to  ongoing  difficulty  in the  overall
telecommunications industry.

Financial Strategy and Expectations

Progress Energy is focused on  strengthening  its balance sheet. The Company has
implemented  a  deleveraging  plan  through  the use of asset  sales and  equity
issuances  through its direct stock  purchase plan and employee  benefit  plans.
This plan also  includes the issuance of equity to fund  strategic  acquisitions
and controlled capital spending.  The Company expects its ratio of total debt to
total  capitalization  to decline  between 200 to 300 basis points per year over
the next several years.

Progress  Energy's Board of Directors  reviews its dividend policy each year. In
2002,  the Company  increased the dividend for the fifteenth  consecutive  year.
Progress  Energy has paid  quarterly  cash dividends on its common stock without
interruption since 1947.

OTHER MATTERS

Progress Ventures - Generation Acquisition

During February 2002, PVI completed the  acquisition of two electric  generating
projects  totaling  nearly 1,100 megawatts in Georgia from LG&E for a total cash
purchase price of approximately $350 million including direct transaction costs.
The two  projects  consist of 1) the Walton  project in Monroe,  Georgia,  a 460
megawatt  natural  gas-fired  plant  placed in  service  in June 2001 and 2) the
Washington project in Washington County, Georgia, a planned 600 megawatt natural
gas-fired  plant  expected  to be  operational  by June  2003.  The  transaction
included  a power  purchase  agreement  with LG&E  Marketing  for both  projects
through  December  31,  2004.  In addition,  there is a project  management  and
completion  agreement  whereby LG&E has agreed to manage the  completion  of the
Washington site construction for PVI in exchange for cash  consideration of $181
million.  The estimated costs to complete the Washington  project as of December
31, 2002 are approximately $57.8 million.

                                       61
<PAGE>

Progress Ventures - Fuel Acquisition

On April 26, 2002,  Progress Energy finalized the acquisition of Westchester Gas
Company,  which includes approximately 215 natural gas-producing wells, 52 miles
of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate
purchase price of approximately  $153 million consisted of cash consideration of
approximately  $22  million and the  issuance of 2.5 million  shares of Progress
Energy common stock valued at  approximately  $129 million.  The purchase  price
included  approximately $1.7 million of direct transaction costs. The properties
are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border.  This transaction  added 140 billion cubic feet (Bcf) of gas reserves to
PVI's growing energy portfolio.

Current Regulatory Environment

General

The  Company's  electric and gas utility  operations  in North  Carolina,  South
Carolina and Florida are  regulated  by the North  Carolina  Utility  Commission
(NCUC),  the Public Service Commission of South Carolina (SCPSC) and the Florida
Public Service Commission (FPSC), respectively. The electric businesses are also
subject to regulation by the Federal Energy Regulatory  Commission  (FERC),  the
U.S.  Nuclear  Regulatory  Commission (NRC) and other federal and state agencies
common to the  utility  business.  In  addition,  the  Company is subject to SEC
regulation  as  a  registered  holding  company  under  PUHCA.  As a  result  of
regulation,  many of the fundamental business decisions,  as well as the rate of
return the electric  utilities  and the gas utility are  permitted to earn,  are
subject to the approval of governmental agencies.

Electric Industry Restructuring

CP&L and Florida Power continue to monitor  progress  toward a more  competitive
environment and have actively participated in regulatory reform deliberations in
North  Carolina,  South Carolina and Florida.  Movement  toward  deregulation in
these states has been affected by recent  developments,  including  developments
related to deregulation of the electric industry in California and other states.

     o    North  Carolina.  The  Company  expects  the  North  Carolina  General
          Assembly will continue to monitor the  experiences of states that have
          implemented electric restructuring legislation.

     o    South  Carolina.  The  Company  expects  the  South  Carolina  General
          Assembly will continue to monitor the  experiences of states that have
          implemented electric restructuring legislation.

     o    Florida.  On December  11,  2001,  the Florida  2020 Study  Commission
          issued its final report to the Florida Legislature. The report covered
          a number  of issues  with  recommendations  in the areas of  wholesale
          competition and reliability,  efficiency, transmission infrastructure,
          environmental  issues  and  new  technologies.  A  key  recommendation
          related to wholesale  competition and reliability permits the transfer
          or sale of existing  generation at book value and on a  plant-by-plant
          basis,  with the  sale and  transfer  being at the  discretion  of the
          investor-owned  utility.  The  Florida  Legislature  did not  take any
          action on the proposed outline or final report during the 2001 or 2002
          legislative session.

The Company  cannot  anticipate  when,  or if, any of these  states will move to
increase competition in the electric industry.

Florida Retail Rate Proceeding

On March 27,  2002,  the parties in Florida  Power's  rate case  entered  into a
Stipulation  and  Settlement  Agreement (the  Agreement)  related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The Agreement
is generally  effective  from May 1, 2002 through  December 31, 2005;  provided,
however,  that if Florida  Power's base rate earnings fall below a 10% return on
equity, Florida Power may petition the FPSC to amend its base rates.

The Agreement  provides that Florida Power will reduce its retail  revenues from
the sale of electricity by an annual amount of $125 million.  The Agreement also
provides that Florida Power will operate under a Revenue Sharing  Incentive Plan
(the Plan) through  2005,  and  thereafter  until  terminated by the FPSC,  that
establishes annual revenue caps and sharing  thresholds.  The Plan provides that
retail base rate  revenues  between the sharing  thresholds  and the retail base
rate  revenue  caps will be divided into two shares - a 1/3 share to be received
by  Florida  Power's  shareholders,  and a 2/3 share to be  refunded  to Florida
Power's retail customers;  provided,  however,  that for the year 2002 only, the
refund to  customers  will be limited to 67.1% of the 2/3  customer  share.  The
retail base rate revenue sharing  threshold amounts for 2002 were $1.296 billion
and will increase $37 million each year thereafter.  The Plan also provides that
all retail base rate revenues above the retail base rate revenue cap established
for each year will be refunded to retail customers on an annual basis. For 2002,
the refund to  customers  was limited to 67.1% of the retail base rate  revenues
that  exceed  the 2002 cap.  The  retail  base  revenue  cap for 2002 was $1.356
billion and will  increase $37 million each year  thereafter.  Any amounts above
the retail base revenue caps will be refunded 100% to customers.  As of December
31,  2002,  $4.7  million was accrued and will be refunded to customers by March
2003.

                                       62
<PAGE>

Per the Agreement, Florida Power was required to refund to customers $35 million
of revenues  Florida Power  collected  during the interim period since March 13,
2001. This one-time retroactive revenue refund was recorded in the first quarter
of 2002 and was returned to retail  customers over an  eight-month  period ended
December 31, 2002. Any additional  refunds under the Agreement are recorded when
they become probable.

See  Note 15B to the  Progress  Energy  consolidated  financial  statements  for
additional information on the Agreement.

North Carolina Clean Air Legislation

On June 20,  2002,  legislation  was  enacted in North  Carolina  requiring  the
state's electric  utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants.  Progress Energy expects its capital costs
to meet these emission  targets to be  approximately  $813 million by 2013. CP&L
currently has  approximately  5,100 megawatts of coal-fired  generation in North
Carolina  that is affected by this  legislation.  The  legislation  requires the
emissions  reductions  to be  completed  in phases by 2013,  and applies to each
utility's  total system rather than setting  requirements  for individual  power
plants.  The  legislation  also freezes the utilities' base rates for five years
unless  there  are  significant   cost  changes  due  to  governmental   action,
significant  expenditures  due to force  majeure or other  extraordinary  events
beyond the control of the utilities or unless the utilities  persistently earn a
return  substantially  in  excess of the rate of  return  established  and found
reasonable by the NCUC in the utilities'  last general rate case.  Further,  the
legislation  allows the  utilities to recover from their  retail  customers  the
projected capital costs during the first seven years of the ten-year  compliance
period  beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period.  Pursuant
to the new law, CP&L entered into an agreement  with the state of North Carolina
to transfer  to the state all future  emissions  allowances  it  generates  from
over-complying  with the new  federal  emission  limits  when  these  units  are
completed.  The new law also  requires the state to undertake a study of mercury
and carbon dioxide  emissions in North Carolina.  Progress Energy cannot predict
the future regulatory interpretation, implementation or impact of this new law.

Other Retail Rate Matters

See  Note 15C to the  Progress  Energy  consolidated  financial  statements  for
additional information on the Company's other retail rate matters.

Regional Transmission Organizations and Standard Market Design

Florida Power

In  early  2000,  FERC  issued  Order  2000  regarding   regional   transmission
organizations (RTOs). This Order set minimum  characteristics and functions that
RTOs must meet, including independent transmission service. As a result of Order
2000, Florida Power, along with Florida Power & Light Company and Tampa Electric
Company, filed with FERC, in October 2000, an application for approval of a Grid
Florida RTO. On March 28,  2001,  FERC issued an order  provisionally  approving
GridFlorida.  However,  in July  2001,  FERC  issued  orders  recommending  that
companies in the Southeast  engage in a mediation to develop a plan for a single
RTO for the Southeast. Florida Power participated in the mediation. FERC has not
issued an order  specifically on this  mediation.  FERC held a discussion on the
mediation  report on November 24,  2001.  In January  2002,  FERC stated that it
would issue orders on the RTO formations for the Southeast during the first half
of 2002 after the development of a standardized  market design for the wholesale
electricity  market.  On July 31,  2002,  FERC  issued  its  Notice of  Proposed
Rulemaking in Docket No.  RM01-12-000,  Remedying Undue  Discrimination  through
Open Access  Transmission  Service and Standard  Electricity  Market Design (SMD
NOPR).  The proposed rules set forth in the SMD NOPR would require,  among other
things,  that 1) all  transmission  owning  utilities  transfer control of their
transmission  facilities to an independent third party; 2) transmission  service
to bundled retail  customers be provided under the  FERC-regulated  transmission
tariff,  rather  than  state-mandated  terms  and  conditions;  3) new terms and
conditions  for  transmission  service  be  adopted  nationwide,  including  new
provisions for pricing transmission in the event of transmission congestion;  4)
new energy markets be established for the buying and selling of electric energy;
and 5) load serving entities be required to meet minimum criteria for generating
reserves.  If  adopted  as  proposed,  the rules set forth in the SMD NOPR would
materially alter the manner in which  transmission  and generation  services are
provided and paid for. Florida Power, as a subsidiary of Progress Energy,  filed
comments on November 15, 2002 and  supplement  comments on January 10, 2003.  On
January 15, 2003, FERC announced the issuance of a White Paper on SMD NOPR to be
released in April 2003. Florida Power, as a subsidiary of Progress Energy, plans
to file comments on the White Paper.  FERC has also indicated that it expects to
issue final rules during the summer 2003. The Company cannot predict the outcome
of these matters or the effect that they may have on the GridFlorida proceedings
currently ongoing before the FERC.

                                       63
<PAGE>

On May 16,  2001,  the FPSC  initiated  dockets  to review the  prudence  of the
GridFlorida applicants' decision to form and participate in the GridFlorida RTO.
On October 15, 2002 the FPSC abated its proceedings  regarding its review of the
proposed GridFlorida RTO. The GridFlorida RTO proposal includes the formation of
a  not-for-profit  Independent  System Operator (ISO) by the joint  Applicants -
Florida Power  Corporation,  Florida  Power & Light  Company and Tampa  Electric
Company. Participation is expected from many of the other transmission owners in
the state of Florida.  The FPSC previously  found the Applicants were prudent in
proactively  forming  GridFlorida  but ordered the  Applicants  to modify  their
proposal. The modifications include but are not limited to addressing 1) pricing
structure  that  recognizes  the FPSC's  jurisdiction  over retail  transmission
rates,  2)  pricing/rate  structure  of  long-term  transmission  contracts,  3)
elimination of pancaking of short-term  transmission  revenues, 4) cost recovery
of incremental  costs imposed on the  Applicants,  5) demarcation  dates for new
facilities and long-term transmission contracts,  and 6) market design. The FPSC
action to abate the proceedings came in response to the Florida Office of Public
Counsel's appeal before the state Supreme Court requesting  review of the FPSC's
order  approving the transfer of  operational  control of electric  transmission
assets to an RTO under the  jurisdiction  of the FERC.  It is  unknown  what the
outcome of this  appeal  will be at this time.  It is  unknown  what  impact the
future proceedings in regard to GridFlorida will have on the Company's earnings,
revenues or prices.

CP&L

In early 2000, FERC issued  Order 2000  regarding  RTOs.  This Order set minimum
characteristics  and  functions  that  RTOs  must  meet,  including  independent
transmission  service.  In October 2000, as a result of Order 2000,  CP&L, along
with Duke Energy Corporation and South Carolina Electric & Gas Company, filed an
application  with the FERC for  approval of a GridSouth  RTO. On July 12,  2001,
FERC issued an order provisionally  approving GridSouth.  However, in July 2001,
FERC issued orders  recommending  that  companies in the  Southeast  engage in a
mediation  to  develop  a  plan  for  a  single  RTO  for  the  Southeast.  CP&L
participated in the mediation. FERC has not issued an order specifically on this
mediation.  FERC held a discussion on the mediation report on November 24, 2001.
In January  2002,  FERC stated that it would issue orders on the RTO  formations
for the  Southeast  during  the first half of 2002  after the  development  of a
standardized  market design for the wholesale  electricity  market.  On July 31,
2002, FERC issued its Notice of Proposed  Rulemaking in Docket No.  RM01-12-000,
Remedying  Undue  Discrimination  through Open Access  Transmission  Service and
Standard  Electricity  Market Design (SMD NOPR). The proposed rules set forth in
the SMD NOPR would require,  among other things, that 1) all transmission owning
utilities  transfer control of their  transmission  facilities to an independent
third party;  2)  transmission  service to bundled retail  customers be provided
under the FERC-regulated  transmission tariff,  rather than state-mandated terms
and conditions;  3) new terms and conditions for transmission service be adopted
nationwide,  including new provisions for pricing  transmission  in the event of
transmission congestion; 4) new energy markets be established for the buying and
selling of electric  energy;  and 5) load  serving  entities be required to meet
minimum criteria for generating reserves. If adopted as proposed,  the rules set
forth in the SMD NOPR would  materially  alter the manner in which  transmission
and  generation  services are provided and paid for.  CP&L,  as a subsidiary  of
Progress Energy,  filed comments on November 15, 2002 and supplement comments on
January 10, 2003.  On January 15, 2003,  FERC  announced the issuance of a White
Paper on SMD NOPR to be  released  in  April  2003.  CP&L,  as a  subsidiary  of
Progress  Energy,  plans to file  comments  on the  White  Paper.  FERC has also
indicated  that it expects to issue  final  rules  during the summer  2003.  The
Company  cannot predict the outcome of these matters or the effect that they may
have on the GridSouth proceedings currently ongoing before FERC.

CP&L applied to the NCUC and the SCPSC for  permission  to transfer  operational
control of its  transmission  assets to GridSouth.  On June 21, 2001, the Public
Staff of the NCUC filed a motion asking the NCUC to hold the GridSouth docket in
abeyance  until the U.S.  Supreme  Court had ruled on the appeal of FERC's Order
No.  888.  That  appeal  addresses  the  scope  of  FERC's   jurisdiction   over
transmission service used to serve retail customers. The appeal of Order No. 888
was heard by the Court on October  3, 2001,  and its  decision  affirmed  FERC's
order.   The  NCUC  issued  an  order   holding  that  CP&L's  and  Duke  Energy
Corporation's  petition to transfer  operational  control of their  transmission
assets to GridSouth shall be held in abeyance pending further order. In February
2002, CP&L and the other GridSouth applicants withdrew the GridSouth application
from the NCUC  and  SCPSC  for  purposes  of  making  certain  revisions  to the
GridSouth  proposal.  The Company has $28.4  million  invested in  GridSouth  at
December 31, 2002. It is unknown what impact the future proceedings in regard to
GridSouth will have on the Company's earnings, revenues or prices.

                                       64
<PAGE>

Franchise Litigation

Six cities,  with a total of approximately  49,000 customers,  have sued Florida
Power in various circuit courts in Florida.  The lawsuits  principally seek 1) a
declaratory  judgment that the cities have the right to purchase Florida Power's
electric  distribution  system  located  within the municipal  boundaries of the
cities, 2) a declaratory judgment that the value of the distribution system must
be determined  through  arbitration,  and 3) injunctive relief requiring Florida
Power to continue to collect from  Florida  Power's  customers  and remit to the
cities,  franchise  fees during the pending  litigation,  and as long as Florida
Power continues to occupy the cities' rights-of-way to provide electric service,
notwithstanding  the expiration of the franchise  ordinances under which Florida
Power had agreed to collect such fees.  Five circuit  courts have entered orders
requiring  arbitration  to  establish  the  purchase  price of  Florida  Power's
electric  distribution  system  within five cities.  Two  appellate  courts have
upheld those circuit  court  decisions  and  authorized  cities to determine the
value of Florida Power's electric  distribution system within the cities through
arbitration.  To date, no city has  attempted to actually  exercise the right to
purchase  any  portion  of  Florida  Power's   electric   distribution   system.
Arbitration  in one of the cases was held in August 2002 and an award was issued
in October 2002 setting the value of Florida Power's  distribution system within
one city at approximately $22 million. At this time, whether and when there will
be further  proceedings  following this award cannot be  determined.  Additional
arbitrations  have been  scheduled to occur in the first and second  quarters of
2003.

As part of the above litigation, two appellate courts have also reached opposite
conclusions  regarding  whether  Florida Power must continue to collect from its
customers and remit to the cities  "franchise fees" under the expired  franchise
ordinances.  Florida Power has filed an appeal with the Florida Supreme Court to
resolve the conflict between the two appellate courts. The Florida Supreme Court
has  issued  an order  setting  a  briefing  schedule  and  reserving  ruling on
accepting  jurisdiction.  On January 12, 2003,  Florida Power served its Initial
Brief in the  Supreme  Court and its  request for oral  argument.  Three  amicus
curiae also filed  motions  seeking leave to  participate  in support of Florida
Power's position and filed amicus briefs. No oral argument has yet been set. The
Company cannot predict the outcome of these matters at this time.

Nuclear

In the Company's retail  jurisdictions,  provisions for nuclear  decommissioning
costs  are  approved  by the  NCUC,  the  SCPSC  and the FPSC  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 jurisdictions, the provisions
for  nuclear  decommissioning  costs are  approved  by FERC.  See Note 1H to the
Progress  Energy  consolidated  financial  statements  for a  discussion  of the
Company's nuclear decommissioning costs.

Spent Fuel Storage

On December  21, 2000,  CP&L  received  permission  from the NRC to increase its
storage capacity for spent fuel rods in Wake County,  North Carolina.  The NRC's
decision  came two years  after  CP&L  asked for  permission  to open two unused
storage pools at the Shearon Harris Nuclear Plant (Harris  Plant).  The approval
meant  that CP&L was able to  complete  cooling  systems and to begin installing
storage racks in its third and fourth storage pools at the Harris Plant.

Pressurized Water Reactors

On March 18, 2002,  the NRC sent a bulletin to companies  that hold licenses for
pressurized  water  reactors  (PWRs)  requiring  information  on the  structural
integrity of the reactor vessel head and a basis for concluding  that the vessel
head will continue to perform its function as a coolant pressure  boundary.  The
Company  filed  responses  as required.  Inspections  of the vessel heads at the
Company's PWR plants have been performed  during  previous  outages.  In October
2001, at the Crystal River Plant (CR3), one nozzle was found to have a crack and
was repaired; however, no degradation of the reactor vessel head was identified.
Current  plans are to replace the vessel  head at CR3 during its next  regularly
scheduled  refueling  outage in 2003. At the Robinson  Plant,  an inspection was
completed in April 2001 and no  penetration  nozzle  cracking was identified and
there was no  degradation  of the  reactor  vessel  head.  At the Harris  Plant,
sufficient  inspections  were completed  during the last refueling outage in the
fourth quarter of 2001 to conclude there is no degradation of the reactor vessel
head. The Company's  Brunswick Plant has a different  design and is not affected
by the issue.

On August 9,  2002,  the NRC issued an  additional  bulletin  dealing  with head
leakage due to cracks near the control rod nozzles.  The NRC has asked licensees
to commit to high  inspection  standards to ensure the more  susceptible  plants
have no cracks.  The  Robinson  Plant is in this  category  and had a  refueling
outage in October  2002.  The  Company  completed  a series of  examinations  in
October 2002 of the entire reactor pressure vessel head and found no indications
of control rod drive  mechanism  cracking  and no  corrosion of the head itself.
During the outage, a boric acid leakage walkdown of the reactor coolant pressure
boundary was also completed and no corrosion was found. For CR3, the Company has
responded to the NRC that previous  inspections are sufficient until the reactor
head is replaced in the fall of 2003. For the Harris Plant, the Company does not
plan further  inspections until its next regularly scheduled outage in spring of
2003.

                                       65
<PAGE>

In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated  penetration nozzles at PWRs.
The Company has  responded  to the Order,  stating  that the Company  intends to
comply with the previsions of the order. No adverse impact is anticipated.

Security

On February 25, 2002, the NRC issued an interim compensatory measure with regard
to  security  at nuclear  plants.  This order  formalized  many of the  security
enhancements  made at the Company's  nuclear plants since  September  2001. This
order includes  additional  restrictions on access,  increased security presence
and closer  coordination with the Company's partners in intelligence,  military,
law enforcement and emergency  response at the federal,  state and local levels.
The Company completed the requirements by the established  deadlines and expects
the NRC to perform an inspection for compliance in the near future.

In addition, in January 2003 the NRC issued a final order with regards to access
control.  This order  requires the Company to enhance its current access control
program  by  January  7,  2004.  The  Company  expects  that  it will be in full
compliance with the order by the established deadline.

As the NRC, other  governmental  entities and the industry  continue to consider
security  issues,  it is possible that more  extensive  security  plans could be
required.

Synthetic Fuels Tax Credits

Progress  Energy,  through the  Progress  Ventures  business  segment,  produces
synthetic  fuel from coal fines.  The  production and sale of the synthetic fuel
qualifies  for  tax  credits  under  Section  29  if  certain  requirements  are
satisfied, including a requirement that the synthetic fuel differs significantly
in chemical  composition from the feedstock used to produce such synthetic fuel.
Any  synthetic  fuel  tax  credit  amounts  not  utilized  are  carried  forward
indefinitely and are included in deferred taxes on the accompanying Consolidated
Balance  Sheet.  See  Note  20 to the  Progress  Energy  consolidated  financial
statements.  All of Progress  Energy's  synthetic fuel  facilities have received
private letter rulings from the IRS with respect to their operations.  These tax
credits  are  subject  to review by the IRS,  and if  Progress  Energy  fails to
prevail  through  the  administrative  or  legal  process,   there  could  be  a
significant tax liability owed for previously  taken Section 29 credits,  with a
significant  impact on earnings  and cash  flows.  Tax credits for the 12 months
ended  December  31,  2002  and  2001,  were  $291  million  and  $349  million,
respectively. Total Section 29 credits generated to date (including FPC prior to
its acquisition by the Company) are approximately $897.2 million.

One  synthetic  fuel  entity,  Colona  Synfuel  Limited  Partnership,   L.L.L.P.
(Colona),  from  which  the  Company  (and FPC prior to its  acquisition  by the
Company) has been allocated  approximately  $251 million in tax credits to date,
is being  audited by the IRS. The audit of Colona was  expected.  The Company is
audited  regularly  in the  normal  course of  business,  as are most  similarly
situated companies.  In September 2002, all of Progress Energy's  majority-owned
synthetic fuel entities, including Colona, were accepted into the IRS Pre-Filing
Agreement  (PFA)  program.  The PFA  program  allows  taxpayers  to  voluntarily
accelerate the IRS exam process in order to seek resolution of specific  issues.
Either the Company or the IRS can  withdraw  from the  program at any time,  and
issues not resolved through the program may proceed to the next level of the IRS
exam process. While the ultimate outcome is uncertain, the Company believes that
participation  in the PFA program will likely  shorten the tax exam process.  In
management's  opinion,  Progress  Energy is  complying  with the private  letter
rulings and all the  necessary  requirements  to be allowed such  credits  under
Section 29 and believes it is likely, although it cannot provide certainty, that
it will  prevail if  challenged  by the IRS on any  credits  taken.  The current
Section 29 tax credit program expires in 2007.

The Company  has  retained an advisor to assist in selling an interest in one or
more synthetic  fuel entities.  The Company is pursuing the sale of a portion of
its synthetic fuel production  capacity that is  underutilized  due to limits on
the amount of credits  that can be generated  and  utilized by the Company.  The
Company  would  expect to retain an  ownership  interest and to operate any sold
facility for a management fee. The final outcome and timing of these discussions
is uncertain and the Company cannot predict the outcome of this matter.

Environmental Matters

The Company is subject to federal,  state and local  regulations  addressing air
and water quality,  hazardous and solid waste management and other environmental
matters.  These environmental  matters are discussed in detail in Note 24 to the
Progress Energy consolidated  financial  statements.  This discussion identifies
specific  environmental  issues, the status of the issues,  accruals  associated
with issue resolutions and the associated exposures to the Company.

                                       66
<PAGE>

New Accounting Standards

See Note 1U and Note 6 to the Progress Energy consolidated  financial statements
for a discussion of the impact of new accounting standards.

CAROLINA POWER & LIGHT COMPANY

The information required by this item is incorporated herein by reference to the
following portions of Progress Energy's Management's  Discussion and Analysis of
Financial  Condition and Results of Operations,  insofar as they relate to CP&L:
RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER
MATTERS.

The  following   Management's   Discussion  and  Analysis  and  the  information
incorporated herein by reference contain forward-looking statements that involve
estimates,  projections, goals, forecasts,  assumptions, risks and uncertainties
that could cause  actual  results or outcomes  to differ  materially  from those
expressed in the  forward-looking  statements.  Please review "Rick Factors" and
"SAFE HARBOR FOR  FORWARD-LOOKING  STATEMENTS"  for a discussion  of the factors
that may impact any such forward-looking statements made herein.

RESULTS OF OPERATIONS

Note 1 to the CP&L consolidated  financial  statements discusses its significant
accounting  policies.  The most critical  accounting policies and estimates that
impact  CP&L's  financial   statements  are  the  economic  impacts  of  utility
regulation and asset impairment policies,  which are described in more detail in
the Progress Energy Management's Discussion and Analysis section.

On July 1, 2000, CP&L  distributed its ownership  interest in the stock of NCNG,
SRS,  Monroe  Power  and  PVI to  Progress  Energy.  Prior  to  that  date,  the
consolidated operations of CP&L and Progress Energy were substantially the same.
Subsequent to July 1, 2000, the operations of these  subsidiaries  are no longer
included in CP&L's results of operations or financial position.

The results of operations  for the CP&L Electric  segment are identical  between
CP&L and  Progress  Energy for all periods  presented.  The  primary  difference
between  the  results  of  operations  of the  CP&L  Electric  segment  and  the
consolidated  CP&L results of operations for the 2000,  2001 and 2002 comparison
periods relate to the non-electric operations, as summarized below:

(in millions)                             2002         2001          2000
                                       ---------    ---------    ----------
CP&L Electric net income                $ 513.1      $ 468.3       $ 373.8
Caronet net income (loss)                (79.4)       (99.5)          81.0
Other non-electric net income (loss)      (5.7)        (7.5)           3.3
                                       ---------    ---------    ----------
Earnings for common stock               $ 428.0      $ 361.3       $ 458.1
                                       =========    =========    ==========

Caronet's results of operations for 2002 and 2001 include after-tax  impairments
of $87.4  million and $102.4  million,  respectively,  for  other-than-temporary
declines  in the value of the  assets of Caronet  and  Caronet's  investment  in
Interpath.  The  Interpath  investment  was sold in December  2002 for a nominal
amount.  Caronet's  results of  operations  for 2000 include the $121.1  million
after-tax gain from the sale of the BellSouth  Carolinas PCS assets in September
2000.  See Note 2 to the CP&L  consolidated  financial  statements  for  further
discussion of this divestiture.

                                       67

<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

The  statements of cash flows for CP&L do not include  amounts  related to NCNG,
SRS, Monroe Power or PVI after July 1, 2000.  Additionally,  the CP&L statements
of cash flows do not include any amounts  related to the  acquisition  of FPC or
the issuance of debt to consummate the transaction.

CP&L's estimated capital  requirements for 2003, 2004 and 2005 are $620 million,
$690 million and $650 million,  respectively, and primarily reflect construction
expenditures to support  customer growth,  add regulated  generation and upgrade
existing facilities.

See Note 6 to the CP&L  consolidated  financial  statements  for  information on
CP&L's  available  credit  facilities at December 31, 2002,  and the  discussion
above for Progress Energy under "Financing Activities" for information regarding
CP&L's financing activities.

FUTURE COMMITMENTS

The following  tables  reflect CP&L's  contractual  cash  obligations  and other
commercial commitments in the respective periods in which they are due.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)
------------------------------------------------------------------------------------------------------------
Contractual Cash        Total Amounts
Obligations               Committed        2003        2004       2005       2006       2007    Thereafter
------------------------------------------------------------------------------------------------------------
Long-term debt             $ 3,065        $   -        $ 300      $ 307      $   -      $ 200     $ 2,258
Capital lease
   obligations                  31            2            2          2          2          2          21
Operating leases                44           10            8          6          4          4          12
Fuel                         1,812          500          434        351        312        199          16
Purchased power              1,073           97           97         97         97         97         588
------------------------------------------------------------------------------------------------------------
Total                      $ 6,025        $ 609        $ 841      $ 763      $ 415      $ 502     $ 2,895


Other Commercial        Total Amounts
Commitments               Committed       2003         2004        2005       2006      2007    Thereafter
------------------------------------------------------------------------------------------------------------
Standby letters of
   credit                   $    5        $   5        $   -      $   -      $   -      $   -     $     -
Guarantees and
   other commitments             1            -            -          -          -          -           1
------------------------------------------------------------------------------------------------------------
Total                       $    6        $   5        $   -      $   -      $   -      $   -     $     1
</TABLE>

Information on CP&L's  contractual  obligations at December 31, 2002 is included
in  the  notes  to the  CP&L  consolidated  financial  statements.  Future  debt
maturities  and  lease   obligations   are  included  in  Note  6  and  Note  7,
respectively,  to the CP&L consolidated  financial  statements.  CP&L's fuel and
purchased power  obligations  are included in Note 18A to the CP&L  consolidated
financial statements.

                                       68
<PAGE>
ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PROGRESS ENERGY, INC.

Market risk represents the potential loss arising from adverse changes in market
rates and prices.  Certain market risks are inherent in the Company's  financial
instruments,  which arise from transactions entered into in the normal course of
business.  The Company's  primary  exposures are changes in interest  rates with
respect to its long-term  debt and commercial  paper,  and  fluctuations  in the
return on  marketable  securities  with  respect to its nuclear  decommissioning
trust  funds.  The  Company  manages  its  market  risk in  accordance  with its
established  risk management  policies,  which may include entering into various
derivative transactions.

These financial  instruments are held for purposes other than trading.  The fair
value of the  Company's  open  trading  positions  was less than a $0.4  million
liability  position at  December  31,  2002.  The risks  discussed  below do not
include the price risks associated with nonfinancial  instrument transactions or
positions associated with the Company's  operations,  such as purchase and sales
commitments and inventory.

Interest Rate Risk

The Company  manages its interest rate risks through the use of a combination of
fixed and  variable  rate  debt.  Variable  rate debt has rates  that  adjust in
periods ranging from daily to monthly.  Interest rate derivative instruments may
be used to  adjust  interest  rate  exposures  and to  protect  against  adverse
movements in rates.

The following tables provide information as of December 31, 2002 and 2001, about
the  Company's  interest rate risk  sensitive  instruments.  The tables  present
principal cash flows and  weighted-average  interest rates by expected  maturity
dates  for the  fixed  and  variable  rate  long-term  debt  and  FPC  obligated
mandatorily redeemable securities of trust. The tables also include estimates of
the fair value of the Company's  interest rate risk sensitive  instruments based
on quoted market prices for these or similar issues. For interest-rate swaps and
interest-rate  forward  contracts,  the  tables  present  notional  amounts  and
weighted-average  interest rates by contractual maturity dates. Notional amounts
are used to  calculate  the  contractual  cash flows to be  exchanged  under the
interest-rate  swaps and the settlement amounts under the interest-rate  forward
contracts. See "Interest Rate Derivatives" under LIQUIDITY AND CAPITAL RESOURCES
above for more information on interest rate derivatives.

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

December 31, 2002                                                                                      Fair Value
                                                                                                       December 31,
(Dollars in millions)             2003     2004     2005    2006     2007     Thereafter    Total          2002
--------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt        $ 275    $ 869    $ 355   $ 909     $ 674     $ 5,614     $ 8,696      $ 9,584
Average interest rate             6.42%    6.66%    7.38%   6.78%     6.41%       6.90%       6.83%
Variable rate long-term debt       -        -        -        -      $ 225     $   861     $ 1,086      $ 1,087
Average interest rate              -        -        -        -       0.03%       1.24%       1.61%         -
FPC mandatorily redeemable
securities of trust                -        -        -        -        -       $   300     $   300      $   303
Interest rate                                                                     7.10%       7.10%         -
Interest rate swaps:
Pay fixed/receive variable(a)      -        -        -        -      $ 350         -       $   350      $   5.2
Interest rate forward
  contracts(b)                   $  35      -        -        -        -           -       $    35      $  (0.5)
Interest rate collars(c)                                             $ 195                 $   195      $ (12.3)

(a)  Receives  floating rate based on  three-month  LIBOR and pays fixed rate of
     7.17%. Designated as hedge of $350 million of fixed rate debt.
(b)  Treasury Rate Lock agreement on $35 million  designated as fair value hedge
     of anticipated debt issuance.
(c)  Interest  rate collars on $195  million  notional.  Designated  as hedge of
     variable rate interest.
</TABLE>

                                       69
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

December 31, 2001                                                                                      Fair Value
                                                                                                       December 31,
(Dollars in millions)             2002     2003     2004    2005      2006     Thereafter    Total         2001
--------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt        $ 188    $ 283   $ 869    $ 348    $ 909      $ 5,379     $ 7,976      $ 8,322
Average interest rate             6.38%    6.42%    6.67%   7.39%    6.78%        6.97%       6.90%         -
Variable rate long-term debt       -        -        -        -        -       $   620     $   620      $   621
Average interest rate              -        -        -        -        -          1.58%       1.58%         -
Extendible notes                 $ 500      -        -        -        -           -       $   500      $   500
Average interest rate -
  variable rate                   2.83%     -        -        -        -           -          2.83%         -
FPC mandatorily redeemable
  securities of trust              -        -        -        -        -       $   300     $   300      $   291
Fixed rate                                                             -          7.10%       7.10%         -
Interest rate swaps:
Pay fixed/receive variable (a)   $ 500      -        -        -        -           -       $   500      $ (18.5)

(a)  Receives  floating rate based on  three-month  LIBOR and pays fixed rate of
     7.17%.  Designated  as a hedge of  interest  payments  on $500  million  of
     extendible notes.
</TABLE>

Marketable Securities Price Risk

The Company's electric utility  subsidiaries  maintain trust funds,  pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents,  which
are exposed to price  fluctuations  in equity markets and to changes in interest
rates.  The fair value of these funds was $796.8  million and $822.8  million at
December  31, 2002 and 2001,  respectively.  The Company  actively  monitors its
portfolio by benchmarking  the  performance of its  investments  against certain
indices  and by  maintaining,  and  periodically  reviewing,  target  allocation
percentages   for   various   asset   classes.   The   accounting   for  nuclear
decommissioning  recognizes that the Company's  regulated electric rates provide
for  recovery  of these  costs net of any trust fund  earnings  and,  therefore,
fluctuations  in trust  fund  marketable  security  returns  do not  affect  the
earnings of the Company.

Contingent Value Obligations Market Value Risk

In  connection  with the  acquisition  of FPC,  the Company  issued 98.6 million
contingent value  obligations  (CVOs).  Each CVO represents the right to receive
contingent  payments based on the  performance of four synthetic fuel facilities
purchased by  subsidiaries  of FPC in October 1999.  The  payments,  if any, are
based on the net after-tax  cash flows the facilities  generate.  These CVOs are
recorded  at fair value and  unrealized  gains and losses  from  changes in fair
value are recognized in earnings.  At December 31, 2002 and 2001, the fair value
of these CVOs was $13.8 million and $41.9 million,  respectively. A hypothetical
10%  decrease  in the  December  31, 2002  market  price would  result in a $1.4
million decrease in the fair value of the CVOs.

                                       70
<PAGE>
CAROLINA POWER & LIGHT COMPANY

The information required by this item is incorporated herein by reference to the
Progress  Energy  Quantitative  and  Qualitative  Disclosures  About Market Risk
insofar as it relates to CP&L.

The following tables provide information as of December 31, 2002 and 2001, about
CP&L's interest rate risk sensitive instruments.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

December 31, 2002
-----------------                                                                                            Fair Value
                                                                                                             December 31,
(dollars in millions)               2003      2004      2005      2006      2007   Thereafter     Total          2002
--------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt              -     $ 300     $ 307         -     $ 200     $ 1,638      $ 2,445     $ 2,708
Average interest rate                  -     6.87%     7.48%         -     6.80%       6.61%        6.76%           -
Variable rate long-term debt           -         -         -         -         -     $   620        $ 620     $   620
Average interest rate                  -         -         -         -         -       1.29%        1.29%           -


December 31, 2001
-----------------                                                                                            Fair Value
                                                                                                             December 31,
(dollars in millions)               2002      2003      2004      2005      2006   Thereafter     Total          2001
--------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt          $ 100     $   7     $ 300     $ 300         -     $ 1,488      $ 2,195     $ 2,274
Average interest rate              6.75%     6.43%      6.87%    7.50%         -       6.88%        6.96%           -
Variable rate long-term debt           -         -         -         -         -     $   620      $   620     $   621
Average interest rate                  -         -         -         -         -       1.58%        1.58%           -
Extendible notes                   $ 500         -         -         -         -           -      $   500     $   500
Average interest rate -
  variable rate                    2.83%         -         -         -         -           -        2.83%           -
Interest rate swaps:
   Pay fixed/receive variable (a)  $ 500         -         -         -         -           -      $   500     $ (18.5)
</TABLE>

(a)  Receives  floating rate based on  three-month  LIBOR and pays fixed rate of
     7.17%. Designated as a hedge on $500 million of Extendible notes.


                                       71
<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>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
                                                                                                    Page
Progress Energy, Inc.
Independent Auditors' Report                                                                        73

Consolidated Financial Statements - Progress Energy, Inc.:

Consolidated Statements of Income for the Years Ended December 31, 2002, 2001 and 2000              74
Consolidated Balance Sheets as of December 31, 2002 and 2001                                        75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000          76
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2002,
   2001 and 2000                                                                                    77
Consolidated Quarterly Financial Data (Unaudited)                                                   78

Notes to Consolidated Financial Statements                                                          79

Carolina Power & Light Company
Independent Auditors' Report                                                                       124

Consolidated Financial Statements - Carolina Power & Light Company:

Consolidated Statements of Income and Comprehensive Income for the Years Ended
       December 31, 2002, 2001, and 2000                                                           125
Consolidated Balance Sheets as of December 31, 2002 and 2001                                       126
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001
   and 2000                                                                                        127
Consolidated Schedules of Capitalization as of December 31, 2002 and 2001                          128
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2002, 2001
   and 2000                                                                                        128
Consolidated Quarterly Financial Data (Unaudited)                                                  128

Notes to Consolidated Financial Statements                                                         129

Independent Auditors' Report on Consolidated Financial Statement Schedule - Progress Energy, Inc.  155
Independent Auditors' Report on Consolidated Financial Statement Schedule - Carolina Power &
           Light Company                                                                           156

Consolidated Financial Statement Schedules for the Years Ended December 31,
2002, 2001 and 2000:

           II-Valuation and Qualifying Accounts - Progress Energy, Inc.                            157
           II-Valuation and Qualifying Accounts - Carolina Power & Light Company                   158
</TABLE>

All other  schedules  have been  omitted as not  applicable  or not  required or
because the  information  required  to be shown is included in the  Consolidated
Financial  Statements or the accompanying  Notes to the  Consolidated  Financial
Statements.

                                       72
<PAGE>

INDEPENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.

We have audited the accompanying consolidated balance sheets of Progress Energy,
Inc.  and its  subsidiaries  as of December  31, 2002 and 2001,  and the related
consolidated statements of income, changes in common stock equity and cash flows
for each of the  three  years in the  period  ended  December  31,  2002.  These
financial  statements are the  responsibility of the Company's  management.  Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the  United  States of  America.  Those  standards  require  that we plan and
perform the audit to obtain  reasonable  assurance  about  whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In our  opinion,  such  financial  statements  present  fairly,  in all material
respects, the financial position of the Company and its subsidiaries at December
31, 2002 and 2001, and the results of their  operations and their cash flows for
each of the three years in the period ended  December 31,  2002,  in  conformity
with accounting principles generally accepted in the United States of America.

As discussed in Note 6 to the financial statements,  in 2002 the Company changed
its method of  accounting  for  goodwill to conform to  Statement  of  Financial
Accounting Standards No. 142.


/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003


                                       73
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
                                                                            Years ended December 31
(In thousands except per share data)                                 2002            2001            2000
---------------------------------------------------------------------------------------------------------------
Operating Revenues
   Utility                                                         $ 6,600,689     $ 6,556,561     $ 3,545,694
   Diversified business                                              1,344,431       1,528,819         223,228
---------------------------------------------------------------------------------------------------------------
      Total Operating Revenues                                       7,945,120       8,085,380       3,768,922
---------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
   Fuel used in electric generation                                  1,614,879       1,559,998         682,627
   Purchased power                                                     862,395         868,078         364,977
   Operation and maintenance                                         1,361,189       1,210,750         792,164
   Depreciation and amortization                                       820,279       1,067,073         735,353
   Taxes other than on income                                          386,254         379,830         162,268
Diversified business
   Cost of sales                                                     1,433,626       1,422,890          81,376
   Impairment of long-lived assets                                     363,822          42,852               -
   Other                                                                98,193         304,817         266,931
---------------------------------------------------------------------------------------------------------------
        Total Operating Expenses                                     6,940,637       6,856,288       3,085,696
---------------------------------------------------------------------------------------------------------------
Operating Income                                                     1,004,483       1,229,092         683,226
---------------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                      14,526          22,481          18,353
   Impairment of investments                                           (25,011)       (164,183)              -
   Gain on sale of investment                                                -               -         200,000
   Other, net                                                           33,804         (28,439)         15,423
---------------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                                    23,319        (170,141)        233,776
---------------------------------------------------------------------------------------------------------------
Interest Charges
   Net interest charges                                                641,574         689,694         261,570
   Allowance for borrowed funds used during construction                (8,133)        (16,801)        (18,992)
---------------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                    633,441         672,893         242,578
---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax                    394,361         386,058         674,424
Income Tax Expense (Benefit)                                          (157,808)       (154,338)        196,502
---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations                                      552,169         540,396         477,922
Discontinued Operations, net of tax                                    (23,783)          1,214             439
---------------------------------------------------------------------------------------------------------------
Net Income                                                         $   528,386     $   541,610     $   478,361
---------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding                                      217,247         204,683         157,169
---------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
    Income from Continuing Operations                              $      2.54     $      2.64     $      3.04
    Discontinued Operations, Net of Tax                                   (.11)            .01             .00
    Net Income                                                     $      2.43     $      2.65     $      3.04
---------------------------------------------------------------------------------------------------------------

Diluted Earnings per Common Share
    Income from Continuing Operations                              $      2.53     $      2.63     $      3.03
    Discontinued Operations, Net of Tax                                   (.11)            .01             .00
    Net Income                                                     $      2.42     $      2.64     $      3.03
---------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share                                $     2.195     $     2.135     $     2.075
---------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

                                       74
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands except per share data)                                                        December 31
Assets                                                                              2002                 2001
----------------------------------------------------------------------------------------------------------------------
Utility Plant
  Utility plant in service                                                       $  20,152,787           $ 19,176,021
  Accumulated depreciation                                                         (10,480,880)            (9,936,514)
----------------------------------------------------------------------------------------------------------------------
        Utility plant in service, net                                                9,671,907              9,239,507
  Held for future use                                                                   15,109                 15,380
  Construction work in progress                                                        752,336              1,004,011
  Nuclear fuel, net of amortization                                                    216,882                262,869
----------------------------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                                    10,656,234             10,521,767
----------------------------------------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                                             61,358                 53,708
  Accounts receivable                                                                  737,369                779,286
  Unbilled accounts receivable                                                         225,011                199,593
  Inventory                                                                            875,485                871,643
  Deferred fuel cost                                                                   183,518                146,652
  Assets of discontinued operations                                                    490,429                552,458
  Prepayments and other current assets                                                 283,036                294,460
----------------------------------------------------------------------------------------------------------------------
        Total Current Assets                                                         2,856,206              2,897,800
----------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                                                    393,215                463,837
  Nuclear decommissioning trust funds                                                  796,844                822,821
  Diversified business property, net                                                 1,884,271              1,072,123
  Miscellaneous other property and investments                                         463,776                441,932
  Goodwill                                                                           3,719,327              3,656,970
  Prepaid pension costs                                                                 60,169                487,551
  Other assets and deferred debits                                                     522,662                525,900
----------------------------------------------------------------------------------------------------------------------
        Total Deferred Debits and Other Assets                                       7,840,264              7,471,134
----------------------------------------------------------------------------------------------------------------------
           Total Assets                                                          $  21,352,704           $ 20,890,701
----------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
----------------------------------------------------------------------------------------------------------------------
Common Stock Equity
  Common stock without par value, 500,000,000 shares authorized, 237,992,513 and
      218,725,352 shares issued and outstanding,
      respectively                                                               $   4,950,558           $  4,121,194
  Unearned restricted shares (950,180 and 674,511 shares, respectively)                (21,454)               (13,701)
  Unearned ESOP shares (4,616,400 and 5,199,388 shares, respectively)                 (101,560)              (114,385)
  Accumulated other comprehensive loss                                                (237,762)               (32,180)
  Retained earnings                                                                  2,087,227              2,042,605
----------------------------------------------------------------------------------------------------------------------
        Total common stock equity                                                    6,677,009              6,003,533
----------------------------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-Not Subject to Mandatory Redemption                     92,831                 92,831
Long-Term debt                                                                       9,747,293              8,618,960
----------------------------------------------------------------------------------------------------------------------
        Total capitalization                                                        16,517,133             14,715,324
----------------------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                                    275,397                688,052
  Accounts payable                                                                     756,287                760,116
  Interest accrued                                                                     220,400                211,731
  Dividends declared                                                                   132,232                117,857
  Short-term obligations                                                               694,850                942,314
  Customer deposits                                                                    158,214                151,968
  Liabilities of discontinued operations                                               124,767                162,917
  Other current liabilities                                                            372,161                403,868
----------------------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                                    2,734,308              3,438,823
----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                                                    932,813              1,408,155
  Accumulated deferred investment tax credits                                          206,221                224,688
  Regulatory liabilities                                                               119,766                291,789
  Other liabilities and deferred credits                                               842,463                811,922
----------------------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                                 2,101,263              2,736,554
----------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 24)
----------------------------------------------------------------------------------------------------------------------
           Total Capitalization and Liabilities                                  $  21,352,704           $ 20,890,701
----------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements

                                       75
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
                                                                                             Years ended December 31
(In thousands)                                                                          2002            2001           2000
---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                            $   528,386    $   541,610    $   478,361
Adjustments to reconcile net income to net cash provided by operating activities:
      Loss (income) from discontinued operations                                           23,783         (1,214)          (439)
      Impairment of long-lived assets and investments                                     388,833        208,983              -
      Depreciation and amortization                                                     1,099,128      1,266,162        846,984
      Deferred income taxes                                                              (402,040)      (367,330)       (93,379)
      Investment tax credit                                                               (18,467)       (22,701)       (17,942)
      Gain on sale of investment                                                                -              -       (200,000)
      Deferred fuel cost (credit)                                                         (36,866)        68,705        (81,604)
      Net (increase) decrease  in accounts receivable                                     (45,172)       182,514        (34,754)
      Net (increase) decrease in inventories                                              (48,785)      (298,733)        15,931
      Net (increase) decrease in prepayments and other current assets                     (39,141)       (20,797)        57,141
      Net increase (decrease) in accounts payable                                          57,387       (162,940)       229,117
      Net  increase (decrease) in other current liabilities                                56,356        123,297       (148,813)
      Other                                                                                34,509        (94,806)      (197,725)
---------------------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                      1,597,911      1,422,750        852,878
---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions                                                       (1,174,220)    (1,177,727)      (853,584)
Diversified business property additions and acquisitions                                 (934,910)      (349,713)      (157,510)
Nuclear fuel additions                                                                    (80,573)      (115,663)       (59,752)
Acquisition of Florida Progress Corporation, net of cash                                        -              -     (3,441,775)
Net proceeds from sale of assets and investment                                            42,825         53,010        200,000
Net contributions to nuclear decommissioning trust                                        (18,502)       (50,649)       (32,391)
Investments in non-utility activities                                                     (27,030)       (15,043)       (89,351)
Other                                                                                     (19,424)             -              -
---------------------------------------------------------------------------------------------------------------------------------
          Net Cash Used in Investing Activities                                        (2,211,834)    (1,655,785)    (4,434,363)
---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net                                                             687,000        488,290              -
Issuance of long-term debt, net                                                         1,797,691      4,564,243        783,052
Net increase (decrease) in short-term indebtedness                                       (247,464)    (4,018,062)     3,782,071
Net increase (decrease) in cash provided by checks drawn in excess of bank balances            79        (45,372)       115,337
Retirement of long-term debt                                                           (1,157,286)      (322,207)      (710,373)
Dividends paid on common stock                                                           (479,981)      (432,078)      (368,004)
Other                                                                                      21,482        (47,127)           (66)
---------------------------------------------------------------------------------------------------------------------------------
           Net Cash Provided by Financing Activities                                      621,521        187,687      3,602,017
---------------------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Discontinued Operations                                             52           (843)           525
---------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                        7,650        (46,191)        21,057
Cash and Cash Equivalents at Beginning of Year                                             53,708         99,899         78,842
---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                              $    61,358    $    53,708    $    99,899
---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                      $   630,935    $   588,127    $   244,224
                            income taxes (net of refunds)                             $   219,278    $   127,427    $   367,665
</TABLE>

Noncash Activities
o   On June 28, 2000,  Caronet, Inc., a wholly owned  subsidiary of the Company,
    contributed  net assets in the amount of $93.0 million in exchange for a 35%
    ownership interest (15% voting interest) in a newly formed company.
o   On November  30,  2000,  the Company  purchased  all  outstanding  shares of
    Florida Progress Corporation.  In conjunction with the purchase, the Company
    issued  approximately  $1.9  billion  in common  stock and $49.3  million in
    contingent value obligations.
o   On April 26, 2002, Progress Fuels Corporation,  a subsidiary of the Company,
    acquired 100% of Westchester Gas Company.  In conjunction with the purchase,
    the Company issued approximately $129.0 million in common stock.

 See Notes to Consolidated Financial Statements

                                       76
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUITY
                                                                                   Unearned     Accumulated                  Total
                                                                       Unearned      ESOP          Other                    Common
(In thousands except share data)           Common Stock Outstanding   Restricted    Common     Comprehensive    Retained     Stock
                                              Shares      Amount          Stock      Stock     Income (Loss)    Earnings    Equity
-----------------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2000                     159,599,650  $ 1,753,393   $ (7,938) $ (140,153)  $         -   $ 1,807,345 $3,412,647
Net income                                                                                                       478,361    478,361
Issuance of shares                            46,527,797    1,863,886                                                     1,863,886
Purchase of restricted stock                                             (10,067)                                           (10,067)
Restricted stock expense recognition                                       3,671                                              3,671
Cancellation of restricted shares                (38,400)      (1,626)     1,626                                                  -
Allocation of ESOP shares                                       5,957                 12,942                                 18,899
Dividends ($2.075 per share)                                                                                    (343,196)  (343,196)
-----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000                   206,089,047    3,621,610    (12,708)   (127,211)            -     1,942,510  5,424,201
Net income                                                                                                       541,610    541,610
FAS 133 transition adjustment (net of
    tax of $15,130)                                                                                (23,567)                 (23,567)
Change in net unrealized losses on cash
    flow hedges (net of tax of $13,268)                                                            (20,703)                 (20,703)
Reclassification adjustment for amounts
    included in net income (net of tax of
      $8,739)                                                                                       13,647                   13,647
Foreign currency translation and other                                                              (1,557)                  (1,557)
                                                                                                                         -----------
Comprehensive income                                                                                                        509,430
                                                                                                                         -----------
Issuance of shares                            12,658,027      488,592                                                       488,592
Purchase of restricted stock                                              (7,992)                                            (7,992)
Restricted stock expense recognition                                       6,084                                              6,084
Cancellation of restricted shares                (21,722)        (915)       915                                                  -
Allocation of ESOP shares                                      11,907                 12,826                                 24,733
Dividends ($2.135 per share)                                                                                    (441,515)  (441,515)
------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001                   218,725,352    4,121,194    (13,701)   (114,385)      (32,180)    2,042,605  6,003,533
Net income                                                                                                       528,386    528,386
Change in net unrealized losses on cash
    flow hedges (net of tax of $17,712)                                                            (27,920)                 (27,920)
Reclassification adjustment for amounts
    included in net income (net of tax of
      $10,480)                                                                                      16,307                   16,307
Foreign currency translation and other                                                              (1,584)                  (1,584)
Minimum pension liability adjustment
      (net of tax of $120,903)                                                                    (192,385)                (192,385)
                                                                                                                         -----------
Comprehensive income                                                                                                        322,804
                                                                                                                         -----------
Issuance of shares                            19,282,212      815,393                                                       815,393
Purchase of restricted stock                                             (16,197)                                           (16,197)
Restricted stock expense recognition                                       7,709                                              7,709
Cancellation of restricted shares                (15,051)        (735)       735                                                  -
Allocation of ESOP shares                                      14,706                 12,825                                 27,531
Dividends ($2.195 per share)                                                                                    (483,764)  (483,764)
-----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002                   237,992,513  $ 4,950,558   $(21,454) $ (101,560)  $  (237,762)  $ 2,087,227 $6,677,009
===================================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements

                                       77
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In thousands except per share data)              First Quarter      Second Quarter         Third Quarter         Fourth Quarter
---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues                                 $1,787,302           $1,958,855           $2,277,040             $1,921,923
Operating income                                      241,981              305,288              200,221                256,993
Income from continuing operations                     124,062              121,933              157,073                149,101
Net income                                            132,527              120,620              151,934                123,305
Common stock data:
Basic earnings per common share
     Income from continuing operations                   0.58                 0.57                 0.73                   0.66
     Net income                                          0.62                 0.56                 0.70                   0.55
Diluted earnings per common share
     Income from continuing operations                   0.58                 0.56                 0.72                   0.66
     Net income                                          0.62                 0.56                 0.70                   0.55
Dividends paid per common share                         0.545                0.545                0.545                  0.545
Market price per share - High                           50.86                52.70                51.97                  44.82
                         Low                            43.01                47.91                36.54                  32.84
---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues                                 $1,755,839           $2,233,383           $2,265,223             $1,830,935
Operating income                                      295,611              288,898              455,475                189,108
Income (loss) from continuing operations              146,807              117,080              369,733                (93,224)
Net income (loss)                                     154,003              111,702              366,443                (90,538)
Common stock data:
Basic earnings per common share
     Income from continuing operations                   0.73                 0.59                 1.80                  (0.44)
     Net income                                          0.77                 0.56                 1.78                  (0.43)
Diluted earnings per common share
     Income from continuing operations                   0.73                 0.58                 1.79                  (0.44)
     Net income                                          0.77                 0.56                 1.77                  (0.42)
Dividends paid per common share                         0.530                0.530                0.530                  0.530
Market price per share - High                           49.25                45.00                45.79                  45.60
                         Low                            38.78                40.36                39.25                  40.50
</TABLE>


o   In the opinion of management,  all  adjustments  necessary to fairly present
    amounts shown for interim periods have been made.  Results of operations for
    an interim  period may not give a true  indication  of results for the year.
    All amounts were restated for discontinued operations (See Note 3A).
o   Second  quarter 2001  includes  seven months of revenue  related to Progress
    Rail  Services  due to  reversal  of net  assets  held for  sale  accounting
    treatment.
o   Fourth  quarter  2001  includes  impairment  and other  charges  related  to
    Strategic  Resource  Solutions Corp. and Interpath  Communications,  Inc. of
    $209.0 million ($152.8 million after tax) (See Note 7).
o   Third quarter 2002 includes impairment and other charges related to Progress
    Telecom,  Caronet  and  Interpath  Communications,  Inc.  of $355.4  million
    ($224.8 million after tax) (See Note 7).
o   Fourth quarter 2002 includes estimated impairment on assets held for sale of
    Railcar Ltd. of $58.8 million ($40.1 million after tax) (See Note 3B).

See Notes to Consolidated Financial Statements.

                                       78
<PAGE>



PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Organization and Summary of Significant Accounting Policies

    A. Organization

    Progress  Energy,  Inc.  (Progress  Energy or the  Company) is a  registered
    holding  company  under  the  Public  Utility  Holding  Company  Act of 1935
    (PUHCA),  as amended.  The Company and its  subsidiaries  are subject to the
    regulatory  provisions  of PUHCA.  The Company was formed as a result of the
    reorganization  of  Carolina  Power & Light  Company  (CP&L)  into a holding
    company structure (CP&L Energy, Inc.) on June 19, 2000. All shares of common
    stock of CP&L were  exchanged  for an equal number of shares of CP&L Energy,
    Inc.  On December 4, 2000,  the Company  changed its name from CP&L  Energy,
    Inc. to Progress Energy, Inc.

    Through its wholly owned  subsidiaries,  CP&L and Florida Power  Corporation
    (Florida  Power),  the  Company  is  primarily  engaged  in the  generation,
    transmission,  distribution  and sale of  electricity  in  portions of North
    Carolina, South Carolina and Florida. Through the Progress Ventures business
    unit, the Company is involved in nonregulated generation operations; natural
    gas fuel exploration and production; coal fuel extraction, manufacturing and
    delivery;  and energy  marketing  and trading  activities.  Through the Rail
    Services  business  unit,  the Company is involved in  nonregulated  railcar
    repair, rail parts  reconditioning and sales, railcar leasing and sales, and
    scrap metal recycling. Through its other business units, the Company engages
    in other  nonregulated  business  areas,  including  telecommunications  and
    holding  company  operations.  Progress  Energy's  legal  structure  is  not
    currently aligned with the functional  management and financial reporting of
    the Progress  Ventures business  segment.  Whether,  and when, the legal and
    functional  structures will converge depends upon legislative and regulatory
    action,  which cannot currently be anticipated.  Effective  January 1, 2003,
    CP&L, Florida Power and Progress  Ventures,  Inc. (PVI) began doing business
    under the assumed names Progress  Energy  Carolinas,  Inc., Progress  Energy
    Florida, Inc., and Progress Energy Ventures, Inc.,  respectively.  The legal
    names of these entities have not changed,  and there is no  restructuring of
    any kind related to the name change. The current corporate and business unit
    structure remains unchanged.

    The Company's results of operations  include the results of Florida Progress
    Corporation  (FPC)  for  the  periods   subsequent  to  November  30,  2000;
    therefore, periods presented may not be comparable (See Note 2C).

    B. Basis of Presentation

    The  consolidated  financial  statements  are  prepared in  accordance  with
    accounting  principles  generally  accepted in the United  States of America
    (GAAP) and include  the  activities  of the  Company and its  majority-owned
    subsidiaries.  Significant  intercompany balances and transactions have been
    eliminated  in  consolidation  except as permitted by Statement of Financial
    Accounting  Standards (SFAS) No. 71,  "Accounting for the Effects of Certain
    Types of Regulation,"  which provides that profits on intercompany  sales to
    regulated affiliates are not eliminated if the sales price is reasonable and
    the future  recovery of the sales price  through the  ratemaking  process is
    probable. See Note 1K for a discussion of SFAS No. 71.

    The accounting records of CP&L, Florida Power and North Carolina Natural Gas
    Corporation  (NCNG) are  maintained  in accordance  with uniform  systems of
    accounts prescribed by the Federal Energy Regulatory  Commission (FERC), the
    North Carolina Utilities Commission (NCUC), the Public Service Commission of
    South Carolina (SCPSC) and the Florida Public Service Commission (FPSC).

    Unconsolidated investments in companies over which the Company does not have
    control,  but has the  ability to  exercise  influence  over  operating  and
    financial  policies (generally 20% - 50% ownership), are accounted for under
    the equity method of accounting. Other investments are stated principally at
    cost. These equity and cost investments,  which total  approximately  $108.9
    million and $147.4 million at December 31, 2002 and 2001, respectively,  are
    included as miscellaneous other property and investments in the Consolidated
    Balance  Sheets.  The primary  component  of this  balance is the  Company's
    investments  in  affordable  housing of $72.3  million and $82.4  million at
    December 31, 2002 and 2001, respectively.  Included in the December 31, 2001
    investment balance is the Company's investment in Interpath  Communications,
    Inc. of $27.0 million.

                                       79
<PAGE>

    Results of  operations of Progress  Rail  Services  Corporation  and certain
    other diversified operations are recognized one month in arrears.

    Certain  amounts for 2001 and 2000 have been  reclassified to conform to the
    2002 presentation.

    C. Use of Estimates and Assumptions

    In  preparing  consolidated  financial  statements  that  conform with GAAP,
    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 consolidated financial statements and amounts
    of revenues and  expenses  reflected  during the  reporting  period.  Actual
    results could differ from those estimates.

    D. Cash

    The Company considers cash and cash equivalents to include unrestricted cash
    on hand,  cash in banks and temporary  investments  with a maturity of three
    months or less.

    E. Inventory

    The Company  accounts for inventory  using the  average-cost  method.  As of
    December 31, inventory was comprised of (in thousands):

                                            2002           2001
                                         ----------     ----------

    Fuel                                 $ 313,003      $ 296,772
    Rail equipment and parts               155,206        200,697
    Materials and supplies                 362,708        349,127
    Other                                   44,568         25,047
                                         ----------     ----------
    Total inventory                      $ 875,485      $ 871,643
                                         ==========     ==========

    F. Utility Plant

    Utility  plant in  service  is stated at  historical  cost less  accumulated
    depreciation.  The Company capitalizes all construction-related direct labor
    and  material  costs of units of property  as well as indirect  construction
    costs. The cost of renewals and betterments is also capitalized. Maintenance
    and repairs of property,  and  replacements and renewals of items determined
    to be less than units of  property,  are charged to  maintenance  expense as
    incurred.  The cost of units of property replaced,  renewed or retired, plus
    removal  or  disposal  costs,  less  salvage,   is  charged  to  accumulated
    depreciation.  Subsequent to the  acquisition  of FPC, the utility plants of
    FPC continue to be  presented  on a gross basis to reflect the  treatment of
    such plant in cost-based regulation.

    The balances of electric  utility plant in service at December 31 are listed
    below (in thousands), with a range of depreciable lives for each:

                                                   2002              2001
                                              -------------     -------------

    Production plant  (7-33 years)            $ 11,062,405      $ 10,670,717
    Transmission plant  (30-75 years)            2,104,520         2,013,243
    Distribution plant  (12-50 years)            6,072,901         5,767,788
    General plant and other (8-75 years)           912,961           724,273
                                              -------------     -------------
    Utility plant in service                  $ 20,152,787      $ 19,176,021
                                              =============     =============

    Generally,  electric  utility  plant other than  nuclear  fuel is pledged as
    collateral  for the first mortgage bonds of CP&L and Florida Power (See Note
    8).

                                       80
<PAGE>

    Allowance  for  funds  used  during  construction   (AFUDC)  represents  the
    estimated  debt and equity costs of capital  funds  necessary to finance the
    construction  of new  regulated  assets.  As  prescribed  in the  regulatory
    uniform systems of accounts,  AFUDC is charged to the cost of the plant. The
    equity  funds  portion of AFUDC is credited to other income and the borrowed
    funds  portion is  credited  to  interest  charges.  Regulatory  authorities
    consider AFUDC an  appropriate  charge for inclusion in the rates charged to
    customers by the utilities over the service life of the property.  The total
    equity  funds  portion of AFUDC was $8.7  million,  $8.8  million  and $13.6
    million in 2002, 2001 and 2000,  respectively.  The composite AFUDC rate for
    CP&L's  electric  utility  plant  was 6.2% in both 2002 and 2001 and 8.2% in
    2000. The composite  AFUDC rate for Florida Power's  electric  utility plant
    was 7.8% in 2002, 2001 and 2000.

    G. Depreciation and Amortization - Utility Plant

    For financial reporting purposes,  substantially all depreciation of utility
    plant other than nuclear fuel is computed on the straight-line  method based
    on the  estimated  remaining  useful  life  of the  property,  adjusted  for
    estimated net salvage.  Depreciation provisions,  including  decommissioning
    costs  (See Note 1H) and  excluding  accelerated  cost  recovery  of nuclear
    generating assets, as a percent of average  depreciable  property other than
    nuclear fuel, were approximately 3.6%, 4.0% and 4.1% in 2002, 2001 and 2000,
    respectively.  Total  depreciation  provisions were $730.3  million,  $804.1
    million and $707.5 million in 2002, 2001 and 2000, respectively.

    With  approval  from the  NCUC  and the  SCPSC,  CP&L  accelerated  the cost
    recovery  of its  nuclear  generating  assets  beginning  January  1,  2000.
    Cumulative  accelerated  depreciation  ranging  from  $530  million  to $750
    million will be recorded by December 31, 2009. The accelerated cost recovery
    of these assets resulted in additional depreciation expense of approximately
    $53  million,  $75  million  and  $275  million  in  2002,  2001  and  2000,
    respectively.  Total accelerated  depreciation recorded through December 31,
    2002 was $326 million for the North  Carolina  jurisdiction  and $77 million
    for the South Carolina jurisdiction (See Note 15C).

    Amortization of nuclear fuel costs, including disposal costs associated with
    obligations to the U.S. Department of Energy (DOE) and costs associated with
    obligations  to the DOE  for  the  decommissioning  and  decontamination  of
    enrichment  facilities,  is computed  primarily  on the  units-of-production
    method and charged to fuel used in electric  generation in the  accompanying
    Consolidated  Statements  of Income.  The total of these costs for the years
    ended December 31, 2002, 2001 and 2000 were $141.1  million,  $130.1 million
    and $114.6 million, respectively.

    Effective  January 1, 2002 the Company  adopted SFAS No. 142,  "Goodwill and
    Other  Intangible  Assets," and no longer  amortizes  goodwill (See Note 6).
    Prior to the adoption of SFAS No. 142, the Company  amortized  goodwill on a
    straight-line basis over a period not exceeding 40 years.  Intangible assets
    are being amortized on a straight-line basis over their respective lives.

    H. Decommissioning and Dismantlement Provisions

    In   the   Company's   retail   jurisdictions,    provisions   for   nuclear
    decommissioning  costs are approved by the NCUC,  the SCPSC and the FPSC 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
    jurisdictions, the provisions for nuclear decommissioning costs are approved
    by FERC. Decommissioning cost provisions, which are included in depreciation
    and  amortization  expense,  were $30.9  million,  $38.5  million  and $32.5
    million in 2002,  2001 and 2000,  respectively.  The Florida Power rate case
    settlement  required  Florida Power to suspend  accruals on its reserves for
    nuclear  decommissioning and fossil dismantlement  through December 31, 2005
    (See Note 15B).

    Accumulated   decommissioning  costs,  which  are  included  in  accumulated
    depreciation, were approximately $1.0 billion at December 31, 2002 and 2001.
    These costs  include  amounts  retained  internally  and  amounts  funded in
    externally-managed decommissioning trusts. Trust earnings increase the trust
    balance with a  corresponding  increase in the  accumulated  decommissioning
    balance. These balances are adjusted for unrealized gains and losses related
    to changes in the fair value of trust assets.

                                       81
<PAGE>

    CP&L's most recent  site-specific  estimates of  decommissioning  costs were
    developed  in 1998,  using  1998  cost  factors,  and are  based  on  prompt
    dismantlement  decommissioning,  which  reflects  the cost of removal of all
    radioactive  and other  structures  currently at the site, with such removal
    occurring shortly after operating license  expiration.  These estimates,  in
    1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for
    Brunswick  Unit No. 1, $298.7  million for  Brunswick  Unit No. 2 and $328.1
    million for the Harris Plant. The estimates are subject to change based on a
    variety of factors including,  but not limited to, cost escalation,  changes
    in technology applicable to nuclear  decommissioning and changes in federal,
    state  or  local  regulations.   The  cost  estimates  exclude  the  portion
    attributable  to  North  Carolina  Eastern  Municipal  Power  Agency  (Power
    Agency),  which holds an undivided  ownership  interest in the Brunswick and
    Harris nuclear generating facilities.  Operating licenses for CP&L's nuclear
    units expire in the years 2010 for Robinson  Unit No. 2, 2016 for  Brunswick
    Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.  An
    application  to extend the Robinson  license 20 years was submitted in 2002,
    and a similar  application  will be made for the Brunswick units in 2004. An
    extension  will also be sought for the Harris Plant,  tentatively  scheduled
    for 2009.

    Florida Power's most recent site-specific  estimate of decommissioning costs
    for the Crystal  River  Nuclear  Plant (CR3) was  developed in 2000 based on
    prompt  dismantlement  decommissioning.  The estimate,  in 2000 dollars,  is
    $490.9  million  and is  subject  to  change  based on the same  factors  as
    discussed above for CP&L's estimates. The cost estimate excludes the portion
    attributable to other  co-owners of CR3. CR3's operating  license expires in
    2016. An application to extend the plant license for 20 years is anticipated
    to be submitted in 2007.

    Management  believes that  decommissioning  costs that have been and will be
    recovered  through  rates by CP&L and Florida  Power will be  sufficient  to
    provide for the costs of decommissioning.

    Florida  Power  maintains  a reserve  for  fossil  plant  dismantlement.  At
    December 31, 2002 and 2001,  this reserve was  approximately  $141.6 million
    and  $140.5   million,   respectively,   and  was  included  in  accumulated
    depreciation.  The provision for fossil plant  dismantlement  was previously
    suspended per a 1997 FPSC settlement  agreement,  but resumed mid-2001.  The
    2001 annual provision,  approved by the FPSC, was $8.8 million.  The accrual
    for fossil dismantlement reserves was suspended again in 2002 by the Florida
    rate case settlement (See Note 15B).

    The  Financial  Accounting  Standards  Board (FASB) has issued SFAS No. 143,
    "Accounting  for  Asset  Retirement   Obligations,"  that  will  change  the
    accounting for the decommissioning and dismantlement provisions beginning in
    2003 (See Note 1U).

    I. Diversified Business Property

    Diversified   business   property   is  stated  at  cost  less   accumulated
    depreciation.  If an impairment  is  recognized on an asset,  the fair value
    becomes  its new cost  basis.  The costs of  renewals  and  betterments  are
    capitalized.  The cost of repairs and  maintenance  is charged to expense as
    incurred.  Depreciation  is  computed  on a  straight-line  basis  using the
    estimated  useful lives  indicated in the table below.  Depletion of mineral
    rights  is  provided  on  the  units-of-production  method  based  upon  the
    estimates of recoverable amounts of clean mineral.

    The Company uses the full cost method to account for its natural gas and oil
    properties.  Under the full cost method,  substantially  all  productive and
    nonproductive costs incurred in connection with the acquisition, exploration
    and  development  of natural gas and oil  reserves  are  capitalized.  These
    capitalized  costs  include the costs of all unproved  properties,  internal
    costs directly  related to acquisition  and  exploration  activities.  These
    costs are amortized  using the  units-of-production  method over the life of
    the Company's  proved  reserves.  Total  capitalized  costs are limited to a
    ceiling  based on the  present  value of  discounted  (at  10%)  future  net
    revenues using current  prices,  plus the lower of cost or fair market value
    of unproved properties. If the ceiling (discounted revenues) is not equal to
    or  greater  than total  capitalized  costs,  the  Company  is  required  to
    write-down  capitalized  costs to this  level.  The  Company  performs  this
    ceiling test  calculation  every quarter.  No  write-downs  were required in
    2002, 2001 or 2000.

    The Company's  nonregulated  businesses capitalize interest costs under SFAS
    No. 34,  "Capitalizing  Interest  Costs." During the year ended December 31,
    2002,  the Company  capitalized  $38.2  million of its  interest  expense of
    $679.8  million  related to the  expansion  of its  nonregulated  generation
    portfolio at PVI.  Capitalized  interest is included in diversified business
    property, net on the Consolidated Balance Sheets.

                                       82
<PAGE>

    Diversified business  depreciation expense was $86.2 million,  $72.3 million
    and $18.5 million at December 31, 2002, 2001 and 2000, respectively.

    The following is a summary of diversified  business  property (in thousands)
    as of December 31, with ranges of depreciable lives:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                        2002            2001
                                                                   ------------    ------------

    Equipment (3 - 25 years)                                       $   298,747     $   228,673
    Nonregulated generation plant and equipment (3 - 40 years)         549,115         108,512
    Land and mineral rights                                             89,506          76,598
    Buildings and plants (5 - 40 years)                                153,186         125,032
    Oil and gas properties (units-of-production)                       264,767          41,413
    Telecommunications equipment (5 - 20 years)                         42,514         266,603
    Rail equipment (3 - 20 years)                                       48,279          54,105
    Marine equipment (3 - 35 years)                                     80,501          78,868
    Computers, office equipment and software (3 - 10 years)             33,575          42,855
    Construction work in progress                                      643,742         342,179
    Accumulated depreciation                                          (319,661)       (292,715)
                                                                   ------------    ------------

    Diversified business property, net                             $ 1,884,271     $ 1,072,123
                                                                   ============    ============
</TABLE>

    During 2002, the Company recorded asset  impairments  related to assets held
    by the Company's telecommunications operations (See Note 7).

    J. Impairment of Long-Lived Assets and Investments

    The Company reviews the  recoverability  of long-lived and intangible assets
    whenever  indicators  exist.  Examples of these  indicators  include current
    period  losses,  combined  with a  history  of  losses  or a  projection  of
    continuing  losses,  or a  significant  decrease  in the  market  price of a
    long-lived  asset group.  If an  indicator  exists for assets to be held and
    used,  then the asset group is tested for  recoverability  by comparing  the
    carrying  value  to the  sum of  undiscounted  expected  future  cash  flows
    directly  attributable  to the  asset  group.  If  the  asset  group  is not
    recoverable  through  undiscounted  cash  flows or the asset  group is to be
    disposed  of,  then an  impairment  loss is  recognized  for the  difference
    between  the  carrying  value  and the fair  value of the asset  group.  The
    accounting  for  impairment of assets is based on SFAS No. 144,  "Accounting
    for the  Impairment or Disposal of Long-Lived  Assets," which was adopted by
    the  Company  effective  January  1,  2002.  Prior to the  adoption  of this
    standard, impairments were accounted for under SFAS No. 121, "Accounting for
    the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
    Of," which was  superceded  by SFAS No. 144. See Note 7 for a discussion  of
    impairment evaluations performed and charges taken.

    K. Cost-Based Regulation

    The Company's  regulated  operations are subject to SFAS No. 71, "Accounting
    for the  Effects  of  Certain  Types of  Regulation."  SFAS No.  71 allows a
    regulated  company  to record  costs  that have been or are  expected  to be
    allowed in the ratemaking  process in a period  different from the period in
    which the costs  would be charged to expense by a  nonregulated  enterprise.
    Accordingly, the Company records assets and liabilities that result from the
    regulated  ratemaking  process  that  would not be  recorded  under GAAP for
    nonregulated  entities.  These regulatory  assets and liabilities  represent
    expenses  deferred for future  recovery from  customers or obligations to be
    refunded to  customers  and are  primarily  classified  in the  accompanying
    Consolidated Balance Sheets as regulatory assets and regulatory  liabilities
    (See Note 15A).

    L. Income Taxes

    The  Company  and its  affiliates  file a  consolidated  federal  income tax
    return.  Deferred income taxes have been provided for temporary differences.
    These occur when there are  differences  between  the book and tax  carrying
    amounts  of assets  and  liabilities.  Investment  tax  credits  related  to
    regulated  operations  have been deferred and are being  amortized  over the
    estimated service life of the related properties. Credits for the production
    and sale of synthetic fuel are deferred to the extent they cannot be or have
    not been utilized in the annual consolidated federal income tax returns (See
    Note 20).

                                       83
<PAGE>

    M. Excise Taxes

    CP&L and Florida Power collect from customers certain excise taxes levied by
    the state or local  government  upon the  customers.  CP&L and Florida Power
    account for excise taxes on a gross basis.  For the years ended December 31,
    2002,  2001 and 2000,  gross receipts tax,  franchise taxes and other excise
    taxes of  approximately  $211.0  million,  $209.8 million and $84.0 million,
    respectively, are included in taxes other than on income in the accompanying
    Consolidated  Statements  of  Income.  These  approximate  amounts  are also
    included in utility revenues.

    N. Derivatives

    Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
    Derivative  Instruments and Hedging Activities," as amended by SFAS No. 138.
    SFAS No. 133, as amended, establishes accounting and reporting standards for
    derivative instruments, including certain derivative instruments embedded in
    other contracts,  and for hedging activities.  SFAS No. 133 requires that an
    entity  recognize all  derivatives  as assets or  liabilities in the balance
    sheet  and  measure  those  instruments  at  fair  value.  See  Note  16 for
    information    regarding   risk   management   activities   and   derivative
    transactions.

    In connection  with the January 2003 FASB Emerging  Issues Task Force (EITF)
    meeting,  the FASB was requested to reconsider an interpretation of SFAS No.
    133.   The   interpretation,   which  is   contained   in  the   Derivatives
    Implementation  Group's C11  guidance,  relates to the pricing of  contracts
    that include broad market indices.  In particular,  that guidance  discusses
    whether the pricing in a contract that contains  broad market indices (e.g.,
    CPI) could qualify as a normal purchase or sale (the normal purchase or sale
    term is a defined  accounting  term,  and may not,  in all  cases,  indicate
    whether the contract would be "normal" from an operating entity  viewpoint).
    The Company is currently  re-evaluating which  contracts,  if any, that have
    previously  been  designated  as  normal  purchases  or sales  would now not
    qualify for this exception.  The Company is currently evaluating the effects
    that this  guidance  will have on its results of  operations  and  financial
    position.

    O. Allowance for Doubtful Accounts

    The Company maintains an allowance for doubtful accounts  receivable,  which
    totaled  approximately  $39.6 million and $38.7 million at December 31, 2002
    and 2001, respectively.

    P. Unamortized Debt Premiums, Discounts and Expenses

    Long-term debt premiums,  discounts and issuance  expenses for the utilities
    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 by the utilities are amortized  over the  applicable  life
    using the straight-line method consistent with ratemaking treatment.

    Q. Revenue Recognition

    The Company  recognizes  electric utility revenues as service is rendered to
    customers.  Operating  revenues include  unbilled  electric utility revenues
    earned  when  service  has been  delivered  but not billed by the end of the
    accounting period. Diversified business revenues are generally recognized at
    the  time  products  are  shipped  or  as  services  are  rendered.  Leasing
    activities are accounted for in accordance with SFAS No. 13, "Accounting for
    Leases." Gains and losses from energy  trading  activities are reported on a
    net  basis.   Revenues  related  to  design  and  construction  of  wireless
    infrastructure are recognized upon completion of services for each completed
    phase of design and construction.

    R. Fuel Cost Deferrals

    Fuel expense  includes  fuel costs or recoveries  that are deferred  through
    fuel  clauses  established  by the  electric  utilities'  regulators.  These
    clauses  allow the utilities to recover fuel costs and portions of purchased
    power costs through surcharges on customer rates.

                                       84
<PAGE>

    S. Environmental

    The Company accrues environmental  remediation liabilities when the criteria
    for SFAS No. 5, "Accounting for Contingencies," has been met.  Environmental
    expenditures  are  expensed as incurred or  capitalized  depending  on their
    future economic benefit.  Expenditures that relate to an existing  condition
    caused by past  operations  and that have no future  economic  benefits  are
    expensed.  Accruals  for  estimated  losses from  environmental  remediation
    obligations  generally  are  recognized  no  later  than  completion  of the
    remedial  feasibility  study.  Such  accruals  are  adjusted  as  additional
    information  develops or circumstances  change. Costs of future expenditures
    for  environmental  remediation  obligations  are not  discounted  to  their
    present  value.  Recoveries of  environmental  remediation  costs from other
    parties are recognized when their receipt is deemed probable (See Note 24E).

    T. Benefit Plans

    The Company follows the guidance in SFAS No. 87, "Employers'  Accounting for
    Pensions," to account for its defined benefit  retirement plans. In addition
    to pension  benefits,  the Company  provides other  postretirement  benefits
    which are  accounted  for under SFAS No.  106,  "Employers'  Accounting  for
    Postretirement  Benefits  Other  Than  Pensions."  See  Note 18 for  related
    disclosures for these plans.

    U. New Accounting Standards

    SFAS No. 143, "Accounting for Asset Retirement Obligations"
    The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
    in July 2001. This statement provides accounting and disclosure requirements
    for  retirement   obligations  associated  with  long-lived  assets  and  is
    effective January 1, 2003. This statement requires that the present value of
    retirement costs for which the Company has a legal obligation be recorded as
    liabilities  with  an  equivalent   amount  added  to  the  asset  cost  and
    depreciated over an appropriate  period. The liability is then accreted over
    time  by  applying  an  interest  method  of  allocation  to the  liability.
    Cumulative accretion and accumulated depreciation will be recognized for the
    time period from the date the liability  would have been  recognized had the
    provisions of this statement been in effect, to the date of adoption of this
    statement.  The  cumulative  effect of initially  applying this statement is
    recognized  as a  change  in  accounting  principle.  The  adoption  of this
    statement  will have no impact on the income of regulated  entities,  as the
    effects are expected to be offset by the  establishment of regulatory assets
    or liabilities pursuant to SFAS No. 71.

    The Company's review  identified  legal  retirement  obligations for nuclear
    decommissioning  of radiated  plant,  coal mine  operations,  synthetic fuel
    operations and gas production.  The Company will record liabilities pursuant
    to SFAS No. 143  beginning in 2003.  The Company used an expected  cash flow
    approach to measure the obligations.  The following proforma liabilities, as
    of December 31, reflect amounts as if this statement had been applied during
    all periods:

    (in millions)                        2002               2001
                                      ----------        -----------
    Regulated:
       Nuclear decommissioning        $ 1,182.5          $ 1,117.7
    Nonregulated:
       Coal mine operations               $ 6.1              $ 5.6
       Synfuel operations                   2.0                1.7
       Gas production                       2.2                2.0

    Nuclear  decommissioning  and coal mine operations have  previously-recorded
    liabilities.  Amounts recorded for nuclear decommissioning of radiated plant
    were  $775.1  million  and $737.1  million at  December  31,  2002 and 2001,
    respectively.  Amounts  recorded for coal mine reclamation were $4.7 million
    and $4.8 million at December 31, 2002 and 2001, respectively. Synthetic fuel
    operations and gas production have no previously-recorded liabilities.

    Proforma net income and earnings per share have not been  presented  for the
    years ended December 31, 2002, 2001 or 2000 because the proforma application
    of SFAS No. 143 to prior  periods  would  result in proforma  net income and
    earnings per share not materially different from the actual amounts reported
    for those periods in the accompanying Consolidated Statements of Income.

                                       85
<PAGE>

    The Company has identified but not recognized  asset  retirement  obligation
    (ARO) liabilities  related to electric  transmission and  distribution,  gas
    distribution and  telecommunications  assets as the result of easements over
    property not owned by the Company.  These easements are generally  perpetual
    and only require  retirement  action upon abandonment or cessation of use of
    the property for the specified  purpose.  The ARO liability is not estimable
    for such  easements  as the  Company  intends  to utilize  these  properties
    indefinitely.  In the event the Company  decides to abandon or cease the use
    of a particular easement, an ARO liability would be recorded at that time.

    The utilities  have  previously  recognized  removal costs as a component of
    depreciation in accordance with  regulatory  treatment.  To the extent these
    amounts do not represent  SFAS No. 143 legal  retirement  obligations,  they
    will be disclosed as regulatory liabilities upon adoption of the standard.

    SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
    FASB  Statement No. 13, and Technical  Corrections"
    In April 2002, the FASB issued SFAS No. 145,  "Rescission of FASB Statements
    No. 4, 44,  and 64,  Amendment  of FASB  Statement  No.  13,  and  Technical
    Corrections."  This newly issued  statement  rescinds SFAS No. 4, "Reporting
    Gains and Losses from  Extinguishment  of Debt (an  amendment of APB Opinion
    No.  30)," which  required all gains and losses from the  extinguishment  of
    debt to be aggregated and, if material, classified as an extraordinary item,
    net of related income tax effect. As a result, the criteria set forth by APB
    Opinion 30 will now be used to classify those gains and losses.  Any gain or
    loss on extinguishment will be recorded in the most appropriate line item to
    which it relates within net income before extraordinary items. For regulated
    companies,  any expenses or call premiums  associated with the reacquisition
    of debt  obligations  are  amortized  over the  applicable  life  using  the
    straight-line  method  consistent with  ratemaking  treatment (See Note 1P).
    SFAS  No.  145 also  amends  SFAS  No.  13 to  require  that  certain  lease
    modifications   that  have  economic   effects  similar  to   sale-leaseback
    transactions  be  accounted  for  in  the  same  manner  as   sale-leaseback
    transactions.  In addition, SFAS No. 145 amends other existing authoritative
    pronouncements  to make various technical  corrections,  clarify meanings or
    describe their applicability  under changed  conditions.  For the provisions
    related to the  rescission  of SFAS No. 4, SFAS No. 145 is effective for the
    Company beginning in fiscal year 2004. The remaining  provisions of SFAS No.
    145 are  effective  for the  Company  in fiscal  year 2003.  The  Company is
    currently  evaluating the effects,  if any, that this statement will have on
    its results of operations and financial position.

    SFAS No. 148,  "Accounting  for  Stock-Based  Compensation"
    In December 2002, the FASB issued SFAS No. 148,  "Accounting for Stock-Based
    Compensation  - Transition  and Disclosure -- an Amendment of FASB Statement
    No. 123," and provided  alternative  methods of  transition  for a voluntary
    change to the fair value-based method of accounting for stock-based employee
    compensation. In addition, this statement amends the disclosure requirements
    of SFAS No.  123,  "Accounting  for  Stock-Based  Compensation,"  to require
    prominent  disclosures in both annual and interim financial statements about
    the method of  accounting  for  stock-based  employee  compensation  and the
    effect of the method used on reported results.  This statement requires that
    companies   follow  the   prescribed   format  and  provide  the  additional
    disclosures  in their annual  reports for years  ending  after  December 15,
    2002. The Company applies the recognition and measurement  principles of APB
    Opinion No. 25,  "Accounting  for Stock Issued to  Employees," as allowed by
    SFAS Nos. 123 and 148, and related  interpretations  in  accounting  for its
    stock-based compensation plans, as described in Note 17.

                                       86
<PAGE>

    For  purposes of the  proforma  disclosures  required  by SFAS No. 148,  the
    estimated  fair  value of the  options  is  amortized  to  expense  over the
    options' vesting period. Under SFAS No. 123, compensation expense would have
    been $13.5  million  and $2.9  million in 2002 and 2001,  respectively.  The
    stock  option  plan was not in effect  in 2000.  The  Company's  information
    related to the proforma impact on earnings and earnings per share follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


    (in thousands except per share data)                            2002        2001         2000
                                                                 ----------   ----------  ----------
    Net income, as reported                                      $ 528,386    $ 541,610   $ 478,361
    Deduct:  Total stock option expense determined under fair
       value method for all awards, net of related tax effects       8,036        1,765           -
                                                                 ----------   ----------  ----------
    Proforma net income                                          $ 520,350    $ 539,845   $ 478,361
                                                                 ==========   ==========  ==========
    Earnings per share:
      Basic - as reported                                            $2.43        $2.65       $3.04
      Basic - proforma                                               $2.40        $2.64       $3.04

      Diluted - as reported                                          $2.42        $2.64       $3.03
      Diluted - proforma                                             $2.39        $2.63       $3.03
</TABLE>

    FIN  No.  45,  "Guarantor's   Accounting  and  Disclosure  Requirements  for
    Guarantees, Including Indirect Guarantees of Indebtedness of Others"
    In  November  2002,  the FASB  issued  Interpretation  No. 45,  "Guarantor's
    Accounting and Disclosure  Requirements for Guarantees,  Including  Indirect
    Guarantees of Indebtedness of Others - an  Interpretation of FASB Statements
    No. 5, 57 and 107 and  Rescission  of FASB  Interpretation  No. 34" (FIN No.
    45). This interpretation clarifies the disclosures to be made by a guarantor
    in its interim  and annual  financial  statements  about  obligations  under
    certain guarantees that it has issued. It also clarifies that a guarantor is
    required to recognize,  at the inception of certain guarantees,  a liability
    for the fair value of the  obligation  undertaken in issuing the  guarantee.
    The  initial  recognition  and  initial   measurement   provisions  of  this
    interpretation are applicable on a prospective basis to guarantees issued or
    modified after December 31, 2002. The disclosure  requirements are effective
    for financial  statements of interim or annual periods ending after December
    15, 2002. The applicable  disclosures  required by FIN No. 45 have been made
    in Notes 9 and 24C. The Company is currently evaluating the effects, if any,
    that  this  interpretation  will  have  on its  results  of  operations  and
    financial position.

    FIN No. 46, "Consolidation of Variable Interest Entities"
    In January 2003, the FASB issued  Interpretation  No. 46,  "Consolidation of
    Variable  Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
    This  interpretation  provides  guidance  related  to  identifying  variable
    interest entities (previously known as special purpose entities or SPEs) and
    determining   whether  such  entities   should  be   consolidated.   Certain
    disclosures  are  required  when  FIN  No.  46  becomes  effective  if it is
    reasonably possible that a company will consolidate or disclose  information
    about a variable  interest entity when it initially applies FIN No. 46. This
    interpretation  must be applied  immediately to variable  interest  entities
    created or obtained  after  January 31, 2003.  For those  variable  interest
    entities created or obtained on or before January 31, 2003, the Company must
    apply the provisions of FIN No. 46 in the third quarter of 2003.

    The Company has an arrangement  with Railcar Asset  Financing  Trust (RAFT),
    through its Railcar Ltd. subsidiary, to which this interpretation may apply.
    Because the Company  expects to sell Railcar Ltd. during 2003 (See Note 3B),
    the application of FIN No. 46 is not expected to have a material impact with
    respect to this  arrangement.  The  Company  is  currently  evaluating  what
    effects,  if any, this interpretation will have on its results of operations
    and financial position.

    EITF Issue 02-03,  "Accounting for Contracts  Involved in Energy Trading and
    Risk Management Activities."
    In June 2002,  the EITF  reached a  consensus  on a portion of Issue  02-03,
    "Accounting  for Contracts  Involved in Energy  Trading and Risk  Management
    Activities."  EITF Issue 02-03  requires  all gains and losses  (realized or
    unrealized)  on  energy  trading  contracts  to be shown  net in the  income
    statement.  The Company's policy already required the gains and losses to be
    recorded  on a net  basis.  The net of the gains and losses is  recorded  in
    diversified  business revenue and other, net on the Consolidated  Statements
    of Income. The Company does not recognize a dealer profit or unrealized gain
    or loss at the  inception  of a  derivative  unless  the fair  value of that
    instrument, in its entirety, is evidenced by quoted market prices or current
    market transactions.

                                       87
<PAGE>

2.  Acquisitions

    A. Generation Acquisition

    On February 15, 2002, PVI acquired 100% of two electric  generating projects
    located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. The
    two projects  consist of 1) Walton County Power, LLC in Monroe,  Georgia,  a
    460 megawatt  natural  gas-fired plant placed in service in June 2001 and 2)
    Washington County Power, LLC in Washington  County,  Georgia,  a planned 600
    megawatt  natural  gas-fired  plant expected to be operational by June 2003.
    The  Walton  and  Washington  projects  have  been  accounted  for using the
    purchase  method of  accounting  and  accordingly  have been included in the
    consolidated financial statements since the acquisition date.

    In the final allocation,  the aggregate cash purchase price of approximately
    $347.9 million was allocated to diversified  business property,  intangibles
    and  goodwill  for  $250.4   million,   $33.4  million  and  $64.1  million,
    respectively.  Of the acquired intangible assets, $33.0 million was assigned
    to tolling and power sale  agreements with LG&E Energy  Marketing,  Inc. for
    each project and is being amortized through December 31, 2004.  Goodwill was
    assigned to the Progress  Ventures  segment and will be  deductible  for tax
    purposes (See Note 6).

    In addition,  PVI entered into a project management and completion agreement
    whereby LG&E Energy Corp.  agreed to manage the completion of the Washington
    site  construction for PVI. As of December 31, 2002, the remaining  payments
    related to the agreement are estimated to be $57.8 million.  The Company has
    guaranteed  certain payments on behalf of PVI related to the construction of
    the facility (See Note 24C).

    The proforma results of operations  reflecting the acquisition  would not be
    materially  different than the reported  results of operations for the years
    ended December 31, 2002 or 2001.

    B. Westchester Acquisition

    On April 26, 2002, Progress Fuels Corporation (Progress Fuels), a subsidiary
    of Progress Energy,  acquired 100% of Westchester Gas Company (Westchester).
    The acquisition included  approximately 215 natural  gas-producing wells, 52
    miles of  intrastate  gas  pipeline and 170 miles of  gas-gathering  systems
    located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
    border.

    The aggregate purchase price of approximately $153 million consisted of cash
    consideration of  approximately  $22 million and the issuance of 2.5 million
    shares of Progress Energy common stock valued at approximately $129 million.
    The purchase price included  approximately $2 million of direct  transaction
    costs. The purchase price has been  preliminarily  allocated to fixed assets
    including oil and gas properties,  based on the  preliminary  fair values of
    the assets acquired. The preliminary purchase price allocation is subject to
    adjustment for changes in the  preliminary  assumptions  pending  additional
    information, including final asset valuations.

    The  acquisition  has been  accounted  for  using  the  purchase  method  of
    accounting and, accordingly,  the results of operations for Westchester have
    been included in Progress Energy's  consolidated  financial statements since
    the date of acquisition.  The proforma results of operations  reflecting the
    acquisition  would not be materially  different than the reported results of
    operations for the years ended December 31, 2002 or 2001.

    C. Florida Progress Corporation Acquisition

    On November  30,  2000,  the Company  completed  its  acquisition  of FPC, a
    diversified,  exempt  electric  utility  holding  company,  for an aggregate
    purchase  price  of  approximately  $5.4  billion.  The  Company  paid  cash
    consideration of  approximately  $3.5 billion and issued 46.5 million common
    shares valued at approximately $1.9 billion. In addition, the Company issued
    98.6 million  contingent  value  obligations  (CVOs) valued at approximately
    $49.3 million (See Note 10). The purchase  price  included  $20.1 million in
    direct transaction costs.

                                       88
<PAGE>

    The  acquisition  was accounted for using the purchase  method of accounting
    and,  accordingly,  the results of operations  for FPC have been included in
    the  Company's   consolidated   financial   statements  since  the  date  of
    acquisition. The excess of the purchase price over the fair value of the net
    identifiable assets and liabilities  acquired was recorded as goodwill.  The
    goodwill,   of  approximately  $3.6  billion,   was  being  amortized  on  a
    straight-line  basis over a period of 40 years.  Effective  January 1, 2002,
    goodwill is no longer subject to amortization (See Note 6).

    The U.S. Securities and Exchange Commission (SEC) order approving the merger
    requires  the Company to divest of Rail  Services  and  certain  immaterial,
    nonregulated  investments  of FPC by  November  30,  2003.  The  Company  is
    evaluating  opportunities  and actively  marketing these investments but may
    not find the right  divestiture  opportunity  by that date.  Therefore,  the
    Company plans to seek an extension from the SEC.

3.  Divestitures

    A. NCNG Divestiture

    On October 16, 2002, the Company announced the Board of Directors'  approval
    to sell NCNG and the Company's  equity  investment in Eastern North Carolina
    Natural Gas Company  (ENCNG) to Piedmont  Natural  Gas  Company,  Inc.,  for
    approximately $400 million in net proceeds. The sale is expected to close by
    summer  of 2003 and must be  approved  by the  NCUC and  federal  regulatory
    agencies.

    The accompanying  consolidated  financial  statements have been restated for
    all periods  presented  for the  discontinued  operations  of NCNG.  The net
    income of these  operations  is reported as  discontinued  operations in the
    Consolidated  Statements of Income. Interest expense of $15.6 million, $14.5
    million and $13.6  million for the years ended  December 31, 2002,  2001 and
    2000,  respectively,  has been allocated to discontinued operations based on
    the net assets of NCNG, assuming a uniform  debt-to-equity  ratio across the
    Company's operations.  The Company ceased recording  depreciation  effective
    October  1,  2002,  upon   classification  of  the  assets  as  discontinued
    operations.  The asset group,  including goodwill, has been recorded at fair
    value less cost to sell,  resulting  in an  estimated  loss on  disposal  of
    approximately  $29.4 million,  which has been recorded until the disposition
    is complete and the actual loss can be determined.  Results of  discontinued
    operations for years ended December 31, were as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


    (in thousands)                                                   2002          2001          2000
                                                                 ----------    ----------     -----------
    Revenues                                                     $ 299,820     $ 321,422      $ 330,365
                                                                 ==========    ==========     ===========

    Earnings before income taxes                                 $   8,944     $   3,909      $   6,711
    Income tax expense                                               3,350         2,695          6,272
                                                                 ----------    ----------     -----------
    Net earnings from discontinued operations                        5,594         1,214            439

    Estimated loss on disposal of discontinued operations,
         including applicable income tax expense of $3,214         (29,377)            -              -
                                                                 ----------   -----------     -----------
    Earnings (loss) from discontinued operations                 $ (23,783)    $   1,214      $     439
                                                                 ==========   ===========     ===========
</TABLE>

    The major  balance  sheet  classes  included  in assets and  liabilities  of
    discontinued  operations in the Consolidated  Balance Sheets, as of December
    31, are as follows:

    (in thousands)                                       2002           2001
                                                      ----------    ----------
    Utility plant, net                                $ 398,931     $ 393,149
    Current assets                                       72,821       116,969
    Deferred debits and other assets                     18,677        42,340
                                                      ----------    ----------
         Assets of discontinued operations            $ 490,429     $ 552,458
                                                      ==========    ==========

    Current liabilities                                $ 76,372     $ 126,208
    Deferred credits and other liabilities               48,395        36,709
                                                      ----------    ----------
         Liabilities of discontinued operations       $ 124,767     $ 162,917
                                                      ==========    ==========
                                       89
<PAGE>

    The Company's equity  investment in ENCNG of $7.7 million as of December 31,
    2002 is included in  miscellaneous  other  property and  investments  in the
    Consolidated Balance Sheets.

    B.  Railcar Ltd. Divestiture

    In  December  2002,  the  Progress  Energy  Board  of  Directors  adopted  a
    resolution  approving the sale of Railcar Ltd., a subsidiary included in the
    Rail Services  segment.  A series of sales  transactions is expected to take
    place throughout 2003. In accordance with SFAS No. 144,  "Accounting for the
    Impairment  or Disposal of  Long-Lived  Assets," an estimated  impairment on
    assets held for sale of $58.8 million has been recognized for the write-down
    of the  assets  to be sold to fair  value  less  the  costs  to  sell.  This
    impairment  has been  included in  impairment  of  long-lived  assets in the
    Consolidated Statements of Income (See Note 7).

    The assets of Railcar Ltd. have been grouped as assets held for sale and are
    included in other current  assets on the  Consolidated  Balance Sheets as of
    December 31, 2002. The assets are recorded at $23.6 million,  which reflects
    the  Company's  initial  estimate of the fair value  expected to be realized
    from the sale of these assets. The primary component of assets held for sale
    is current  assets of $21.6  million.  These  assets are  subject to certain
    commitments  under operating leases (See Note 12). The Company expects to be
    relieved of the majority of these commitments as a result of the sale.

    C. Inland Marine Transportation Divestiture

    During  2001,   the  Company   completed  the  sale  of  its  Inland  Marine
    Transportation  business  operated by MEMCO Barge  Line,  Inc.,  and related
    investments  to AEP Resources,  Inc., a wholly owned  subsidiary of American
    Electric  Power,  for a sales  price of $270  million.  Of the $270  million
    purchase  price,  $230 million was used to pay early  termination of certain
    off-balance  sheet  arrangements  for  assets  leased  by the  business.  In
    connection   with  the  sale,   the  Company   entered  into   environmental
    indemnification  provisions  covering both known and unknown sites (See Note
    24E).

    The Company  adjusted the FPC purchase  price  allocation to reflect a $15.0
    million  negative net realizable  value of the Inland Marine  business.  The
    Company's  results of operations  exclude Inland Marine  Transportation  net
    income of $9.1  million for 2001 and $1.8  million for the month of December
    2000.  These earnings were included in the  determination  of net realizable
    value for the purchase price allocation.

    D. BellSouth Carolinas PCS Partnership Interest Divestiture

    In September 2000,  Caronet,  Inc.  (Caronet),  a wholly owned subsidiary of
    CP&L, sold its 10% limited  partnership  interest in BellSouth Carolinas PCS
    for $200 million. The sale resulted in an after-tax gain of $121.1 million.

4.  Financial Information by Business Segment

    The Company  currently  provides  services  through the  following  business
    segments:  CP&L Electric,  Florida Power Electric,  Progress Ventures,  Rail
    Services and Other.

    The CP&L  Electric and Florida  Power  Electric  segments are engaged in the
    generation,  transmission,  distribution  and  sale of  electric  energy  in
    portions of North  Carolina,  South  Carolina  and Florida.  These  electric
    operations  are subject to the rules and  regulations of FERC, the NCUC, the
    SCPSC and the FPSC.

    The Progress Ventures segment  operations  include  nonregulated  generation
    operations;  natural gas exploration and production;  coal fuel  extraction,
    manufacturing  and  delivery;  and  energy  marketing  and  limited  trading
    activities on behalf of the utility  operating  companies as well as for its
    nonregulated plants.  Management reviews the operations of the segment after
    the allocation of energy  marketing and trading  activities,  which Progress
    Ventures  performs on behalf of the  regulated  utilities,  CP&L and Florida
    Power.

    The Rail Services  segment  operations  include railcar  repair,  rail parts
    reconditioning  and  sales,  railcar  leasing  and  sales,  and scrap  metal
    recycling.  These  activities  include  maintenance  and  reconditioning  of
    salvageable scrap components of railcars, locomotive repair and right-of-way
    maintenance.  Included in this segment is an estimated  impairment on assets
    held for sale (See Note 3B).

                                       90
<PAGE>

    The Other segment is made up of other nonregulated  business areas including
    telecommunications   and  holding  company   operations.   The  discontinued
    operations  related to the sale of NCNG are not  included  in the  operating
    segments below (See Note 3A).
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(In thousands)                                           Florida
                                                          Power                      Rail
                                              CP&L      Electric     Progress      Services               Consolidated
                                            Electric      (c)        Vendures        (b)        Other        Totals
FOR THE YEAR ENDED DECEMBER 31, 2002
Revenues
        Unaffiliated                       $3,538,957  $3,061,732      $748,317    $714,499   ($118,385)    $7,945,120
        Intersegment                                -           -       326,639       4,623    (331,262)             -
                                           ----------------------------------------------------------------------------
                   Total revenues           3,538,957   3,061,732     1,074,956     719,122    (449,647)     7,945,120
Depreciation and amortization                 523,846     294,856        67,295      20,436      33,495        939,928
Net interest charges                          211,536     106,783        12,132      32,767     270,223        633,441
Impairment of long-lived assets and
investments
    (Notes 3B and 7)                                -           -             -      58,836     329,997        388,833
Income taxes (benefit) (e)                    237,362     163,273      (359,862)    (15,370)   (183,211)      (157,808)
Income (loss) from continuing operations      513,115     322,594       198,088     (41,733)   (439,895)       552,169
Segment income (loss) from continuing
  operations after allocation (a)             453,115     309,594       271,088     (41,733)   (439,895)       552,169
Total segment assets (d)                    8,659,297   5,226,243     2,354,081     614,640   4,008,014     20,862,275
Capital and investment expenditures           624,202     550,019       805,609       8,332     120,968      2,109,130
=======================================================================================================================

FOR THE YEAR ENDED DECEMBER 31, 2001
Revenues
     Unaffiliated                          $3,343,720  $3,212,841      $526,200    $890,328    $112,291     $8,085,380
     Intersegment                                   -           -       398,228       1,174    (399,402)             -
                                           ----------------------------------------------------------------------------
          Total revenues                    3,343,720   3,212,841       924,428     891,502   (287,111)      8,085,380
Depreciation and amortization                 521,910     452,971        40,695      36,053     109,615      1,161,244
Net interest charges                          241,427     113,707        24,085      40,589     253,085        672,893
Impairment   of   long-lived   assets  and
investments
    (Note 7)                                        -           -             -           -     207,035        207,035
Income taxes (benefit)                        264,078     182,590      (421,559)     (6,416)   (173,031)      (154,338)
Income (loss) from continuing operations      468,328     309,576       201,990     (12,108)   (427,390)       540,396
Segment income (loss) from continuing
  operations after allocation (a)             405,661     285,566       288,667     (12,108)   (427,390)       540,396
Total segment assets                        8,884,385   5,009,640     1,018,875     602,597   4,822,746     20,338,243
Capital and investment expenditures           823,952     353,433       265,183      12,886      71,986      1,527,440
=======================================================================================================================

FOR THE YEAR ENDED DECEMBER 31, 2000
Revenues
     Unaffiliated                          $3,308,215  $  241,606      $108,739         $ -    $110,362     $3,768,922
     Intersegment                                   -           -        15,717           -    (15,717)              -
                                           ----------------------------------------------------------------------------
          Total revenues                    3,308,215     241,606       124,456           -      94,645      3,768,922
Depreciation and amortization                 698,633      28,872        17,020           -      15,657        760,182
Net interest charges                          221,856       9,777         5,714           -       5,231        242,578
Gain on sale of investment                          -           -             -           -     200,000        200,000
Income taxes (benefit)                        227,705      13,580      (109,057)          -      64,274        196,502
Income (loss) from continuing operations      373,764      21,764        39,816           -      42,578        477,922
Segment income (loss) from continuing
  operations after allocation (a)             289,724      20,057       125,563           -      42,578        477,922
Total segment assets                        8,840,736   4,997,728       644,234           -   4,515,053     18,997,751
Capital and investment expenditures           821,991      49,805        38,981           -     100,317      1,011,094
=======================================================================================================================
</TABLE>

(a) Amounts  include  allocation  of energy  marketing  and  trading  net income
    managed by Progress Ventures on behalf of the electric utilities.
(b) Amounts for the year ended  December 31, 2001 reflect  cumulative  operating
    results of Rail Services since the acquisition date of November 30, 2000. As
    of December 31, 2000,  the Rail Services  segment was included as Net Assets
    Held for Sale and, therefore, no assets are reflected for this segment as of
    that date.  During 2001,  the Company  announced its intention to retain the
    Rail Services  segment and,  therefore,  these assets were  reclassified  to
    operating assets.
(c) Amounts for the year ended December 31, 2000,  reflect  operating results of
    Florida Power electric since the acquisition  date of November 30, 2000 (See
    Note 2C).
(d) In February 2002, CP&L  transferred  the Rowan Plant totaling  approximately
    $245 million to Progress Ventures.
(e) Amounts  for 2002  include  income tax  benefit  reallocation  from  holding
    company to profitable subsidiaries according to an SEC order.

                                       91
<PAGE>

    Segment totals for depreciation  and  amortization  expense include expenses
    related to the Progress Ventures,  Rail Services and Other segments that are
    included in diversified business expenses on the Consolidated  Statements of
    Income.  Segment totals for interest  expense  exclude  immaterial  expenses
    related to the Progress Ventures,  Rail Services and Other segments that are
    included in other, net on the Consolidated Statements of Income.

5.  Related Party Transactions

    NCNG sells  natural  gas to CP&L,  Florida  Power and PVI.  During the years
    ended  December  31,  2002,  2001 and 2000,  sales of  natural  gas to CP&L,
    Florida  Power and PVI  amounted to $19.5  million,  $18.7  million and $5.9
    million,   respectively.   These  revenues  are  included  in   discontinued
    operations on the  Consolidated  Statements of Income.  Progress Fuels sells
    coal to  Florida  Power.  These  intercompany  revenues  are  eliminated  in
    consolidation;  however, in accordance with SFAS No. 71, "Accounting for the
    Effects of Certain Types of Regulation,"  profits on  intercompany  sales to
    regulated affiliates are not eliminated if the sales price is reasonable and
    the future  recovery of the sales price  through the  ratemaking  process is
    probable.

    The  Company  and its  operating  subsidiaries  participate  in a money pool
    arrangement to better manage cash and working  capital  requirements.  Under
    this  arrangement,   subsidiaries  with  surplus  short-term  funds  provide
    short-term loans to participating affiliates.

    The  Company  has  announced  plans to sell  NCNG to  Piedmont  Natural  Gas
    Company,  Inc. (See Note 3A). At December 31, 2002 and 2001, the Company and
    its affiliates had amounts due from and payable to NCNG.  Under the terms of
    the  sales  agreement,  these  amounts  will be  settled  at the time of the
    transaction  and  therefore,  the amounts are no longer being  eliminated in
    consolidation.  The receivables due from and the payables due to the Company
    are  included  in assets  of  discontinued  operations  and  liabilities  of
    discontinued operations, respectively, on the Consolidated Balance Sheets.

    At December 31, 2002 and 2001,  NCNG had notes  payable  balances due to the
    Company  related  to the  money  pool of $5.8  million  and  $51.7  million,
    respectively. Interest payable balances as of December 31, 2002 and 2001 and
    amounts  recorded for interest  income and interest  expense  related to the
    money  pool for 2002,  2001 and 2000  were not  significant.  The  remaining
    amounts of  receivables  and payables with the Company and its affiliates at
    December 31, 2002 and 2001 represent amounts generated through NCNG's normal
    course of  operations.  NCNG had payables to the Company of $5.0 million and
    $31.9  million and  receivables  from the Company of $3.6  million and $51.9
    million at December 31, 2002 and 2001, respectively.

    In 2000,  prior to the  acquisition  of FPC,  the  Company  purchased  a 90%
    membership   interest  in  two  synthetic  fuel  related  limited  liability
    companies from a wholly owned  subsidiary of FPC.  Interest expense incurred
    during the pre-acquisition period was approximately $3.3 million. Subsequent
    to the  acquisition  date,  intercompany  amounts  have been  eliminated  in
    consolidation (See Note 2C).

6.  Goodwill and Other Intangible Assets

    Effective  January 1, 2002, the Company adopted SFAS No. 142,  "Goodwill and
    Other  Intangible   Assets."  This  statement  clarifies  the  criteria  for
    recording of other  intangible  assets  separately from goodwill.  Effective
    January 1, 2002,  goodwill  is no longer  subject to  amortization  over its
    estimated  useful life.  Instead,  goodwill is subject to at least an annual
    assessment for impairment by applying a two-step fair value-based test. This
    assessment could result in periodic impairment charges.

    The Company  completed the first step of the initial  transitional  goodwill
    impairment  test,  which  indicated  that  the  Company's  goodwill  was not
    impaired  as of January 1, 2002.  In  addition,  the Company  performed  the
    annual  goodwill  impairment  tests for the CP&L  Electric and Florida Power
    Electric  segments during the second quarter 2002,  which indicated that the
    Company's goodwill was not impaired.  The annual test for Progress Ventures'
    goodwill will be performed during 2003.

                                       92
<PAGE>

    In connection with the pending sale of NCNG, goodwill  attributable to these
    operations has been reclassified to assets of discontinued  operations.  The
    Company reviewed the carrying value of the NCNG disposal group in accordance
    with SFAS No. 144 (See Note 3A).

    The changes in the carrying  amount of goodwill for the year ended  December
    31, 2002, by reportable segment, are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                         Florida Power      Progress
    (In thousands)                      CP&L Electric      Electric         Ventures         Other           Total
    Balance as of January 1, 2002         $ 1,921,802      $ 1,733,448      $      -       $ 34,960    $ 3,690,210
    Acquisitions                                    -                -        64,077              -         64,077
    Divestitures                                    -                -             -         (1,720)        (1,720)
    Discontinued operations                         -                -             -        (33,240)       (33,240)
                                       ------------------------------------------------------------------------------
    Balance as of December 31, 2002       $ 1,921,802      $ 1,733,448      $ 64,077       $      -    $ 3,719,327
                                       ==============================================================================
</TABLE>

    The acquired  goodwill relates to the acquisition of generating  assets from
    LG&E Energy Corp. in February 2002 (See Note 2A).

    As required by SFAS No. 142, the results for the prior year periods have not
    been restated.  A  reconciliation  of net income as if SFAS No. 142 had been
    adopted is  presented  below for years  ending  December  31.  The  goodwill
    amortization used in the reconciliation includes $5.9 million for both years
    ending  December  31,  2001  and  2000  for  NCNG,   which  is  included  in
    discontinued operations.

    (In thousands, except per share data)     2001            2000
                                            -----------     ----------
    Reported net income                     $ 541,610       $ 478,361
    Goodwill amortization                      96,828          14,100
                                            -----------     ----------
    Adjusted net income                     $ 638,438       $ 492,461
                                            ===========     ==========

    Basic earnings per common share:
    Reported net income                     $    2.65       $    3.04
    Adjusted net income                     $    3.12       $    3.13

    Diluted earnings per common share:
    Reported net income                     $    2.64       $    3.03
    Adjusted net income                     $    3.11       $    3.12

    The gross  carrying  amount and  accumulated  amortization  of the Company's
    intangible assets as of December 31, 2002 and 2001 are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                 2002                                     2001
                                -------------------------------------    ---------------------------------
(In thousands)                     Gross Carrying     Accumulated          Gross Carrying   Accumulated
                                       Amount        Amortization              Amount      Amortization
                                 -----------------------------------    ---------------------------------
Synthetic fuel intangibles            $ 140,469       $ (45,189)             $ 140,469      $ (22,237)
Power sale agreements                    33,000          (5,593)                     -              -
Other                                    40,968          (7,792)                36,071         (5,938)
                                  -----------------------------------    ---------------------------------
Total                                 $ 214,437       $ (58,574)             $ 176,540      $ (28,175)
                                  ===================================    =================================
</TABLE>

    All of the Company's intangibles are subject to amortization. Synthetic fuel
    intangibles  represent  intangibles  for synthetic  fuel  technology.  These
    intangibles  are  being  amortized  on  a  straight-line   basis  until  the
    expiration of tax credits  under Section 29 of the Internal  Revenue Code in
    December  2007 (See Note 20).  The power  sale  agreement  intangibles  were
    recorded as part of the  acquisition  of generating  assets from LG&E Energy
    Corp.  and  are  amortized  on a  straight-line  basis  beginning  with  the
    in-service  date of these  plants  through  December 31, 2004 (See Note 2A).
    Other  intangibles  are  primarily  customer  contracts and permits that are
    amortized over their respective lives.

    Net  intangible  assets are included in other assets and deferred  debits in
    the accompanying Consolidated Balance Sheets.  Amortization expense recorded
    on intangible  assets for the years ended  December 31, 2002,  2001 and 2000
    were $32.8  million,  $21.6  million  and $6.3  million,  respectively.  The
    estimated  amortization expense for intangible assets for 2003 through 2007,
    in  millions,  is  approximately  $33.5,  $36.5,  $20.3,  $19.8  and  $19.8,
    respectively.

                                       93
<PAGE>

7.  Impairments of Long-Lived Assets and Investments

    Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting for
    the  Impairment  or Disposal of  Long-Lived  Assets."  SFAS No. 144 provides
    guidance  for the  accounting  and  reporting of  impairment  or disposal of
    long-lived  assets. The statement  supersedes SFAS No. 121,  "Accounting for
    the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
    Of." In 2002 and 2001, the Company  recorded  pre-tax  long-lived  asset and
    investment  impairments of approximately  $388.8 million and $209.0 million,
    respectively.   There  were  no  impairments  recorded  in  2000.  Estimated
    impairments of assets held for sale of $58.8 million is included in the 2002
    amount, which relates to Railcar Ltd. (See Note 3B).

    A. Long-Lived Assets

    Due  to  the  decline  of  the  telecommunications  industry  and  continued
    operating  losses,  the Company  initiated an  independent  valuation  study
    during  2002 to  assess  the  recoverability  of the  long-lived  assets  of
    Progress  Telecommunications  Corporation  (Progress  Telecom)  and Caronet.
    Based on this assessment,  the Company recorded asset  impairments of $305.0
    million on a pre-tax  basis and other  charges of $25.4 million on a pre-tax
    basis  primarily  related to inventory  adjustments  in the third quarter of
    2002. This write-down  constitutes a significant reduction in the book value
    of these long-lived assets.

    The long-lived asset  impairments  include an impairment of property,  plant
    and  equipment,  construction  work in process and  intangible  assets.  The
    impairment  charge  represents  the  difference  between  the fair value and
    carrying amount of these long-lived  assets.  The fair value of these assets
    was determined  using a valuation  study heavily  weighted on the discounted
    cash flow methodology, using market approaches as supporting information.

    Due to historical losses at Strategic Resource Solutions Corp. (SRS) and the
    decline in the market value for technology companies,  the Company evaluated
    the long-lived  assets of SRS in 2001.  Fair value was  determined  based on
    discounted  cash flows.  As a result of this  review,  the Company  recorded
    asset  impairments  of $42.9  million and other charges of $1.9 million on a
    pre-tax basis during the fourth quarter of 2001.

    B. Investments

    The Company  continually  reviews its  investments  to  determine  whether a
    decline  in  fair  value  below  the  cost  basis  is  other-than-temporary.
    Effective June 28, 2000, Caronet entered into an agreement with Bain Capital
    whereby  it  contributed  the net  assets  used in its  application  service
    provider business to a newly formed company, named Interpath Communications,
    Inc.  (Interpath),  for a 35% ownership  interest  (15% voting  interest) in
    Interpath.  In 2001,  the Company  obtained a valuation  study to assess its
    investment  in  Interpath  based on  current  valuations  in the  technology
    sector.   As  a   result,   the   Company   recorded   an   impairment   for
    other-than-temporary  declines  in  the  fair  value  of its  investment  in
    Interpath.  Investment  impairments  were also  recorded  related to certain
    investments  of SRS.  Investment  write-downs  totaled  $164.2  million on a
    pre-tax basis for the year ended  December 31, 2001. In May 2002,  Interpath
    merged with a third party. Pursuant to the terms of the merger agreement and
    due to additional  funds being  contributed  by Bain Capital,  the Company's
    ownership was diluted to 19% (7% voting interest).  As a result, the Company
    reviewed the Interpath investment for impairment and wrote off the remaining
    amount  of its  cost-basis  investment  in  Interpath,  recording  a pre-tax
    impairment  of $25.0  million in the third  quarter  of 2002.  In the fourth
    quarter of 2002, the Company sold its remaining  interest in Interpath for a
    nominal amount.

                                       94
<PAGE>

8.  Debt and Credit Facilities

    A. Debt and Credit

    At December 31, 2002 and 2001 the Company's  long-term debt consisted of the
    following (maturities and weighted-average interest rates as of December 31,
    2002):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


    (in thousands)                                                                  2002               2001
                                                                           ---------------    ----------------
    Progress Energy, Inc.:
    Senior unsecured notes, maturing 2004-2031                     6.93%      $ 4,800,000          $4,000,000
    Unamortized fair value hedge gain                                              33,676                   -
    Unamortized premium and discount, net                                         (31,256)            (29,708)
                                                                           ---------------    ----------------
                                                                                4,802,420           3,970,292
                                                                           ---------------    ----------------
    Carolina Power & Light Company:
    First mortgage bonds, maturing 2004-2023                       6.92%        1,550,000           1,800,000
    Pollution control obligations, maturing 2010-2024              1.86%          707,800             707,800
    Unsecured notes, maturing 2012                                 6.50%          500,000                   -
    Extendible notes, maturing 2002                                  -                  -             500,000
    Medium-term notes, maturing 2008                               6.65%          300,000             300,000
    Miscellaneous notes                                            6.44%            6,910               7,234
    Unamortized premium and discount, net                                         (16,244)            (16,716)
                                                                           ---------------    ----------------
                                                                                3,048,466           3,298,318
                                                                           ---------------    ----------------
    Florida Power Corporation:
    First mortgage bonds, maturing 2003-2023                       6.83%          810,000             810,000
    Pollution control obligations, maturing 2018-2027              1.11%          240,865             240,865
    Medium-term notes, maturing 2003-2028                          6.74%          416,900             449,100
    Unamortized premium and discount, net                                          (6,433)             (2,935)
                                                                           ---------------    ----------------
                                                                                1,461,332           1,497,030
                                                                           ---------------    ----------------
    Progress Ventures Holdings, Inc.:
    Variable rate project financing, maturing 2007                 3.02%          225,000                   -

    Florida Progress Funding Corporation (Note 9):
    Mandatorily redeemable preferred securities, maturing 2039     7.10%          300,000             300,000
    Purchase accounting fair value adjustment                                     (30,276)            (30,413)
    Unamortized premium and discount, net                                          (8,680)             (8,922)
                                                                           ---------------    ----------------
                                                                                  261,044             260,665
                                                                           ---------------    ----------------
    Progress Capital Holdings, Inc.:
    Medium-term notes, maturing 2003-2008                          6.96%          223,000             273,000
    Miscellaneous notes                                            1.53%            1,428               7,707
                                                                           ---------------    ----------------
                                                                                  224,428             280,707
                                                                           ---------------    ----------------
    Current portion of long-term debt                                            (275,397)           (688,052)
                                                                           ---------------    ----------------
        Total long-term debt                                                  $ 9,747,293         $ 8,618,960
                                                                           ===============    ================
</TABLE>

    As of December 31, 2002 and 2001,  the Company had $694.9 million and $942.3
    million,  respectively, of outstanding commercial paper and other short-term
    debt classified as short-term  obligations.  The  weighted-average  interest
    rates of such  short-term  obligations  at  December  31, 2002 and 2001 were
    1.67% and 2.95%, respectively. The Company no longer reclassifies commercial
    paper to long-term debt.  Certain amounts for 2001 have been reclassified to
    conform to 2002  presentation,  with no effect on  previously  reported  net
    income or common stock equity.

    At December 31, 2002,  the Company had  committed  lines of credit  totaling
    $1.74  billion,  all of  which  are used to  support  its  commercial  paper
    borrowings. The Company is required to pay minimal annual commitment fees to
    maintain its credit facilities. The following table summarizes the Company's
    credit facilities (in millions):

                                       95
<PAGE>

      Company             Description                       Total
    ----------------------------------------------------------------

    Progress Energy      364-Day (expiring 11/11/03)      $   430.2
    Progress Energy      3-Year (expiring 11/13/04)           450.0
    CP&L                 364-Day (expiring 7/30/03)           285.0
    CP&L                 3-Year (expiring 7/31/05)            285.0
    Florida Power        364-Day (expiring 4/1/03)             90.5
    Florida Power        5-Year (expiring 11/30/03)           200.0
                                                          ----------
        Total credit facilities                           $ 1,740.7
                                                          ==========

    As of  December  31,  2002,  there  were no loans  outstanding  under  these
    facilities.

    Progress Energy and Florida Power each have an uncommitted bank bid facility
    authorizing them to borrow and re-borrow,  and have loans outstanding at any
    time,  up to $300  million and $100  million,  respectively.  These bank bid
    facilities were not drawn as of December 31, 2002.

    The combined  aggregate  maturities of long-term  debt for 2003 through 2007
    are approximately $275 million,  $869 million,  $355 million,  $909 million,
    and $899 million, respectively.

    B. Covenants and Default Provisions

    Financial Covenants
    Progress  Energy's,  CP&L's and Florida  Power's  credit  lines and the bank
    facility of Progress Genco Ventures, LLC (Genco), a PVI subsidiary,  contain
    various  terms and  conditions  that could affect the  Company's  ability to
    borrow under these  facilities.  These include maximum debt to total capital
    ratios,  interest  coverage  tests,  material  adverse  change  clauses  and
    cross-default provisions.

    All of the credit facilities agreements include a defined maximum total debt
    to total capital ratio.  As of December 31, 2002,  the calculated  ratio for
    these  four  companies,  pursuant  to the  terms of the  agreements,  are as
    follows:

    Company                               Maximum Ratio     Actual Ratio (b)
    ----------------------------------- ------------------- ------------------
    Progress Energy, Inc.                      70% (a)            62.4%
    Carolina Power & Light Company             65%                52.7%
    Florida Power Corporation                  65%                48.6%
    Progress Genco Ventures, LLC               40%                24.8%

    (a) Progress  Energy's  maximum debt ratio reduces to 68% effective June 30,
    2003.
    (b) Indebtedness as defined by the bank agreements  includes certain letters
    of credit and guarantees which are not recorded on the Consolidated  Balance
    Sheets.

    Progress  Energy's  364-day  credit  facility  has a financial  covenant for
    interest  coverage.  This  covenant  requires  Progress  Energy's  EBITDA to
    interest  expense to be at least 2.5 to 1. For the year ended  December  31,
    2002,  this ratio was 3.43 to 1.  Genco's bank  facility  requires a minimum
    1.25 to 1 debt service coverage ratio. For the year ended December 31, 2002,
    Genco's debt service coverage was 7.65 to 1.

    Material Adverse Change Clause
    The credit  facilities  of Progress  Energy,  CP&L,  Florida Power and Genco
    include a provision under which lenders could refuse to advance funds in the
    event of a material adverse change in the borrower's financial condition.

    Cross-Default Provisions
    Progress   Energy's,   CP&L's  and  Florida  Power's  credit  lines  include
    cross-default  provisions  for  defaults  of  indebtedness  in excess of $10
    million.  Progress Energy's cross-default  provisions only apply to defaults
    of indebtedness by Progress  Energy and its significant  subsidiaries (i.e.,
    CP&L, FPC, Florida Power, PVI, Progress Fuels and Progress Capital Holdings,
    Inc.).  CP&L's and Florida  Power's  cross-default  provisions only apply to
    defaults of indebtedness  by CP&L and Florida Power and their  subsidiaries,
    respectively,  not other  affiliates  of CP&L  or Florida  Power.  The Genco
    credit facility includes a similar provision for defaults by Progress Energy
    or PVI.

                                       96
<PAGE>

    Additionally, certain of Progress Energy's long-term debt indentures contain
    cross-default  provisions  for  defaults  of  indebtedness  in excess of $25
    million;  these  provisions  only  apply to other  obligations  of  Progress
    Energy,   not  its   subsidiaries.   In  the  event  that  these   indenture
    cross-default  provisions are triggered,  the debt holders could  accelerate
    payment of approximately  $4.8 billion in long-term debt. Certain agreements
    underlying  the  Company's  indebtedness  also  limit its  ability  to incur
    additional   liens  or  engage  in  certain  types  of  sale  and  leaseback
    transactions.

    Other Restrictions
    Neither  Progress  Energy's  Articles of  Incorporation  nor any of its debt
    obligations  contain any  restrictions on the payment of dividends.  Certain
    documents   restrict  the  payment  of   dividends   by  Progress   Energy's
    subsidiaries as outlined below.

    CP&L's mortgage  indenture provides that so long as any first mortgage bonds
    are outstanding,  cash dividends and  distributions on its common stock, and
    purchases  of its common  stock,  are  restricted  to  aggregate  net income
    available  for CP&L,  since  December  31, 1948,  plus $3 million,  less the
    amount of all preferred  stock dividends and  distributions,  and all common
    stock  purchases,  since  December 31, 1948.  At December 31, 2002,  none of
    CP&L's retained earnings of $1.3 billion was restricted.

    In addition, CP&L's Articles of Incorporation provide that cash dividends on
    common stock shall be limited to 75% of net income  available  for dividends
    if common stock equity falls below 25% of total  capitalization,  and to 50%
    if common stock equity falls below 20%. On December 31, 2002,  CP&L's common
    stock equity was approximately 46.6% of total capitalization.

    Florida Power's  mortgage  indenture  provides that it will not pay any cash
    dividends  upon its  common  stock,  or make any other  distribution  to the
    stockholders,  except a payment or distribution out of net income of Florida
    Power subsequent to December 31, 1943. At December 31, 2002, none of Florida
    Power's retained earnings of $598 million was restricted.

    In addition,  Florida Power's Articles of Incorporation provide that no cash
    dividends or  distributions  on common stock shall be paid, if the aggregate
    amount  thereof since April 30, 1944,  including the amount then proposed to
    be expended,  plus all other  charges to retained  earnings  since April 30,
    1944, exceed (a) all credits to retained earnings since April 30, 1944, plus
    (b) all amounts  credited to capital  surplus after April 30, 1944,  arising
    from the  donation  to  Florida  Power of cash or  securities  or  transfers
    amounts from retained earnings to capital surplus.

    Florida Power's Articles of  Incorporation  also provide that cash dividends
    on  common  stock  shall  be  limited  to 75% of net  income  available  for
    dividends if common  stock  equity falls below 25% of total  capitalization,
    and to 50% if common  stock  equity  falls below 20%. On December  31, 2002,
    Florida  Power's  common  stock  equity  was  approximately  50.7%  of total
    capitalization.

    Genco is  required  to hedge 75% of the  amount  outstanding  under its bank
    facility through September 2005 and 50% thereafter,  pursuant to the term of
    the agreement for expansion of its  nonregulated  generation  portfolio.  At
    December 31, 2002, Genco held interest rate cash flow hedges with a notional
    amount of $195  million  and a total fair value of $12.3  million  liability
    position  related to this covenant.  See  additional  discussion of interest
    rate cash flow hedges in Note 16.

    C. Secured Obligations

    CP&L's  and  Florida  Power's  first  mortgage  bonds are  secured  by their
    respective mortgage  indentures.  Each mortgage  constitutes a first lien on
    substantially all of the fixed properties of the respective company, subject
    to  certain  permitted  encumbrances  and  exceptions.  Each  mortgage  also
    constitutes a lien on subsequently  acquired property. At December 31, 2002,
    CP&L and Florida  Power had a total of  approximately  $3.3 billion of first
    mortgage bonds  outstanding,  including  those related to pollution  control
    obligations.  Each mortgage allows the issuance of additional mortgage bonds
    upon the satisfaction of certain conditions.

                                       97
<PAGE>

    Genco obtained a bank facility to be used  exclusively  for expansion of its
    nonregulated  generation  portfolio.  Borrowings  under  this  facility  are
    secured by the assets in the generation portfolio. The facility is for up to
    $310 million,  of which $225 million had been drawn as of December 31, 2002.
    Borrowings   under  the  facility  are   restricted   for  the   operations,
    construction,  repayments and other related  charges of the credit  facility
    for the  development  projects.  Cash held and  restricted to operations was
    $21.1 million at December 31, 2002, and is included in other current assets.
    Cash  held and  restricted  for  long-term  purposes  was $37.1  million  at
    December 31, 2002 and is included in other assets and deferred debits on the
    Consolidated Balance Sheets.

    D. Guarantees of Subsidiary Debt

    FPC has guaranteed the  outstanding  debt  obligations for two of its wholly
    owned  subsidiaries,  FPC  Capital  I and  Progress  Capital  Holdings, Inc.

    At December  31, 2002 and 2001,  Progress  Capital  Holdings,  Inc. had $223
    million and $273 million,  respectively,  in medium-term  notes  outstanding
    which were  fully  guaranteed  by FPC (See Note 8).  FPC  Capital I had $300
    million in  mandatorily  redeemable  securities  outstanding at December 31,
    2002 and 2001 for  which  FPC has also  guaranteed  payment.  See Note 9 for
    additional discussion of these notes. This debt is recorded on the Company's
    accompanying Consolidated Balance Sheets.

    E. Hedging Activities

    Progress  Energy  uses  interest  rate  derivatives  to adjust the fixed and
    variable rate  components of its debt  portfolio and to hedge cash flow risk
    of fixed  rate debt to be  issued  in the  future.  See  discussion  of risk
    management activities and derivative transactions at Note 16.

9.  FPC-Obligated  Mandatorily  Redeemable  Preferred Securities of a Subsidiary
    Holding Solely FPC Guaranteed Notes

    In  April  1999,  FPC  Capital  I (the  Trust),  an  indirect  wholly  owned
    subsidiary  of  FPC,   issued  12  million  shares  of  $25  par  cumulative
    FPC-obligated   mandatorily   redeemable  preferred  securities   (Preferred
    Securities)  due 2039, with an aggregate  liquidation  value of $300 million
    and an annual distribution rate of 7.10%.  Currently,  all 12 million shares
    of the Preferred  Securities  that were issued are  outstanding.  Concurrent
    with the issuance of the Preferred  Securities,  the Trust issued to Florida
    Progress Funding Corporation (Funding Corp.) all of the common securities of
    the Trust  (371,135  shares) for $9.3  million.  Funding  Corp.  is a direct
    wholly owned subsidiary of FPC.

    The  existence of the Trust is for the sole purpose of issuing the Preferred
    Securities  and the  common  securities  and using the  proceeds  thereof to
    purchase  from  Funding  Corp.  its  7.10%  Junior  Subordinated  Deferrable
    Interest  Notes  (subordinated  notes) due 2039,  for a principal  amount of
    $309.3 million. The subordinated notes and the Notes Guarantee (as discussed
    below) are the sole assets of the Trust.  Funding Corp.'s  proceeds from the
    sale of the  subordinated  notes were advanced to Progress  Capital and used
    for general  corporate  purposes  including  the  repayment  of a portion of
    certain outstanding short-term bank loans and commercial paper.

    FPC has fully and  unconditionally  guaranteed  the  obligations  of Funding
    Corp. under the subordinated notes (the Notes Guarantee).  In addition,  FPC
    has guaranteed the payment of all  distributions  required to be made by the
    Trust,  but only to the extent that the Trust has funds  available  for such
    distributions  (Preferred  Securities  Guarantee).  The Preferred Securities
    Guarantee, considered together with the Notes Guarantee,  constitutes a full
    and  unconditional  guarantee  by FPC of the Trust's  obligations  under the
    Preferred Securities.

    The  subordinated  notes may be  redeemed  at the  option of  Funding  Corp.
    beginning in 2004 at par value plus accrued  interest through the redemption
    date. The proceeds of any redemption of the subordinated  notes will be used
    by the Trust to redeem proportional  amounts of the Preferred Securities and
    common  securities  in  accordance  with their terms.  Upon  liquidation  or
    dissolution of Funding Corp.,  holders of the Preferred  Securities would be
    entitled to the liquidation preference of $25 per share plus all accrued and
    unpaid dividends thereon to the date of payment.

    These Preferred Securities are classified as long-term debt on the Company's
    Consolidated Balance Sheets.

                                       98
<PAGE>

10. Contingent Value Obligations

    In connection  with the  acquisition  of FPC during 2000, the Company issued
    98.6  million  CVOs.  Each CVO  represents  the right to receive  contingent
    payments  based  on  the  performance  of  four  synthetic  fuel  facilities
    purchased by  subsidiaries  of FPC in October 1999.  The  payments,  if any,
    would be based on the net after-tax cash flows the facilities generate.  The
    CVO  liability  is  adjusted  to  reflect  market  price  fluctuations.  The
    liability,  included in other liabilities and deferred credits,  at December
    31, 2002 and 2001, was $13.8 million and $41.9 million, respectively.

11. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption

    All of the Company's  preferred stock was issued by its subsidiaries and was
    not subject to mandatory redemption. Preferred stock outstanding at December
    31, 2002 and 2001  consisted of the  following (in  thousands,  except share
    data):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

    Carolina Power & Light Company:
    Authorized - 300,000 shares, cumulative, $100 par value Preferred
    Stock; 20,000,000 shares, cumulative, $100 par value Serial
    Preferred Stock
       $5.00 Preferred -  236,997  shares outstanding (redemption price $110.00)            $24,349
       $4.20 Serial Preferred - 100,000 shares outstanding  (redemption price $102.00)       10,000
       $5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00)        24,985
                                                                                         ----------
                                                                                            $59,334
                                                                                         ----------
    Florida Power Corporation:
    Authorized - 4,000,000 shares, cumulative, $100 par value Preferred
    Stock; 5,000,000 shares, cumulative, no par value Preferred Stock;
    1,000,000 shares, $100 par value Preference Stock
       $100 par value Preferred Stock:
          4.00% - 39,980 shares outstanding (redemption price $104.25)                      $ 3,998
          4.40% - 75,000 shares outstanding (redemption price $102.00)                        7,500
          4.58% - 99,990 shares outstanding (redemption price $101.00)                        9,999
          4.60% - 39,997 shares outstanding (redemption price $103.25)                        4,000
          4.75% - 80,000 shares outstanding (redemption price $102.00)                        8,000
                                                                                         ----------
                                                                                            $33,497
                                                                                         ----------
          Total Preferred Stock of Subsidiaries                                             $92,831
                                                                                         ==========
</TABLE>

12. Leases

    The Company leases office buildings, computer equipment,  vehicles, railcars
    and other property and equipment  with various terms and  expiration  dates.
    Some rental payments for  transportation  equipment  include minimum rentals
    plus contingent  rentals based on mileage.  These contingent rentals are not
    significant.  Rent expense (under  operating  leases) totaled $57.1 million,
    $62.6 million and $26.8 million for 2002, 2001 and 2000, respectively.

    Assets  recorded  under  capital  leases  at  December  31  consist  of  (in
    thousands):

                                         2002         2001
                                      ---------    ---------
    Buildings                         $ 27,626     $ 27,626
    Equipment and other                  2,919       12,170
    Less:  Accumulated amortization     (9,422)      (8,975)
                                      ---------    ---------
                                      $ 21,123     $ 30,821
                                      =========    =========

    Equipment and other  capital  lease assets were written down in  conjunction
    with the  impairments  of  Progress  Telecom  and  Caronet  during the third
    quarter of 2002 (See Note 7A).

                                       99
<PAGE>

    Minimum annual rental payments,  excluding  executory costs such as property
    taxes, insurance and maintenance, under long-term noncancelable leases as of
    December 31, 2002 are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                 Capital Leases     Operating Leases
                                                 ---------------    ----------------
    2003                                              $ 3,300            $75,722
    2004                                                3,300             58,750
    2005                                                3,300             35,356
    2006                                                3,300             24,695
    2007                                                3,300             20,185
    Thereafter                                         29,014             78,400
                                                 ---------------    ----------------
                                                      $45,514           $293,108
                                                                    ================
    Less amount representing imputed interest         (17,042)
                                                 ---------------
    Present value of net minimum lease payments
              under capital leases                   $ 28,472
                                                 ===============
</TABLE>

    The Company  expects to sell  Railcar  Ltd.  during 2003 (See Note 3B).  The
    operating lease obligations above include $34.2 million, $24.0 million, $6.7
    million,  $1.5  million and $1.4  million for the years 2003  through  2007,
    respectively,  which are  attributable  to Railcar Ltd. Upon the sale of the
    related assets, the Company expects to be relieved of these obligations.

    The Company is also a lessor of land, buildings, railcars and other types of
    properties it owns under operating  leases with various terms and expiration
    dates.  The leased  buildings  and railcars are  depreciated  under the same
    terms as other  buildings  and  railcars  included in  diversified  business
    property.  Minimum rentals  receivable under  noncancelable  leases for 2003
    through 2007 are approximately  $11.3 million,  $7.7 million,  $6.0 million,
    $4.8 million and $2.7 million,  respectively,  with $7.3 million  receivable
    thereafter.  These rentals  receivable  totals include $10.3  million,  $7.0
    million,  $5.6 million,  $4.5 million and $2.6  million,  for the years 2003
    through  2007,  respectively,   and  $4.4  million  thereafter,   which  are
    attributable  to  Railcar  Ltd.  Upon the sale of the  related  assets,  the
    Company expects to no longer receive this income.

    CP&L and Florida Power are lessors of electric poles and streetlights. Rents
    received are contingent upon usage and totaled $80.8 million,  $78.4 million
    and $27.5 million for 2002, 2001 and 2000, respectively.

13. Fair Value of Financial Instruments

    The carrying amounts of cash and cash equivalents and short-term obligations
    approximate fair value due to the short maturities of these instruments.  At
    December 31, 2002 and 2001,  investments in company-owned life insurance and
    other benefit plan assets,  with carrying  amounts of  approximately  $149.9
    million and $124.3  million,  respectively,  are  included in  miscellaneous
    other property and investments  and approximate  fair value due to the short
    maturity of the instruments.  Other  instruments are presented at fair value
    in accordance  with GAAP.  The carrying  amount of the  Company's  long-term
    debt,  including current  maturities,  was $10.1 billion and $9.4 billion at
    December 31, 2002 and 2001,  respectively.  The estimated fair value of this
    debt, as obtained from quoted market prices for the same or similar  issues,
    was  $11.0  billion  and  $9.7  billion  at  December  31,  2002  and  2001,
    respectively.

    External funds have been established as a mechanism to fund certain costs of
    nuclear  decommissioning (See Note 1H). These nuclear  decommissioning trust
    funds  are  invested  in  stocks,   bonds  and  cash  equivalents.   Nuclear
    decommissioning trust funds are presented on the Consolidated Balance Sheets
    at amounts that approximate  fair value.  Fair value is obtained from quoted
    market prices for the same or similar investments.

14. Common Stock

    In November  2002,  the Company  issued 14.67 million shares of common stock
    for net cash proceeds of approximately $600.0 million,  which were primarily
    used to retire  commercial  paper.  In April 2002,  the  Company  issued 2.5
    million  shares of common  stock,  valued at  approximately  $129.0  million
    dollars,  in conjunction  with the purchase of Westchester  Gas Company (See
    Note 2B). In August 2001,  the Company issued 12.65 million shares of common
    stock for net cash proceeds of $488.0 million,  which were primarily used to
    retire  commercial  paper. In November 2000, the Company issued 46.5 million
    shares of common stock, valued at approximately $1.9 billion, in conjunction
    with the FPC acquisition (See Note 2C).

                                       100
<PAGE>

    As of December 31, 2002, the Company had  52,537,780  shares of common stock
    authorized by the Board of Directors  that  remained  unissued and reserved,
    primarily to satisfy the  requirements of the Company's stock plans. In July
    2002,  the Board of Directors  authorized  meeting the  requirements  of the
    Progress  Energy 401(k)  Savings and Stock  Ownership  Plan and the Investor
    Plus  Stock  Purchase  Plan  with  original  issue  shares.  Prior  to  that
    authorization,  the Company met the  requirements  of these stock plans with
    issued and  outstanding  shares held by the Trustee of the  Progress  Energy
    401(k) Savings and Stock  Ownership Plan  (previously  known as the Progress
    Energy, Inc. Stock  Purchase-Savings  Plan) or with open market purchases of
    common  stock  shares,  as  appropriate.  During  2002,  the Company  issued
    approximately  2.1 million  shares  under  these  plans for net  proceeds of
    approximately $87.0 million.  The Company continues to meet the requirements
    of the restricted stock plan with issued and outstanding shares.

    There are various  provisions  limiting the use of retained earnings for the
    payment of dividends under certain  circumstances.  As of December 31, 2002,
    there were no significant restrictions on the use of retained earnings.

15. Regulatory Matters

    A. Regulatory Assets and Liabilities

    As regulated  entities,  the utilities are subject to the provisions of SFAS
    No.  71,  "Accounting  for the  Effects  of  Certain  Types of  Regulation."
    Accordingly,  the utilities record certain assets and liabilities  resulting
    from the  effects of the  ratemaking  process,  which  would not be recorded
    under GAAP for nonregulated  entities. The utilities' ability to continue to
    meet the  criteria  for  application  of SFAS No. 71 may be  affected in the
    future by  competitive  forces and  restructuring  in the  electric  utility
    industry.  In the event that SFAS No. 71 no longer  applied  to a  separable
    portion  of  the  Company's   operations,   related  regulatory  assets  and
    liabilities  would be eliminated unless an appropriate  regulatory  recovery
    mechanism  was  provided.  Additionally,  these  factors  could result in an
    impairment of utility  plant assets as determined  pursuant to SFAS No. 144,
    "Accounting  for the Impairment or Disposal of Long-Lived  Assets" (See Note
    1J).

    At December  31, 2002 and 2001,  the balances of the  utilities'  regulatory
    assets (liabilities) were as follows (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                  2002           2001
                                                               -----------    -----------

    Deferred fuel costs (included in current assets)           $ 183,518      $ 146,652
                                                               -----------    -----------

    Income taxes recoverable through future rates                230,025        236,312
    Deferred purchased power contract termination costs           46,601         95,326
    Harris Plant deferred costs                                   16,888         32,476
    Loss on reacquired debt                                       32,979         25,649
    Deferred DOE enrichment facilities-related costs (Note 1G)    31,525         39,102
    Other postretirement benefits (Note 18C)                      11,018         12,207
    Other                                                         24,179         22,765
                                                               -----------    -----------
         Total regulatory assets                                 393,215        463,837
                                                               -----------    -----------

    Nuclear maintenance and refueling                             (9,601)          (346)
    Defined benefit retirement plan (Note 18C)                   (50,988)      (234,102)
    Emission allowance gains                                      (7,774)        (7,494)
    Storm reserve (Note 24D)                                     (35,631)       (35,527)
    Other                                                        (15,772)       (14,320)
                                                               -----------    -----------
        Total regulatory liabilities                            (119,766)      (291,789)
                                                               -----------    -----------

             Net regulatory assets                             $ 456,967      $  318,700
                                                              ===========     ===========
</TABLE>
                                       101
<PAGE>

    NCNG is allowed to recover  the costs of gas  purchased  for resale  through
    customer rates. NCNG was in an overrecovery position as of December 31, 2002
    and 2001.  The NCNG  liability of $12.7  million as of December 31, 2002 and
    $4.5  million  as of  December  31,  2001  is  included  in  liabilities  of
    discontinued operations.

    Except for portions of deferred fuel, all regulatory assets earn a return or
    the cash has not yet been  expended,  in which case the assets are offset by
    liabilities that do not incur a carrying cost.

    B. Florida Power Rate Case Settlement

    Florida Power's retail rates are set by the FPSC,  while its wholesale rates
    are governed by FERC.  Florida  Power's  last  general  retail rate case was
    approved  in 1992 and  allowed a 12%  regulatory  return  on equity  with an
    allowed range between 11% and 13%. Florida Power  previously  operated under
    an agreement  committing  several  parties not to seek any  reduction in its
    base rates or authorized  return on equity.  That agreement  expired on June
    30, 2001.  The FPSC initiated a rate  proceeding in 2001  regarding  Florida
    Power's future base rates. On March 27, 2002, the parties in Florida Power's
    rate  case  entered  into  a  Stipulation  and  Settlement   Agreement  (the
    Agreement) related to retail rate matters. The Agreement was approved by the
    FPSC on April 23, 2002.  The  Agreement is generally  effective  from May 1,
    2002 through December 31, 2005; provided,  however,  that if Florida Power's
    base rate  earnings  fall below a 10% return on  equity,  Florida  Power may
    petition the FPSC to amend its base rates.

    The Agreement  provides  that Florida Power will reduce its retail  revenues
    from the sale of  electricity  by an  annual  amount  of $125  million.  The
    Agreement  also  provides  that Florida  Power will operate  under a Revenue
    Sharing  Incentive  Plan (the  Plan)  through  2005,  and  thereafter  until
    terminated by the FPSC,  that  establishes  annual  revenue caps and sharing
    thresholds.  The Plan provides  that retail base rate  revenues  between the
    sharing  thresholds  and the retail base rate  revenue  caps will be divided
    into  two  shares  -  a  1/3  share  to  be  received  by  Florida   Power's
    shareholders,  and a 2/3 share to be  refunded  to  Florida  Power's  retail
    customers;  provided,  however,  that for the year 2002 only,  the refund to
    customers  will be limited to 67.1% of the 2/3  customer  share.  The retail
    base rate revenue sharing threshold amounts for 2002 were $1.296 billion and
    will increase $37 million each year thereafter.  The Plan also provides that
    all retail  base rate  revenues  above the  retail  base rate  revenue  caps
    established for each year will be refunded to retail  customers on an annual
    basis.  For 2002, the refund to customers was limited to 67.1% of the retail
    base rate revenues that exceed the 2002 cap. The retail base revenue cap for
    2002 was $1.356 billion and will increase $37 million each year  thereafter.
    Any amounts  above the retail  base  revenue  caps will be refunded  100% to
    customers.  As of December  31,  2002,  $4.7 million was accrued and will be
    refunded to customers by March 2003.

    The Agreement  also  provides that  beginning  with the  in-service  date of
    Florida  Power's  Hines Unit 2 and  continuing  through  December  31, 2005,
    Florida  Power will be allowed to  recover  through  the fuel cost  recovery
    clause a return on average  investment  and  depreciation  expense for Hines
    Unit 2, to the extent  such costs do not exceed the unit's  cumulative  fuel
    savings over the recovery  period.  Hines Unit 2 is a 516 MW  combined-cycle
    unit under construction and currently scheduled for completion in late 2003.

    Additionally,  the  Agreement  provided  that  Florida  Power would effect a
    mid-course  correction of its fuel cost  recovery  clause to reduce the fuel
    factor by $50 million for 2002.  The fuel cost recovery  clause will operate
    as  it  normally  does,  including,  but  not  limited  to,  any  additional
    mid-course  adjustments  that may become  necessary,  and the calculation of
    true-ups to actual fuel clause expenses.

    Florida   Power  will   suspend   accruals  on  its   reserves  for  nuclear
    decommissioning  and  fossil   dismantlement   through  December  31,  2005.
    Additionally,  for each  calendar  year  during  the term of the  Agreement,
    Florida Power will reduce depreciation expense by $62.5 million, and may, at
    its option, record up to an equal annual amount as an offsetting accelerated
    depreciation  expense.  In addition,  Florida  Power is  authorized,  at its
    discretion, to accelerate the amortization of certain regulatory assets over
    the  term  of  the   Agreement.   Florida  Power   recorded  no  accelerated
    depreciation or amortization expense for the year ended December 31, 2002.

                                       102
<PAGE>

    Under the terms of the  Agreement,  Florida  Power  agreed to  continue  the
    implementation  of its four-year  Commitment to Excellence  Reliability Plan
    and  expects  to achieve a 20%  improvement  in its  annual  System  Average
    Interruption Duration Index by no later than 2004. If this improvement level
    is not achieved for calendar years 2004 or 2005,  Florida Power will provide
    a refund of $3 million for each year the level is not achieved to 10% of its
    total retail customers served by its worst  performing  distribution  feeder
    lines.

    Per the  Agreement,  Florida  Power was required to refund to customers  $35
    million of revenues  Florida Power collected during the interim period since
    March 13, 2001. This one-time retroactive revenue refund was recorded in the
    first  quarter  of  2002  and  was  returned  to  retail  customers  over an
    eight-month period ended December 31, 2002. Any additional refunds under the
    Agreement are recorded when they become probable.

    C. Retail Rate Matters

    The NCUC and SCPSC approved  proposals to accelerate cost recovery of CP&L's
    nuclear  generating assets beginning January 1, 2000, and continuing through
    2004. On June 14, 2002,  the NCUC approved  modification  of CP&L's  ongoing
    accelerated  cost  recovery  of its  nuclear  generating  assets.  Effective
    January 1, 2003, the NCUC will no longer require annual minimum  accelerated
    depreciation.  The  aggregate  minimum  and maximum  amounts of  accelerated
    depreciation,  $415 million and $585  million,  respectively,  are unchanged
    from the original NCUC order.  The date by which the minimum  amount must be
    depreciated  was extended  from  December 31, 2004 to December 31, 2009.  On
    October 29, 2002, the SCPSC approved  similar  modifications.  The order was
    effective  November 1, 2002,  and the aggregate  minimum and maximum of $115
    million and $165 million  established for  accelerated  cost recovery by the
    SCPSC is unchanged.  The accelerated  cost recovery of these assets resulted
    in additional depreciation expense of approximately $53 million, $75 million
    and $275 million in 2002, 2001 and 2000, respectively.  Recovering the costs
    of its  nuclear  generating  assets  on an  accelerated  basis  will  better
    position CP&L for the uncertainties  associated with potential restructuring
    of the electric utility industry.  Total accelerated  depreciation  recorded
    through   December  31,  2002  was  $326  million  for  the  North  Carolina
    jurisdiction and $77 million for the South Carolina jurisdiction.

    On May 30, 2001,  the NCUC issued an order allowing CP&L to offset a portion
    of its annual  accelerated cost recovery of nuclear generating assets by the
    amount of sulfur  dioxide  (SO2)  emission  allowance  expense.  CP&L offset
    accelerated  depreciation  expense  against  emission  allowance  expense by
    approximately  $5.8  million  in  2002.  CP&L  did  not  offset  accelerated
    depreciation  expense against  emission  allowance  expense in 2001. CP&L is
    allowed  to recover  emission  allowance  expense  through  the fuel  clause
    adjustment in its South Carolina retail jurisdiction.  Florida Power is also
    allowed  to  recover  its  emission  allowance  expenses  through  the  fuel
    adjustment  clause in its retail  jurisdiction.  See Note 24E  regarding the
    North Carolina rate freeze and accelerated  recovery of environmental  costs
    beginning January 1, 2003.

    In compliance with a regulatory  order,  Florida Power accrues a reserve for
    maintenance  and  refueling  expenses  anticipated  to  be  incurred  during
    scheduled nuclear plant outages.

    In conjunction  with the acquisition of NCNG, CP&L agreed to cap base retail
    electric rates in North Carolina and South Carolina  through  December 2004.
    The cap on base retail  electric  rates in South  Carolina  was  extended to
    December  2005 in  conjunction  with  regulatory  approval to form a holding
    company.  NCNG also agreed to cap its North  Carolina  margin  rates for gas
    sales and transportation services, with limited exceptions, through November
    1, 2003.  In  February  2002,  NCNG filed a general  rate case with the NCUC
    requesting  an  annual  rate  increase  of  $47.6  million,  based  upon its
    completion of major  expansion  projects.  On May 3, 2002, NCNG withdrew the
    application,   based  upon  the  NCUC  Public  Staff's  and  other  parties'
    interpretation  of the order approving the merger of CP&L and NCNG that such
    a case was not permitted  until 2003. On May 16, 2002,  NCNG filed a request
    to  increase  its  margin  rates  and  rebalance  its  rates  with the NCUC,
    requesting  an  annual  rate  increase  of $4.1  million  to  recover  costs
    associated  with specific  system  improvements.  On September 23, 2002, the
    NCUC issued its order  approving  the $4.1 million rate  increase.  The rate
    increase was effective October 1, 2002.

    In  conjunction  with the FPC merger,  CP&L  reached a  settlement  with the
    Public  Staff of the  NCUC in which it  agreed  to  provide  credits  to its
    non-real time pricing customers in the amounts of $3.0 million in 2002, $4.5
    million in 2003,  $6.0 million in 2004 and $6.0  million in 2005.  CP&L also
    agreed to write-off and forego  recovery of $10 million of unrecovered  fuel
    costs in each of its 2000 NCUC and SCPSC fuel cost recovery proceedings.

                                       103
<PAGE>

    At December  31, 2000,  Florida  Power,  with the approval of the FPSC,  had
    established  a regulatory  liability  to defer $63 million of  revenues.  In
    2001, Florida Power applied the deferred revenues, plus accrued interest, to
    reduce its regulatory asset related to deferred  purchased power termination
    costs. In addition, Florida Power recorded accelerated amortization of $34.0
    million to further offset this regulatory asset during 2001.

    In February  2003,  Florida Power  petitioned  the FPSC to increase its fuel
    factors due to continuing increases in oil and natural gas commodity prices.
    The crisis in the Middle East along with the Venezuelan oil workers'  strike
    have put upward  pressure on commodity  prices that was  not  anticipated by
    Florida  Power  when  fuel  factors  for 2003 were  approved  by the FPSC in
    November 2002. If Florida Power's  petition is approved,  the increase would
    go into effect April 1, 2003.

    D. Regional Transmission Organizations

    In early  2000  FERC  issued  Order  2000  regarding  regional  transmission
    organizations  (RTOs). This Order set minimum  characteristics and functions
    that RTOs must meet, including independent transmission service. As a result
    of Order 2000,  Florida Power,  along with Florida Power & Light Company and
    Tampa Electric Company, filed with FERC, in October 2000, an application for
    approval  of a  GridFlorida  RTO.  On March 28,  2001,  FERC issued an order
    provisionally   approving   GridFlorida.   CP&L,   along  with  Duke  Energy
    Corporation and South Carolina Electric & Gas Company,  filed with FERC, for
    approval  of a  GridSouth  RTO.  On July  12,  2001,  FERC  issued  an order
    provisionally approving GridSouth. However, in July 2001, FERC issued orders
    recommending  that  companies  in the  Southeast  engage in a  mediation  to
    develop a plan for a single RTO for the  Southeast.  Florida  Power and CP&L
    participated in the mediation.  FERC has not issued an order specifically on
    this  mediation.  On July 31,  2002,  FERC  issued  its  Notice of  Proposed
    Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
    Open Access Transmission Service and Standard Electricity Market Design (SMD
    NOPR).  If  adopted as  proposed,  the rules set forth in the SMD NOPR would
    materially alter the manner in which  transmission  and generation  services
    are  provided  and paid for.  Florida  Power and CP&L,  as  subsidiaries  of
    Progress Energy, filed comments on November 15, 2002 and supplement comments
    on January 10, 2003.  On January 15, 2003 FERC  announced  the issuance of a
    White  Paper on SMD NOPR to be released  in April  2003.  Florida  Power and
    CP&L, as subsidiaries of Progress Energy, plan to file comments on the White
    Paper.  FERC has also  indicated that it expects to issue final rules during
    the summer 2003.  The Company cannot predict the outcome of these matters or
    the effect that they may have on the GridFlorida  and GridSouth  proceedings
    currently  ongoing  before the FERC.  The Company  has $28.4  million and an
    insignificant amount invested in GridSouth and GridFlorida, respectively, at
    December 31, 2002.  It is unknown  what impact the future  proceedings  will
    have on the Company's earnings, revenues or prices.

16. Risk Management Activities and Derivatives Transactions

    Under  its  risk  management  policy,  the  Company  may  use a  variety  of
    instruments,  including  swaps,  options  and forward  contracts,  to manage
    exposure to  fluctuations  in  commodity  prices and  interest  rates.  Such
    instruments  contain credit risk if the counterparty  fails to perform under
    the contract.  The Company  minimizes such risk by performing credit reviews
    using,  among  other  things,  publicly  available  credit  ratings  of such
    counterparties.  Potential non-performance by counterparties is not expected
    to  have  a  material  effect  on the  consolidated  financial  position  or
    consolidated results of operations of the Company.

    A. Commodity Contracts - General

    Most of the Company's  commodity  contracts are not derivatives  pursuant to
    SFAS No. 133 or qualify as normal  purchases  or sales  pursuant to SFAS No.
    133. Therefore, such contracts are not recorded at fair value.

    B. Commodity Derivatives - Cash Flow Hedges

    The  Company  held  natural  gas and oil cash flow  hedging  instruments  at
    December 31, 2002. The objective for holding these  instruments is to manage
    a portion of the market risk  associated  with  fluctuations in the price of
    natural gas and oil on the Company's forecasted sales of natural gas and oil
    production. As of December 31, 2002, the Company is hedging exposures to the
    price  variability  of these  commodities  for  contracts  maturing  through
    December 2004.

    The total fair value of these  instruments  at December 31, 2002 was a $10.2
    million liability  position.  The ineffective portion of commodity cash flow
    hedges was not material in 2002.  As of December  31, 2002,  $5.0 million of
    after-tax  deferred losses in accumulated other  comprehensive  income (OCI)
    are expected to be reclassified to earnings during the next 12 months as the
    hedged transactions occur. Due to the volatility of the commodities markets,
    the value in OCI is subject  to change  prior to its  reclassification  into
    earnings.

                                       104
<PAGE>

    C. Commodity Derivatives - Economic Hedges and Trading

    Nonhedging derivatives, primarily electricity and natural gas contracts, are
    entered into for trading purposes and for economic hedging  purposes.  While
    management  believes the economic hedges mitigate  exposures to fluctuations
    in commodity  prices,  these  instruments  are not  designated as hedges for
    accounting purposes and are monitored consistent with trading positions. The
    Company  manages open positions with strict policies that limit its exposure
    to market  risk and require  daily  reporting  to  management  of  potential
    financial exposures.  Gains and losses from such contracts were not material
    during 2002, 2001 or 2000, and the Company did not have material outstanding
    positions in such contracts at December 31, 2002 or 2001.

    D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges

    The Company  manages its interest rate exposure in part by  maintaining  its
    variable-rate and fixed-rate  exposures  within defined limits. In addition,
    the Company also enters into financial  derivative  instruments,  including,
    but not limited to,  interest  rate swaps and lock  agreements to manage and
    mitigate interest rate risk exposure.

    The Company uses cash flow hedging  strategies  to hedge  variable  interest
    rates on long-term  debt and to hedge  interest  rates with regard to future
    fixed-rate  debt  issuances.  At December  31,  2002,  the  Company  held an
    interest  rate cash flow  hedge,  with a notional  amount of $35.0  million,
    related to an anticipated 2003 issuance of fixed-rate debt and held interest
    rate cash flow hedges,  with a varying notional amount and maximum of $195.0
    million, related to variable-rate debt. The total fair value of these hedges
    at December 31, 2002 was a $12.8 million liability position.  As of December
    31,  2002,  $7.8  million of  after-tax  deferred  losses in OCI,  including
    amounts in OCI related to terminated hedges, are expected to be reclassified
    to earnings during the next 12 months as the hedged interest payments occur.
    Due to the  volatility  of  interest  rates,  the value in OCI is subject to
    change prior to its  reclassification  into earnings.  At December 31, 2001,
    the Company had open interest  rate cash flow hedges with  notional  amounts
    totaling  $500.0  million and a total fair value of $18.5 million  liability
    position.

    The Company  uses fair value  hedging  strategies  to manage its exposure to
    fixed  interest  rates on long-term  debt. At December 31, 2002, the Company
    had open  interest  rate fair value hedges with  notional  amounts  totaling
    $350.0  million and a total fair value of $5.2 million  asset  position.  In
    addition,  the Company  initiated  and  terminated  interest rate fair value
    hedges on long-term debt in 2002,  resulting in total deferred hedging gains
    of approximately  $35.2 million reflected in long-term debt, which are being
    amortized over periods ending in 2006 and 2007  coinciding with the maturity
    of the related debt instruments.

    The notional  amounts of interest rate  derivatives are not exchanged and do
    not  represent  exposure  to  credit  loss.  In the  event of  default  by a
    counterparty,  the risk in these  transactions  is the cost of replacing the
    agreements at current market rates.

17. Stock-Based Compensation

    The Company  accounts for  stock-based  compensation  in accordance with the
    provisions of APB Opinion No. 25 as allowed by SFAS Nos. 123 and 148.

    A. Employee Stock Ownership Plan

    The Company  sponsors the Progress Energy 401(k) Savings and Stock Ownership
    Plan  (401(k)) for which  substantially  all full-time  non-bargaining  unit
    employees  and  certain  part-time   non-bargaining  unit  employees  within
    participating  subsidiaries are eligible.  Participating subsidiaries within
    the Company as of January 1, 2002 were CP&L, NCNG,  Florida Power,  Progress
    Telecom, Progress Fuels (Corporate) and Progress Energy Service Company. The
    401(k),  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 401(k), as amended in 1989,
    is an Employee Stock  Ownership Plan (ESOP) that can enter into  acquisition
    loans to acquire  Company common stock to satisfy 401(k) common share needs.
    Qualification  as an ESOP did not change the level of  benefits  received by
    employees  under the 401(k).  Common stock  acquired with the proceeds of an
    ESOP loan is held by the 401(k)  Trustee in a suspense  account.  The common

                                       105
<PAGE>

    stock  is  released  from  the  suspense  account  and  made  available  for
    allocation to participants as the ESOP loan is repaid.  Such allocations are
    used to partially  meet common stock needs  related to Company  matching and
    incentive contributions and/or reinvested dividends. All or a portion of the
    dividends  paid on ESOP  suspense  shares and on ESOP  shares  allocated  to
    participants may be used to repay ESOP acquisition loans. To the extent used
    to repay such loans,  the dividends are  deductible for income tax purposes.
    Also,  beginning in 2002, the dividends paid on ESOP shares which are either
    paid directly to  participants or used to purchase  additional  shares which
    are then  allocated  to  participants  are fully  deductible  for income tax
    purposes.

    There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
    and 2001,  respectively,  with a fair  value of $200.1  million  and  $234.1
    million,  respectively.  ESOP shares allocated to plan participants  totaled
    13,554,283 and 14,088,173 at December 31, 2002 and 2001,  respectively.  The
    Company's  matching and incentive goal compensation cost under the 401(k) is
    determined  based on matching  percentages  and incentive goal attainment as
    defined in the plan. Such  compensation  cost is allocated to  participants'
    accounts  in the form of  Company  common  stock,  with the number of shares
    determined by dividing compensation cost by the common stock market value at
    the time of allocation. The Company currently meets common stock share needs
    with open market  purchases,  with shares  released  from the ESOP  suspense
    account and with newly issued  shares.  Matching and incentive cost met with
    shares  released  from the  suspense  account  totaled  approximately  $20.3
    million,  $18.2 million and $15.6  million for the years ended  December 31,
    2002,  2001  and  2000,  respectively.  The  Company  has a  long-term  note
    receivable  from the 401(k) Trustee  related to the purchase of common stock
    from the Company in 1989. The balance of the note receivable from the 401(k)
    Trustee is included in the  determination  of  unearned  ESOP common  stock,
    which reduces common stock equity.  ESOP shares that have not been committed
    to be released to participants'  accounts are not considered outstanding for
    the determination of earnings per common share.  Interest income on the note
    receivable and dividends on  unallocated  ESOP shares are not recognized for
    financial statement purposes.

    B. Stock Option Agreements

    Pursuant  to the  Company's  1997  Equity  Incentive  Plan and  2002  Equity
    Incentive  Plan,  amended and restated as of July 10, 2002,  the Company may
    grant options to purchase shares of common stock to directors,  officers and
    eligible employees.  Generally, options granted to employees, vest one-third
    per year with 100%  vesting at the end of year three and options  granted to
    directors  vest 100% at the end of one year.  The  options  expire ten years
    from the date of grant.  All option  grants have an exercise  price equal to
    the fair market value of the Company's common stock on the grant date.

    Compensation expense is measured for stock options as the difference between
    the market price of the Company's common stock and the exercise price of the
    option at the grant  date.  Accordingly,  no  compensation  expense has been
    recognized for stock option grants.

    The pro forma  information  presented  in Note 1U  regarding  net income and
    earnings  per share is  required  by SFAS No.  123.  Under  this  statement,
    compensation  cost is  measured at the grant date based on the fair value of
    the award and is recognized over the vesting  period.  The pro forma amounts
    presented in Note 1U have been  determined  as if the Company had  accounted
    for its employee  stock options under SFAS No. 123. The fair value for these
    options  was  estimated  at the date of grant using a  Black-Scholes  option
    pricing model with the following weighted-average assumptions:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                  2002        2001
                                                               ----------------------
    Risk-free interest rate (%)                                   4.14%       4.83%
    Dividend yield (%)                                            5.20%       5.21%
    Volatility factor (%)                                         24.98%      26.47%
    Weighted-average expected life of the options (in years)        10          10
</TABLE>

    The  option  valuation  model  requires  the  input  of  highly   subjective
    assumptions,   primarily  stock  price  volatility,  changes  in  which  can
    materially affect the fair value estimate.

    The  options   outstanding   as  of  December   31,  2002  and  2001  had  a
    weighted-average   remaining  contractual  life  of  9.32  and  9.75  years,
    respectively,  and had  exercise  prices  that ranged from $41.97 to $51.85.
    There were no options  outstanding  at December  31,  2000.  At December 31,
    2002,   92,400   outstanding   shares  were  antidilutive  for  purposes  of
    calculating  diluted earnings per share. All options outstanding at December
    31, 2001 were antidilutive. As of December 31, 2002, no options have expired
    or been  exercised.  The tabular  information  for the option activity is as
    follows:

                                       106
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                  2002             2002           2001           2001
                                               -----------  ------------------ -----------  ---------------
                                                Number of    Weighted-Average   Number of      Weighted-
                                                 Options      Exercise Price     Options        Average
                                                                                             Exercise Price
    Options outstanding, January 1              2,328,855        $43.49                 -          -
    Granted                                     2,893,650        $42.34         2,353,155        $43.49
    Forfeited                                     (65,310)       $43.71           (24,300)       $43.49
    Options outstanding, December 31            5,157,195        $42.84         2,328,855        $43.49
    Options exercisable at December 31,
       with a remaining contractual life of
       8.75 years                                 754,538        $43.49                 -          -
    Weighted-average grant date fair value
       of options granted during the year                         $6.83                           $8.05

</TABLE>

    C. Other Stock-Based Compensation Plans

    The Company has additional compensation plans for officers and key employees
    of the Company  that are  stock-based  in whole or in part.  The two primary
    programs are the Performance  Share Sub-Plan (PSSP) and the Restricted Stock
    Awards  program  (RSA),  both of  which  were  established  pursuant  to the
    Company's 1997 Equity  Incentive Plan and were continued under the Company's
    2002 Equity Incentive Plan, as amended and restated as of July 10, 2002.

    Under the terms of the PSSP,  officers and key  employees of the Company are
    granted  performance shares that vest over a three-year  consecutive period.
    Each  performance  share has a value that is equal to, and changes with, the
    value of a share of the Company's common stock, and dividend equivalents are
    accrued on, and  reinvested  in, the  performance  shares.  The PSSP has two
    equally  weighted  performance  measures,  both of  which  are  based on the
    Company's  results as  compared to a peer group of  utilities.  Compensation
    expense is recognized over the vesting period based on the expected ultimate
    cash payout. Compensation expense is reduced by any forfeitures.

    The RSA allows the Company to grant  shares of  restricted  common  stock to
    officers and key employees of the Company.  The restricted  shares generally
    vest  on  a  graded  vesting   schedule  over  a  minimum  of  three  years.
    Compensation  expense,  which is based on the fair value of common  stock at
    the grant date, is  recognized  over the  applicable  vesting  period,  with
    corresponding  increases in common stock equity. The weighted-average  price
    of  restricted  shares at the grant  date was  $44.27,  $41.86 and $36.97 in
    2002, 2001 and 2000,  respectively.  Compensation  expense is reduced by any
    forfeitures. Restricted shares are not included as shares outstanding in the
    basic  earnings  per  share  calculation  until  the  shares  are no  longer
    forfeitable. Changes in restricted stock shares outstanding were:

                              2002          2001           2000
                           ----------    -----------    ------------

    Beginning balance        674,511       653,344        331,900
    Granted                  365,920       113,651        359,844
    Vested                   (75,200)      (70,762)          -
    Forfeited                (15,051)      (21,722)       (38,400)
                           ----------    -----------    ------------
    Ending balance           950,180       674,511        653,344
                           ==========    ===========    ============

    The total amount expensed for other stock-based compensation plans was $16.7
    million,   $14.3  million  and  $15.6  million  in  2002,   2001  and  2000,
    respectively.

                                       107
<PAGE>

18. Postretirement Benefit Plans

    A. Pension Benefits

    The Company and some of its  subsidiaries  have a  non-contributory  defined
    benefit retirement (pension) plan for substantially all full-time employees.
    The  Company  also has  supplementary  defined  benefit  pension  plans that
    provide benefits to higher-level employees.

    The components of net periodic  pension benefit for the years ended December
    31 are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                              2002               2001               2000
                                                          ---------------    ---------------    ---------------

    Expected return on plan assets                           $ (161,181)        $ (169,329)         $ (87,628)
    Service cost                                                 45,414             31,863             22,123
    Interest cost                                               105,646             96,200             56,924
    Amortization of transition obligation                           106                125                125
    Amortization of prior service (benefit) cost                    306             (1,325)            (1,314)
    Amortization of actuarial (gain) loss                         2,050             (4,989)            (5,721)
                                                          ---------------    ---------------    ---------------

         Net periodic pension benefit                            (7,659)           (47,455)           (15,491)
         Additional benefit recognition (Note 18C)               (7,614)           (16,464)            (3,401)
                                                          ---------------    ---------------    ---------------
         Net periodic pension benefit recognized              $ (15,273)          $(63,919)         $ (18,892)
                                                          ===============    ===============    ===============
</TABLE>

    In addition to the net periodic benefit reflected above, in 2000 the Company
    recorded  a charge of  approximately  $21.5  million  to  adjust  one of its
    supplementary defined benefit pension plans.

    Prior service costs and benefits are amortized on a straight-line basis over
    the average remaining service period of active participants. Actuarial gains
    and losses in excess of 10% of the greater of the pension  obligation or the
    market-related  value of assets are  amortized  over the  average  remaining
    service period of active participants.

    Reconciliations  of the changes in the plan's  benefit  obligations  and the
    plan's funded status are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                           2002              2001
                                                                        ------------      ------------
       Projected benefit obligation at  January 1                       $ 1,390,737       $ 1,376,859
           Interest cost                                                    105,646            96,200
           Service cost                                                      45,414            31,863
           Benefit payments                                                 (91,114)          (86,010)
           Actuarial loss                                                   242,898            13,164
           Plan amendments                                                        -            20,882
           Acquisition adjustment (Note 2C)                                       -           (62,221)
                                                                        ------------      ------------

       Projected benefit obligation at December 31                        1,693,581         1,390,737
       Fair value of plan assets at December 31                           1,363,943         1,677,630
                                                                        ------------      ------------

       Funded status                                                       (329,638)          286,893
       Unrecognized transition obligation                                       264               370
       Unrecognized prior service cost                                        5,040             5,346
       Unrecognized actuarial loss                                          741,885           111,600
       Minimum pension liability adjustment                                (496,904)                -
                                                                        ------------      ------------

       Prepaid (accrued) pension cost at December 31, net (Note 18C)     $  (79,353)        $ 404,209
                                                                        ============      ============
</TABLE>
                                       108
<PAGE>

    The net  accrued  pension  cost of $79.4  million at  December  31,  2002 is
    recognized  in the  accompanying  Consolidated  Balance  Sheets  as  prepaid
    pension cost of $60.2 million and accrued benefit cost of $139.6 million, of
    which $130.7 is included in other  liabilities and deferred credits and $8.9
    million is included  in  liabilities  of  discontinued  operations.  The net
    prepaid pension cost of $404.2 million at December 31, 2001 is recognized in
    the  accompanying  Consolidated  Balance  Sheets as prepaid  pension cost of
    $487.6 million,  accrued benefit cost of $85.4 million, which is included in
    other  liabilities  and deferred  credits,  and NCNG prepaid pension cost of
    $2.0  million  included in assets of  discontinued  operations.  The defined
    benefit plans with accumulated  benefit obligations in excess of plan assets
    had projected benefit  obligations  totaling $1.51 billion and $85.1 million
    at December  31, 2002 and 2001,  respectively.  Those plans had  accumulated
    benefit obligations totaling $1.35 billion and $83.9 million at December 31,
    2002 and 2001, respectively,  plan assets totaling $1.22 billion at December
    31, 2002 and no plan assets at December 31, 2001.

    Due to a  combination  of  decreases  in the fair value of plan assets and a
    decrease in the  discount  rate used to measure the  pension  obligation,  a
    minimum  pension  liability  adjustment  of $496.9  million was  recorded at
    December 31, 2002. This  adjustment  resulted in a charge of $5.3 million to
    intangible  assets,  included  in other  assets and  deferred  debits in the
    accompanying  Consolidated  Balance  Sheets,  a $178.3  million  charge to a
    pension-related  regulatory liability (See Note 18C) and a pre-tax charge of
    $313.3  million to  accumulated  other  comprehensive  loss,  a component of
    common stock equity.

    Reconciliations of the fair value of pension plan assets are (in thousands):

                                                    2002              2001
                                                ------------      ------------
    Fair value of plan assets at January 1      $ 1,677,630       $ 1,843,410
    Actual return on plan assets                   (228,256)
                                                                      (84,254)
    Benefit payments                                (91,114)          (86,010)
    Employer contributions                            5,683             4,484
                                                ------------      ------------
    Fair value of plan assets at December 31    $ 1,363,943       $ 1,677,630
                                                ============      ============

    The  weighted-average  discount rate used to measure the pension  obligation
    was 6.6% and 7.5% in 2002 and 2001, respectively.  The weighted-average rate
    of increase in future compensation for non-bargaining unit employees used to
    measure  the  pension  obligation  was 4.0% in  2002,  2001  and  2000.  The
    corresponding  rate of increase in future  compensation  for bargaining unit
    employees was 3.5% in 2002,  2001 and 2000.  The expected  long-term rate of
    return on pension plan assets used in determining  the net periodic  pension
    cost was 9.25% in 2002, 2001 and 2000.

    B. Retiree Health and Life Insurance Benefits

    In addition to pension  benefits,  the Company and some of its  subsidiaries
    provide contributory other postretirement benefits (OPEB), including certain
    health care and life  insurance  benefits,  for retired  employees  who meet
    specified criteria.

    The components of net periodic OPEB cost for the years ended December 31 are
    (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                               2002           2001           2000
                                            -----------    -----------    -----------

    Expected return on plan assets           $ (4,565)       $(4,651)      $ (4,045)
    Service cost                               13,099         13,231         10,067
    Interest cost                              31,876         28,414         15,446
    Amortization of prior service cost            506            319            107
    Amortization of transition obligation       3,066          4,701          5,878
    Amortization of actuarial (gain) loss         656           (592)          (819)
                                            -----------    -----------    -----------

    Net periodic OPEB cost                     44,638         41,422         26,634
    Additional cost recognition (Note 18C)      1,863          3,461            202
                                            -----------    -----------    -----------
    Net periodic OPEB cost recognized        $ 46,501       $ 44,883       $ 26,836
                                            ===========    ===========    ===========
</TABLE>
                                       109
<PAGE>

    Prior service costs and benefits are amortized on a straight-line basis over
    the average remaining service period of active participants. Actuarial gains
    and  losses in excess of 10% of the  greater of the OPEB  obligation  or the
    market-related  value of assets are  amortized  over the  average  remaining
    service period of active participants.

    Reconciliations  of the changes in the plan's  benefit  obligations  and the
    plan's funded status are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                             2002            2001
                                                          -----------    -----------

       OPEB obligation at  January 1                       $ 400,944      $ 374,923
           Interest cost                                      31,876         28,414
           Service cost                                       13,099         13,231
           Benefit payments                                  (24,144)       (17,207)
           Actuarial loss                                     91,842         27,428
           Plan amendment                                          -        (25,845)
                                                           ----------    -----------

       OPEB obligation at December 31                        513,617        400,944

       Fair value of plan assets at December 31               52,354         55,529
                                                           ----------    -----------

       Funded status                                        (461,263)      (345,415)
       Unrecognized transition obligation                     30,063         33,129
       Unrecognized prior service cost                         7,169          7,675
       Unrecognized actuarial loss                           106,686          6,429
                                                           ----------    -----------

       Accrued OPEB cost at December 31 (Note 18C)         $(317,345)     $(298,182)
                                                           ==========    ===========
</TABLE>

    The accrued OPEB cost is included in other  liabilities and deferred credits
    in the accompanying Consolidated Balance Sheets.

    Reconciliations of the fair value of OPEB plan assets are (in thousands):

                                                   2002          2001
                                                ---------     ---------
    Fair value of plan assets at January 1      $ 55,529      $ 54,642
    Actual return on plan assets                  (4,506)         (444)
    Employer contribution                         25,475        18,538
    Benefits paid                                (24,144)      (17,207)
                                                ---------     ---------

    Fair value of plan assets at December 31    $ 52,354      $ 55,529
                                                =========     =========

    The  assumptions  used to measure the OPEB  obligation and determine the net
    periodic OPEB cost are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                       2002           2001            2000

    Weighted-average long-term rate of return on plan assets           8.20%          8.70%           9.20%
    Weighted-average discount rate                                     6.60%          7.50%           7.50%
    Initial medical cost trend rate for pre-Medicare benefits          7.50%          7.50%        7.2% - 7.5%
    Initial medical cost trend rate for post-Medicare benefits         7.50%          7.50%        6.2% - 7.5%
    Ultimate medical cost trend rate                                   5.25%           5.0%        5.0% - 5.3%
    Year ultimate medical cost trend rate is achieved                  2009            2008         2005-2009
</TABLE>
                                       110
<PAGE>

    The medical  cost trend rates were  assumed to decrease  gradually  from the
    initial rates to the ultimate  rates.  Assuming a 1% increase in the medical
    cost trend rates,  the aggregate of the service and interest cost components
    of the net periodic OPEB cost for 2002 would  increase by $7.0 million,  and
    the OPEB  obligation at December 31, 2002,  would increase by $50.8 million.
    Assuming a 1% decrease in the medical cost trend rates, the aggregate of the
    service and interest cost  components of the net periodic OPEB cost for 2002
    would decrease by $6.0 million and the OPEB obligation at December 31, 2002,
    would decrease by $46.2 million.

    C. FPC Acquisition

    During 2000,  the Company  completed the  acquisition  of FPC (See Note 2C).
    FPC's  pension  and OPEB  liabilities,  assets  and net  periodic  costs are
    reflected  in  the  above  information  as  appropriate.  Certain  of  FPC's
    non-bargaining  unit  benefit  plans were  merged  with those of the Company
    effective January 1, 2002.

    Florida  Power  continues to recover  qualified  plan pension costs and OPEB
    costs  in rates  as if the  acquisition  had not  occurred.  Accordingly,  a
    portion  of the  accrued  OPEB  cost  reflected  in the  table  above  has a
    corresponding regulatory asset at December 31, 2002 and 2001 (see Note 15A).
    In addition,  a portion of the prepaid  pension cost  reflected in the table
    above  has a  corresponding  regulatory  liability.  Pursuant  to  its  rate
    treatment,  Florida Power recognized additional periodic pension credits and
    additional  periodic  OPEB costs,  as  indicated  in the net  periodic  cost
    information above.

19. Earnings Per Common Share

    Basic earnings per common share is based on the  weighted-average  number of
    common shares outstanding. Diluted earnings per share includes the effect of
    the  non-vested  portion of restricted  stock awards and the effect of stock
    options outstanding.

    A reconciliation of the weighted-average number of common shares outstanding
    for basic and dilutive purposes is as follows (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                      2002            2001             2000
                                                  -------------    ------------     ------------
    Weighted-average common shares - basic           217,247         204,683          157,169
    Restricted stock awards                              766             664              455
    Stock options                                        153               -                -
                                                  -------------    ------------     ------------
    Weighted-average shares - fully dilutive         218,166         205,347          157,624
                                                  =============    ============     ============
</TABLE>

    There  are no  adjustments  to  net  income  or to  income  from  continuing
    operations  between the calculations of basic and fully diluted earnings per
    common  share.  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. The  weighted-average  of these shares totaled
    4.8  million,  5.4 million and 5.7 million for the years ended  December 31,
    2002, 2001 and 2000, respectively.

20. Income Taxes

    Deferred  income taxes are provided for temporary  differences  between book
    and tax bases of assets and  liabilities.  Investment tax credits related to
    regulated  operations  are  amortized  over the service  life of the related
    property. A regulatory asset or liability has been recognized for the impact
    of tax  expenses or benefits  that are  recovered  or refunded in  different
    periods by the utilities pursuant to rate orders.

                                       111
<PAGE>

    Accumulated  deferred income tax (assets) liabilities at December 31 are (in
    thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                  2002              2001
                                                              ------------      ------------
    Accelerated depreciation and property cost differences    $ 1,657,410       $ 1,748,646
    Deferred costs, net                                           (33,485)           79,819
    Federal income tax credit carry forward                      (474,545)         (278,773)
    Minimum pension liability adjustment                         (117,064)                -
    Miscellaneous other temporary differences, net               (106,650)         (149,615)
    Valuation allowance                                            46,779            35,270
                                                              ------------      ------------

    Net accumulated deferred income tax liability             $   972,445       $ 1,435,347
                                                              ============      ============
</TABLE>

    Total deferred income tax  liabilities  were $2.50 billion and $2.64 billion
    at  December  31, 2002 and 2001,  respectively.  Total  deferred  income tax
    assets were $1.53  billion and $1.20  billion at December 31, 2002 and 2001,
    respectively. The net of deferred income tax liabilities and deferred income
    tax assets is included on the Consolidated Balance Sheets under the captions
    other current liabilities and accumulated deferred income taxes.

    The federal income tax credit carry forward at December 31, 2002 consists of
    $451.6  million of alternative  minimum tax credit with an indefinite  carry
    forward  period and $22.9  million of general  business  credit with a carry
    forward period that will begin to expire in 2020.

    The Company established valuation allowances of $11.5 million, $24.4 million
    and $10.9  million  during  2002,  2001 and 2000,  respectively,  due to the
    uncertainty  of realizing  certain  future state tax  benefits.  The Company
    believes it is more  likely  than not that the results of future  operations
    will generate  sufficient taxable income to allow for the utilization of the
    remaining deferred tax assets.

    Reconciliations of the Company's  effective income tax rate to the statutory
    federal income tax rate are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                     2002           2001             2000
                                                  ----------     ----------      -----------

    Effective income tax rate                       (40.0)%       (40.0)%           29.1%
    State income taxes, net of federal benefit       (8.2)         (7.7)            (4.7)
    AFUDC amortization                               (5.2)         (5.0)            (5.2)
    Federal tax credits                              78.0          94.5             12.3
    Goodwill amortization and write-offs               -          (11.4)            (0.5)
    Investment tax credit amortization                4.7           5.9              4.2
    ESOP dividend deduction                           3.8           1.9              1.0
    Interpath investment impairment                     -          (2.1)              -
    Other differences, net                            1.9          (1.1)            (1.2)
                                                  ----------     ----------      -----------

      Statutory federal income tax rate              35.0%         35.0%            35.0%
                                                  ==========     ==========      ===========
</TABLE>

    Income  tax  expense  (benefit)  applicable  to  continuing   operations  is
    comprised of (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                  2002           2001          2000
                                               -----------   -----------    ----------
    Current   - federal                        $  194,914    $  183,548     $ 247,991
                state                              67,785        52,144        59,832
    Deferred  - federal                          (378,939)     (356,919)      (82,966)
                state                             (23,101)      (10,411)      (10,414)
    Investment tax credit                         (18,467)      (22,700)      (17,941)
                                               -----------   -----------    ----------

          Total income tax expense (benefit)   $ (157,808)   $ (154,338)    $ 196,502
                                               ===========   ===========    ==========
</TABLE>
                                       112
<PAGE>

    The Company, through its subsidiaries,  is a majority owner in five entities
    and a  minority  owner  in one  entity  that  own  facilities  that  produce
    synthetic  fuel as defined under the Internal  Revenue  Service Code (Code).
    The  production  and  sale  of the  synthetic  fuel  from  these  facilities
    qualifies  for tax  credits  under  Section 29 of the Code  (Section  29) if
    certain  requirements  are  satisfied,  including  a  requirement  that  the
    synthetic fuel differs  significantly in chemical  composition from the coal
    used to produce such synthetic fuel.  Total Section 29 credits  generated to
    date   (including  FPC  prior  to  its   acquisition  by  the  Company)  are
    approximately  $897.2  million.  All entities have received  private  letter
    rulings  (PLR's) from the  Internal  Revenue  Service  (IRS) with respect to
    their  synthetic fuel  operations.  The PLR's do not limit the production on
    which  synthetic  fuel  credits  may be  claimed.  Should the tax credits be
    denied on future audits, and the Company fails to prevail through the IRS or
    legal  process,  there  could  be  a  significant  tax  liability  owed  for
    previously taken Section 29 credits,  with a significant  impact on earnings
    and cash flows.

    One of  the  Company's  synthetic  fuel  entities,  Colona  Synfuel  Limited
    Partnership,  L.L.L.P.  (Colona),  is being audited by the IRS. The audit of
    Colona was expected.  The Company is audited  regularly in the normal course
    of business as are most similarly situated companies. The Company (including
    FPC  prior  to  its   acquisition   by  the  Company)  has  been   allocated
    approximately  $251 million in tax credits to date for this  synthetic  fuel
    entity. As provided for in contractual  arrangements  pertaining to Progress
    Energy's  purchase  of Colona,  the Company  has begun  escrowing  quarterly
    royalty  payments owed to an unaffiliated  entity until final  resolution of
    the audit.

    In September 2002, all of Progress  Energy's  majority-owned  synthetic fuel
    entities,   including  Colona,  were  accepted  into  the  IRS's  Pre-Filing
    Agreement  (PFA) program.  The PFA program  allows  taxpayers to voluntarily
    accelerate  the IRS exam  process in order to seek  resolution  of  specific
    issues.  Either the Company or the IRS can withdraw  from the program at any
    time,  and issues not  resolved  through the program may proceed to the next
    level of the IRS exam process. While the ultimate outcome is uncertain,  the
    Company  believes that  participation in the PFA program will likely shorten
    the tax exam process.

    In management's opinion, Progress Energy is complying with all the necessary
    requirements to be allowed such credits and believes it is likely,  although
    it cannot provide  certainty,  that it will prevail if challenged by the IRS
    on any credits taken.

21. Other Income and Other Expense

    Other  income and  expense  includes  interest  income,  gain on the sale of
    investments, impairment of investments and other income and expense items as
    discussed  below.  The components of other, net as shown on the Consolidated
    Statements  of Income for the years  ended  December  31 are as follows  (in
    thousands):

                                       113
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                     2002          2001          2000
                                                                 ------------  ------------- ------------
    Other income
    Net financial trading gain (loss)                               $  (1,942)   $     (696)    $ 15,603
    Net energy purchased for resale                                     1,540         2,786        2,260
    Nonregulated energy and delivery services income                   28,754        29,183       26,225
    Contingent value obligation unrealized gain (Note 10)              28,109             -        8,876
    Investment gains                                                   30,218         2,500        6,722
    AFUDC equity                                                        8,739         8,842       13,568
    Other                                                              31,174        16,444       12,828
                                                                 ------------- ------------- -------------
        Total other income                                          $ 126,592    $   59,059     $ 86,082
                                                                 ------------- ------------- -------------

    Other expense
    Nonregulated energy and delivery services expenses                 28,766        34,734       25,459
    Donations                                                          21,302        23,035        9,397
    Investment losses                                                  18,235         4,365        6,672
    Contingent value obligation unrealized loss (Note 10)                   -         1,479            -
    Other                                                              24,485        23,885       29,131
                                                                 ------------- ------------- -------------
       Total other expense                                          $  92,788    $   87,498     $ 70,659

    Other, net                                                      $  33,804    $  (28,439)    $ 15,423
                                                                 ============= ============= =============
</TABLE>

    Net  financial  trading gain (loss)  represents  non-asset-backed  trades of
    electricity and gas. Nonregulated energy and delivery services include power
    protection  services and mass market programs (surge  protection,  appliance
    services and area light sales) and  delivery,  transmission  and  substation
    work for other utilities.

22. Joint Ownership of Generating Facilities

    CP&L and Florida Power hold undivided ownership interests in certain jointly
    owned  generating  facilities.  Each is 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.  CP&L's and Florida
    Power's  share of expenses for the jointly  owned  facilities is included in
    the appropriate  expense category.  The co-owner of P11 has exclusive rights
    to the  output of the unit  during  the  months of June  through  September.
    Florida Power has that right for the remainder of the year.

    CP&L's  and  Florida  Power's  ownership  interests  in  the  jointly  owned
    generating  facilities  are listed  below  with  related  information  as of
    December 31, 2002 and 2001 (dollars in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

    2002
                                                  Company                                                        Construction
                                                 Ownership       Plant        Accumulated       Accumulated        Work in
        Subsidiary             Facility           Interest    Investment     Depreciation      Decommissioning     Progress
       ----------             --------           --------     ----------     ------------      ---------------    -----------

    CP&L                Mayo Plant                 83.83%     $  464,202      $  239,971           $      -        $ 14,089
    CP&L                Harris Plant               83.83%      3,159,946       1,432,245             95,643           6,117
    CP&L                Brunswick Plant            81.67%      1,476,534         867,530            339,521          26,436
    CP&L                Roxboro Unit  4            87.06%        316,491         138,408                  -           8,079
    Florida Power       Crystal River Unit 3       91.78%        777,141         504,417            396,868          27,907
    Florida Power       Intercession Unit P-11     66.67%         22,090           5,232                  -           3,987
</TABLE>
                                       114
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

    2001
                                                  Company                                                        Construction
                                                 Ownership       Plant        Accumulated       Accumulated         Work in
        Subsidiary             Facility           Interest    Investment     Depreciation      Decommissioning      Progress
        ----------             --------           --------    ----------     ------------      ---------------    -----------

    CP&L                Mayo Plant                 83.83%     $  460,026      $  230,630           $      -        $  7,116
    CP&L                Harris Plant               83.83%      3,154,183       1,321,694             93,637          14,416
    CP&L                Brunswick Plant            81.67%      1,427,842         828,480            339,945          41,455
    CP&L                Roxboro Unit  4            87.06%        309,032         126,007                  -           7,881
    Florida Power       Crystal River Unit 3       91.78%        773,835         469,840            416,995          25,723
    Florida Power       Intercession Unit P-11     66.67%         22,302           4,583                  -              94
</TABLE>

    In the table above,  plant  investment and accumulated  depreciation are not
    reduced by the regulatory disallowances related to the Harris Plant.

23. Accumulated Other Comprehensive Loss

    Components  of  accumulated  other  comprehensive  loss are as  follows  (in
    thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                              2002             2001
                                                           ------------    -------------
    Loss on cash flow hedges                                $ (42,236)        $(30,623)
    Minimum pension liability adjustments                    (192,385)               -
    Foreign currency translation and other                     (3,141)          (1,557)
                                                           ------------    -------------
    Total accumulated other comprehensive loss              $(237,762)        $(32,180)
                                                           ============    =============
</TABLE>

24. Commitments and Contingencies

    A. Fuel and Purchased Power

    Pursuant to the terms of the 1981 Power Coordination  Agreement, as amended,
    between CP&L and Power Agency, CP&L is obligated to purchase a percentage of
    Power Agency's  ownership capacity of, and energy from, the Harris Plant. In
    1993,  CP&L 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,  CP&L  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  capacity  costs,  total  approximately  $33  million.  These
    contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
    for 2002,  2001 and 2000,  respectively.  In 1987,  the NCUC ordered CP&L 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. At December 31, 2002 and 2001, CP&L had deferred  purchased  capacity
    costs,  including carrying costs accrued on the deferred balances,  of $16.9
    million and $32.5 million, respectively.  Increased purchases (which are not
    being deferred for future  recovery)  resulting from the 1993 agreement with
    Power  Agency were  approximately  $32.2  million,  $28.6  million and $26.0
    million for 2002, 2001 and 2000, respectively.

    CP&L  has a  long-term  agreement  for the  purchase  of power  and  related
    transmission  services from Indiana  Michigan Power Company's  Rockport Unit
    No. 2 (Rockport).  The agreement  provides for the purchase of 250 megawatts
    of capacity through 2009 with minimum annual payments of  approximately  $31
    million,   representing  capital-related  capacity  costs.  Total  purchases
    (including  transmission use charges) under the Rockport  agreement amounted
    to $58.6 million,  $62.8 million and $61.0 million for 2002,  2001 and 2000,
    respectively.

    Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
    of power from Skygen Energy LLC's Broad River facility  (Broad  River).  The
    agreement  provides  for the  purchase of  approximately  500  megawatts  of
    capacity   through  2021  with  an  original   minimum   annual  payment  of
    approximately $16 million,  primarily representing  capital-related capacity
    costs. A separate long-term  agreement for additional power from Broad River

                                       115
<PAGE>

    commenced June 1, 2002. This agreement provided for the additional  purchase
    of  approximately  300  megawatts of capacity  through 2022 with an original
    minimum   annual   payment  of   approximately   $16  million   representing
    capital-related  capacity  costs.  Total  purchases  under the  Broad  River
    agreements  amounted to $37.7  million  and $21.2  million in 2002 and 2001,
    respectively.

    Florida Power has long-term  contracts  for  approximately  473 megawatts of
    purchased power with other utilities, including a contract with The Southern
    Company for  approximately 413 megawatts of purchased power annually through
    2010. Florida Power can lower these purchases to approximately 200 megawatts
    annually  with a three-year  notice.  Total  purchases,  for both energy and
    capacity,  under these agreements amounted to $159.3 million, $111.7 million
    and $104.5  million for 2002,  2001 and 2000,  respectively.  Total capacity
    payments were $50.5 million,  $54.1 million and $54.0 million for 2002, 2001
    and  2000,   respectively.   Minimum   purchases   under  these   contracts,
    representing  capital-related  capacity costs, are approximately $50 million
    annually through 2005 and $30 million annually for 2006 and 2007.

    Both CP&L and Florida  Power have ongoing  purchased  power  contracts  with
    certain cogenerators  (qualifying  facilities) with expiration dates ranging
    from 2003 to 2025.  These purchased power  contracts  generally  provide for
    capacity  and  energy  payments.  Energy  payments  for  the  Florida  Power
    contracts  are based on actual power taken under these  contracts.  Capacity
    payments are subject to the qualifying  facilities  meeting certain contract
    performance  obligations.  Florida  Power's total capacity  purchases  under
    these  contracts  amounted  to $231.7  million,  $225.8  million  and $226.4
    million  for 2002,  2001 and 2000,  respectively.  Minimum  expected  future
    capacity  payments under these  contracts as of December 31, 2002 are $246.8
    million,  $257.4 million,  $268.7 million, $279.7 million and $289.4 million
    for 2003 through 2007,  respectively.  CP&L has various  pay-for-performance
    contracts  with  qualifying  facilities for  approximately  300 megawatts of
    capacity expiring at various times through 2009.  Payments for both capacity
    and  energy  are  contingent  upon the  qualifying  facilities'  ability  to
    generate.  Payments made under these  contracts were $144.5 million in 2002,
    $145.1 million in 2001 and $168.4 million in 2000.

    Florida  Power and CP&L have entered into various  long-term  contracts  for
    coal, gas and oil  requirements of their generating  plants.  Payments under
    these  commitments  were $1.9 billion,  $1.7 billion and $678.8  million for
    2002,  2001 and  2000,  respectively.  Estimated  annual  payments  for firm
    commitments of fuel purchases and transportation costs under these contracts
    are approximately $1.7 billion, $1.1 billion, $913.8 million, $907.7 million
    and $850.6 million for 2003 through 2007, respectively.

    B. Other Commitments

    The Company has certain  future  commitments  related to four synthetic fuel
    facilities  purchased that provide for contingent payments (royalties) of up
    to $11.4 million on sales from each plant annually through 2007. The related
    agreements  were amended in December  2001 to require the payment of minimum
    annual royalties of approximately  $6.6 million for each plant through 2007.
    As a result of the amendment,  the Company recorded a liability (included in
    other  liabilities and deferred credits on the Consolidated  Balance Sheets)
    and a deferred cost asset  (included in other assets and deferred  debits in
    the Consolidated  Balance Sheets),  each of approximately $114.3 million and
    $134.3 million at December 31, 2002 and 2001, respectively, representing the
    minimum  amounts due through 2007,  discounted at 6.05%.  As of December 31,
    2002 and 2001,  the portions of the asset and  liability  recorded that were
    classified  as current were $23.8 million and $25.8  million,  respectively.
    The deferred  cost asset will be amortized to expense each year as synthetic
    fuel sales are made.  The maximum  amounts  payable  under these  agreements
    remain   unchanged.   Actual  amounts  paid  under  these   agreements  were
    approximately $51.4 million in 2002, $45.8 million in 2001 and $43.1 million
    in 2000.

    The Company has entered into a joint venture to build a 750-mile natural gas
    pipeline system to serve 14 eastern North Carolina counties. The Company has
    agreed to fund  approximately  $22.0  million  of the  project.  The  entire
    project is expected to be completed in early 2005. In  conjunction  with the
    NCNG divestiture, the Company expects to sell its interest in the venture to
    Piedmont  Natural Gas,  Inc. by summer 2003,  subject to receipt of required
    regulatory approvals (See Note 3A).

                                       116
<PAGE>

    C. Guarantees

    As a part of normal business, Progress Energy and certain subsidiaries enter
    into various agreements  providing  financial or performance  assessments to
    third parties. Such agreements include guarantees, standby letters of credit
    and surety bonds.  These agreements are entered into primarily to support or
    enhance the  creditworthiness  otherwise  attributed  to a  subsidiary  on a
    stand-alone basis,  thereby  facilitating the extension of sufficient credit
    to accomplish the subsidiaries' intended commercial purposes.

    At  December  31,  outstanding  guarantees  are  summarized  as follows  (in
    millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                2002           2001
                                                           ------------    -----------
    Guarantees supporting nonregulated portfolio expansion
       and energy marketing and trading activities            $ 329.0         $ 23.0
    Standby letters of credit                                    48.2           29.2
    Surety bonds                                                106.8           52.1
    Other guarantees                                             18.6           39.8
                                                           ------------    -----------
       Total                                                  $ 502.6        $ 144.1
                                                           ============    ===========
</TABLE>

    Guarantees Supporting  Nonregulated Portfolio Expansion and Energy Marketing
    and Trading Activities

    Progress  Energy has issued  approximately  $317.0  million of guarantees on
    behalf of PVI and its  subsidiaries  for  obligations  under power purchase
    agreements, tolling agreements, gas agreements,  construction agreements and
    trading operations. Approximately $145.0 million of these commitments relate
    to certain  guarantee  agreements issued to support  obligations  related to
    PVI's expansion of its nonregulated generation portfolio.

    The remaining  $172.0  million of these new  commitments  issued by Progress
    Energy are guarantees  issued to support PVI's energy  marketing and trading
    functions.  The majority of the marketing and trading contracts supported by
    the  guarantees  contain  language  regarding   downgrade  events,   ratings
    triggers,  monthly netting of exposure and/or payments and offset provisions
    in the  event of a  default.  Based  upon the  amount of  trading  positions
    outstanding  at December 31, 2002, if the Company's  ratings were to decline
    below  investment  grade,  the Company would have to deposit cash or provide
    letters of credit or other cash collateral for  approximately  $13.7 million
    for the benefit of the Company's counterparties.

    In addition,  PVI issued a $12.0 million  guarantee  related to expansion of
    the  portfolio.   These  guarantees  ensure   performance  under  generation
    construction and operating agreements.

    Standby Letters of Credit

    The Company has issued stand-by letters of credit to financial  institutions
    for the benefit of third  parties that have  extended  credit to the Company
    and certain subsidiaries. These letters of credit have been issued primarily
    for  the  purpose  of  supporting  payments  of  trade  payables,   securing
    performance  under contracts and lease  obligations and  self-insurance  for
    workers compensation.  If a subsidiary does not pay amounts when due under a
    covered contract,  the counterparty may present its claim for payment to the
    financial institution,  which will in turn request payment from the Company.
    Any  amounts  owed  by  the  Company's  subsidiaries  are  reflected  in the
    accompanying Consolidated Balance Sheets.

    Surety Bonds

    At  December  31,  2002,  the  Company  had $106.8  million in surety  bonds
    purchased  primarily  for  purposes  such as providing  worker  compensation
    coverage and obtaining  licenses,  permits and rights-of-way.  To the extent
    liabilities are incurred as a result of the activities covered by the surety
    bonds,  such  liabilities  are  included  in the  accompanying  Consolidated
    Balance Sheets.

                                       117
<PAGE>

    Other Guarantees

    The Company has other  guarantees  outstanding  related  primarily to prompt
    performance  payments,  lease  obligations  and other  payments  subject  to
    contingencies.

    As of December 31, 2002,  management does not believe  conditions are likely
    for performance under these agreements.

    D. Insurance

    CP&L and Florida  Power are members 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,  each company is insured for $500 million at each of its respective
    nuclear  plants.  In  addition  to  primary  coverage,  NEIL  also  provides
    decontamination,  premature  decommissioning  and excess property  insurance
    with limits of $2.0 billion on the  Brunswick  and Harris  Plants,  and $1.1
    billion on the Robinson and CR3 Plants.

    Insurance coverage against  incremental costs of replacement power resulting
    from  prolonged  accidental  outages  at  nuclear  generating  units is also
    provided through membership in NEIL. Both CP&L and Florida Power are insured
    thereunder,  following a twelve-week  deductible period, for 52 weeks in the
    amount of $3.5 million per week at each of the nuclear units.  An additional
    110 weeks of coverage is provided at 80% of the above weekly amount. For the
    current policy period,  the companies are subject to  retrospective  premium
    assessments of up to approximately $31.4 million with respect to the primary
    coverage, $32.5 million with respect to the decontamination, decommissioning
    and  excess  property  coverage,  and  $22.2  million  for  the  incremental
    replacement  power costs  coverage,  in the event covered  losses at insured
    facilities exceed premiums, reserves,  reinsurance and other NEIL resources.
    Pursuant to regulations,  each 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
    decontaminate,  before any proceeds can be used for  decommissioning,  plant
    repair or restoration.  Each company is responsible to the extent losses may
    exceed limits of the coverage described above.

    Both CP&L and  Florida  Power are insured  against  public  liability  for a
    nuclear  incident  up to $9.55  billion  per  occurrence.  Under the current
    provisions of the Price Anderson Act,  which limits  liability for accidents
    at nuclear power plants,  each company, as an owner of nuclear units, can be
    assessed for a portion of any third-party  liability  claims arising from an
    accident at any commercial  nuclear power plant in the United States. In the
    event that public  liability  claims from an insured nuclear incident exceed
    $300 million (currently available through commercial insurers), each company
    would be subject to pro rata  assessments  of up to $88.1  million  for each
    reactor owned per occurrence. Payment of such assessments would be made over
    time as  necessary  to limit the payment in any one year to no more than $10
    million per reactor owned.  Congress is expected to approve revisions to the
    Price Anderson Act in the first quarter of 2003, that will include increased
    limits and assessments  per reactor owned.  The final outcome of this matter
    cannot be predicted at this time.

    There have been recent  revisions  made to the nuclear  property and nuclear
    liability insurance policies regarding the maximum recoveries  available for
    multiple  terrorism  occurrences.  Under the NEIL  policies,  if there  were
    multiple  terrorism  losses  occurring  within one year after the first loss
    from  terrorism,  NEIL would make available one industry  aggregate limit of
    $3.2  billion,   along  with  any  amounts  it  recovers  from  reinsurance,
    government indemnity or other sources up to the limits for each claimant. If
    terrorism  losses occurred beyond the one-year  period,  a new set of limits
    and  resources  would apply.  For nuclear  liability  claims  arising out of
    terrorist acts, the primary level available through  commercial  insurers is
    now subject to an industry aggregate limit of $300 million. The second level
    of coverage obtained through the assessments  discussed above would continue
    to apply to losses  exceeding  $300  million and would  provide  coverage in
    excess of any diminished primary limits due to the terrorist acts aggregate.

    CP&L and Florida Power self-insure their transmission and distribution lines
    against loss due to storm damage and other natural disasters.  Florida Power
    accrues  $6  million  annually  to a  storm  damage  reserve  pursuant  to a
    regulatory  order and may defer  losses in excess of the  reserve  (See Note
    15A).

                                       118
<PAGE>

    E. Claims and uncertainties

    1. The Company is subject to federal, state and local regulations addressing
    hazardous  and  solid  waste  management,  air and water  quality  and other
    environmental matters.

    Hazardous and Solid Waste Management

    Various  organic  materials  associated  with the production of manufactured
    gas,  generally  referred to as coal tar, are  regulated  under  federal and
    state  laws.  The  principal  regulatory  agency that is  responsible  for a
    specific former  manufactured  gas plant (MGP) site depends largely upon the
    state in which the site is  located.  There are  several  MGP sites to which
    both electric  utilities and the gas utility have some  connection.  In this
    regard,  both electric  utilities and the gas utility and other  potentially
    responsible  parties  are participating in investigating  and, if necessary,
    remediating  former MGP sites with several regulatory  agencies,  including,
    but not limited to, the U.S.  Environmental  Protection  Agency  (EPA),  the
    Florida Department of Environmental Protection (FDEP) and the North Carolina
    Department  of  Environment  and  Natural   Resources,   Division  of  Waste
    Management  (DWM).  In  addition,  the  Company  and  its  subsidiaries  are
    periodically  notified  by  regulators  such as the EPA  and  various  state
    agencies of their involvement or potential  involvement in sites, other than
    MGP sites, that may require  investigation and/or remediation.  A discussion
    of these sites by legal entity follows.

    CP&L.  There are 12 former MGP sites and 14 other sites associated with CP&L
    that have  required  or are  anticipated  to  require  investigation  and/or
    remediation  costs.  CP&L  received  insurance  proceeds  to  address  costs
    associated with  environmental  liabilities  related to its involvement with
    MGP sites.  All  eligible  expenses  related to these are charged  against a
    specific  fund  containing   these  proceeds.   As  of  December  31,  2002,
    approximately  $8.0 million remains in this  centralized fund with a related
    accrual  of  $8.0   million   recorded  for  the   associated   expenses  of
    environmental  issues.  As  CP&L's  share of  costs  for  investigating  and
    remediating  these sites becomes known, the fund is assessed to determine if
    additional  accruals  will be  required.  CP&L does not believe  that it can
    provide an estimate  of the  reasonably  possible  total  remediation  costs
    beyond what remains in the  environmental  insurance  recovery fund. This is
    due to the fact that the sites are at different  stages:  investigation  has
    not begun at 15 sites,  investigation  has begun but  remediation  cannot be
    estimated  at seven  sites  and four  sites  have  begun  remediation.  CP&L
    measures its liability for these sites based on available evidence including
    its experience in  investigating  and remediating  environmentally  impaired
    sites.  The process often  involves  assessing and  developing  cost-sharing
    arrangements  with  other   potentially   responsible   parties.   Once  the
    environmental  insurance  recovery fund is depleted,  CP&L will accrue costs
    for the sites to the extent its  liability  is probable and the costs can be
    reasonably estimated.  Presently, CP&L cannot determine the total costs that
    may be incurred in connection with the  remediation of all sites.  According
    to  current  information,  these  future  costs  at the CP&L  sites  are not
    expected to be material to the Company's  financial  condition or results of
    operations.

    Florida  Power.  There are two  former MGP sites and 11 other  active  sites
    associated  with  Florida  Power that have  required or are  anticipated  to
    require  investigation and/or remediation costs. As of December 31, 2002 and
    2001,  Florida  Power  has  accrued  approximately  $10.9  million  and $8.5
    million,  respectively, for probable and reasonably estimable costs at these
    sites. Florida Power does not believe that it can provide an estimate of the
    reasonably  possible  total  remediation  costs  beyond  what  is  currently
    accrued.   In  2002,   Florida  Power  filed  a  petition  for  recovery  of
    approximately  $4.0 million in environmental costs through the Environmental
    Cost Recovery  Clause with the FPSC.  Florida Power was successful with this
    filing  and  will  recover  costs  through  rates  for   investigation   and
    remediation  associated with  transmission and distribution  substations and
    transformers.  As more  activity  occurs at these sites,  Florida Power will
    assess the need to adjust the accruals. These accruals have been recorded on
    an undiscounted basis.  Florida Power measures its liability for these sites
    based on available  evidence  including its experience in investigating  and
    remediating  environmentally  impaired  sites.  This process often  includes
    assessing and developing  cost-sharing  arrangements  with other potentially
    responsible parties.

                                       119
<PAGE>

    NCNG.  There are five former MGP sites associated with NCNG that have or are
    anticipated to have investigation or remediation costs associated with them.
    As of December 31,  2002,  NCNG has accrued  approximately  $2.8 million for
    probable and reasonably  estimable  remediation costs at these sites.  These
    accruals  have been  recorded on an  undiscounted  basis.  NCNG measures its
    liability  for  these  sites  based  on  available  evidence  including  its
    experience in investigating and remediating  environmentally impaired sites.
    This  process  often   involves   assessing  and   developing   cost-sharing
    arrangements  with  other  potentially  responsible  parties.  NCNG does not
    believe  it can  provide  an  estimate  of  the  reasonably  possible  total
    remediation  costs  beyond  the  accrual  because  two  of  the  five  sites
    associated  with NCNG have not begun  investigation  activities.  Therefore,
    NCNG  cannot  currently  determine  the total  costs that may be incurred in
    connection with the  investigation  and/or  remediation of all sites.  Based
    upon  current  information,  the Company does not expect the future costs at
    the NCNG  sites to be  material  to the  Company's  financial  condition  or
    results of operations.  On October 16, 2002, the Company  announced plans to
    sell NCNG to Piedmont  Natural Gas Company,  Inc. (See Note 3A). The Company
    will retain the environmental  liability associated with the five former MGP
    sites.

    Florida  Progress   Corporation.   In  2001,  FPC  sold  its  Inland  Marine
    Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources,
    Inc. (See Note 3C). FPC  established an accrual to address  indemnities  and
    retained an environmental liability  associated  with the  transaction.  The
    balance in this accrual is $9.9 million at December 31, 2002.  FPC estimates
    that its maximum contractual  liability to AEP Resources,  Inc.,  associated
    with Inland  Marine  Transportation  is $60  million.  This accrual has been
    determined  on an  undiscounted  basis.  FPC measures its liability for this
    site based on estimable  and  probable  remediation  scenarios.  The Company
    believes that it is reasonably  probable that additional costs, which cannot
    be  currently  estimated,  may be  incurred  related  to  the  environmental
    indemnification  provision  beyond the amount  accrued.  The Company  cannot
    predict the outcome of this matter.

    CP&L,  Florida  Power,  PVI and NCNG have filed  claims  with the  Company's
    general liability  insurance carriers to recover costs arising out of actual
    or potential  environmental  liabilities.  Some claims have been settled and
    others are still  pending.  While the Company  cannot predict the outcome of
    these matters,  the outcome is not expected to have a material effect on the
    consolidated financial position or results of operations.

    The Company is also  currently in the process of assessing  potential  costs
    and exposures at other  environmentally  impaired  sites. As the assessments
    are developed  and analyzed,  the Company will accrue costs for the sites to
    the extent the costs are probable and can be reasonably estimated.

    Air and Water Quality

    There has been and may be further  proposed  federal  legislation  requiring
    reductions in air  emissions for nitrogen  oxides,  sulfur  dioxide,  carbon
    dioxide and mercury.  Some of these proposals establish nation-wide caps and
    emission   rates   over  an   extended   period  of  time.   This   national
    multi-pollutant  approach to air pollution control could involve significant
    capital  costs  which  could  be  material  to  the  Company's  consolidated
    financial  position  or  results  of  operations.  Some  companies  may seek
    recovery of the related cost through rate adjustments or similar mechanisms.
    Control equipment that will be installed on North Carolina fossil generating
    facilities as part of the North  Carolina  legislation  discussed  below may
    address  some of the issues  outlined  above.  However,  the Company  cannot
    predict the outcome of this matter.

    The EPA is  conducting  an  enforcement  initiative  related  to a number of
    coal-fired   utility  power  plants  in  an  effort  to  determine   whether
    modifications  at  those  facilities  were  subject  to  New  Source  Review
    requirements  or New Source  Performance  Standards under the Clean Air Act.
    Both CP&L and Florida Power were asked to provide  information to the EPA as
    part  of  this   initiative   and  cooperated  in  providing  the  requested
    information.  The EPA  initiated  civil  enforcement  actions  against other
    unaffiliated  utilities as part of this  initiative.  Some of these  actions
    resulted in settlement  agreements  calling for  expenditures,  ranging from
    $1.0  billion to $1.4  billion.  A utility  that was not  subject to a civil
    enforcement  action  settled its New Source  Review  issues with the EPA for
    $300  million.   These  settlement  agreements  have  generally  called  for
    expenditures  to be  made  over  extended  time  periods,  and  some  of the
    companies may seek recovery of the related cost through rate  adjustments or
    similar mechanisms. The Company cannot predict the outcome of this matter.

    In 1998, the EPA published a final rule addressing the regional transport of
    ozone.  This  rule is  commonly  known as the NOx SIP Call.  The EPA's  rule
    requires 23  jurisdictions,  including  North  Carolina,  South Carolina and
    Georgia,  but not Florida,  to further reduce  nitrogen  oxide  emissions in

                                       120
<PAGE>

    order to attain a pre-set state NOx emission levels by May 31, 2004. CP&L is
    currently  installing  controls  necessary to comply with the rule.  Capital
    expenditures needed to meet these measures in North and South Carolina could
    reach approximately $370 million, which has not been adjusted for inflation.
    Increased  operation and maintenance  costs relating to the NOx SIP Call are
    not expected to be material to the Company's results of operations.  Further
    controls are anticipated as electricity demand increases. The Company cannot
    predict the outcome of this matter.

    In July 1997, the EPA issued final regulations establishing a new eight-hour
    ozone standard.  In October 1999, the District of Columbia  Circuit Court of
    Appeals  ruled against the EPA with regard to the federal  eight-hour  ozone
    standard.  The U.S.  Supreme  Court has  upheld,  in part,  the  District of
    Columbia Circuit Court of Appeals decision. Designation of areas that do not
    attain the standard is proceeding,  and further litigation and rulemaking on
    this and other  aspects of the  standard  are  anticipated.  North  Carolina
    adopted the federal  eight-hour  ozone  standard and is proceeding  with the
    implementation  process.  North Carolina has promulgated final  regulations,
    which will require CP&L to install nitrogen oxide controls under the state's
    eight-hour  standard.  The costs of those  controls are included in the $370
    million cost estimate set forth above.  However,  further technical analysis
    and rulemaking may result in a requirement  for additional  controls at some
    units. The Company cannot predict the outcome of this matter.

    The EPA published a final rule approving  petitions under Section 126 of the
    Clean Air Act. This rule as originally promulgated, required certain sources
    to make  reductions in nitrogen  oxide  emissions by May 1, 2003.  The final
    rule also includes a set of regulations that affect nitrogen oxide emissions
    from  sources  included  in the  petitions.  The North  Carolina  coal-fired
    electric generating plants are included in these petitions. Acceptable state
    plans  under the NOx SIP Call can be approved in lieu of the final rules the
    EPA approved as part of the Section 126 petitions.  CP&L,  other  utilities,
    trade organizations and other states participated in litigation  challenging
    the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of
    Appeals ruled in favor of the EPA, which will require North Carolina to make
    reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in
    its May 15th  decision,  rejected the EPA's  methodology  for estimating the
    future growth factors the EPA used in calculating  the emissions  limits for
    utilities.  In August  2001,  the Court  granted a request by CP&L and other
    utilities to delay the  implementation  of the Section 126 Rule for electric
    generating  units pending  resolution by the EPA of the growth factor issue.
    The Court's order tolls the three-year  compliance period (originally set to
    end on May 1, 2003) for electric  generating  units as of May 15,  2001.  On
    April 30, 2002, the EPA published a final rule harmonizing the dates for the
    Section 126 Rule and the NOx SIP Call.  In addition,  the EPA  determined in
    this  rule  that  the  future  growth  factor  estimation   methodology  was
    appropriate. The new compliance date for all affected sources is now May 31,
    2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP
    Call rule and has indicated it will rescind the Section 126 rule in a future
    rule making. The Company expects a favorable outcome of this matter.

    On June 20, 2002,  legislation  was enacted in North Carolina  requiring the
    state's  electric  utilities to reduce the  emissions of nitrogen  oxide and
    sulfur dioxide from  coal-fired  power plants.  Progress  Energy expects its
    capital  costs to meet these  emission  targets will be  approximately  $813
    million by 2013.  CP&L  currently has  approximately  5,100 MW of coal-fired
    generation  capacity in North Carolina that is affected by this legislation.
    The legislation  requires the emissions reductions to be completed in phases
    by 2013,  and applies to each  utility's  total  system  rather than setting
    requirements for individual  power plants.  The legislation also freezes the
    utilities' base rates for five years unless there are  extraordinary  events
    beyond the control of the  utilities  or unless the  utilities  persistently
    earn a return  substantially in excess of the rate of return established and
    found  reasonable  by the NCUC in the  utilities'  last  general  rate case.
    Further,  the legislation  allows the utilities to recover from their retail
    customers  the  projected  capital costs during the first seven years of the
    ten-year  compliance period beginning on January 1, 2003. The utilities must
    recover at least 70% of their  projected  capital costs during the five-year
    rate freeze period.  Pursuant to the new law, CP&L entered into an agreement
    with the  state of North  Carolina  to  transfer  to the  state  all  future
    emissions  allowances it generates from  over-complying with the new federal
    emission  limits when these units are  completed.  The new law also requires
    the state to  undertake a study of mercury and carbon  dioxide  emissions in
    North  Carolina.  Progress  Energy  cannot  predict  the  future  regulatory
    interpretation, implementation or impact of this new law.

    Certain historical waste sites exist that are being addressed voluntarily by
    PVI. An immaterial  accrual has been  established  to address  investigation
    expenses  related to these sites.  The Company  cannot  determine  the total
    costs that may be incurred in  connection  with these  sites.  According  to
    current  information,  these future costs are not expected to be material to
    the Company's financial condition or results of operations.

                                       121
<PAGE>

    Rail Services is voluntarily  addressing  certain historical waste sites. An
    immaterial  accrual has been  established to address  estimable  costs.  The
    Company cannot  determine the total costs that may be incurred in connection
    with these sites.  According to current information,  these future costs are
    not expected to be material to the Company's  financial condition or results
    of operations.

    Other Environmental Matters

    The Kyoto  Protocol  was  adopted in 1997 by the  United  Nations to address
    global  climate  change by reducing  emissions  of carbon  dioxide and other
    greenhouse  gases.  The United  States has not adopted  the Kyoto  Protocol,
    however,  a number of carbon dioxide  emissions  control proposals have been
    advanced in Congress and by the Bush administration. The Bush administration
    favors  voluntary  programs.  Reductions in carbon dioxide  emissions to the
    levels specified by the Kyoto Protocol and some legislative  proposals could
    be materially  adverse to Company  financials  and  operations if associated
    costs cannot be recovered from  customers.  The Company favors the voluntary
    program  approach  recommended  by the  administration,  and  is  evaluating
    options for the reduction, avoidance, and sequestration of greenhouse gases.
    However, the Company cannot predict the outcome of this matter.

    In 1997,  the EPA's  Mercury  Study  Report and  Utility  Report to Congress
    conveyed  that mercury is not a risk to the average  American and  expressed
    uncertainty  about whether  reductions in mercury  emissions from coal-fired
    power plants would reduce human exposure.  Nevertheless,  the EPA determined
    in 2000 that regulation of mercury  emissions from  coal-fired  power plants
    was appropriate. The EPA is currently developing a Maximum Available Control
    Technology  (MACT)  standard,  which is expected to become final in December
    2004, with compliance in 2008.  Achieving  compliance with the MACT standard
    could be materially  adverse to the  Company's  financials  and  operations.
    However, the Company cannot predict the outcome of this matter.

    2. CP&L,  like other  electric  power  companies in North  Carolina,  pays a
    franchise  tax  levied  by the  state  pursuant  to North  Carolina  General
    Statutes  Section  105-116,   a  state-level  annual  franchise  tax  (State
    Franchise Tax). Part of the revenue  generated by the State Franchise Tax is
    required by North  Carolina  General  Statutes  Section  105-116.1(b)  to be
    distributed  to North Carolina  cities in which CP&L  maintains  facilities.
    CP&L has paid and continues to pay the State Franchise Tax to the state when
    such  taxes are due.  However,  pursuant  to an  Executive  Order  issued on
    February  5, 2002,  by the  Governor of North  Carolina,  the  Secretary  of
    Revenue withheld distributions of State Franchise Tax revenues to cities for
    two  quarters of fiscal year  2001-2002  in an effort to balance the state's
    budget.

    In response to the state's  failure to  distribute  the State  Franchise Tax
    proceeds,   certain  cities  in  which  CP&L  maintains  facilities  adopted
    municipal  franchise  tax  ordinances  purporting  to impose on CP&L a local
    franchise  tax. The local taxes are intended to be collected  for as long as
    the state  withholds  distribution  of the State Franchise Tax proceeds from
    the cities. The first local tax payments were due August 15, 2002. On August
    2, 2002,  CP&L  filed a lawsuit  against  the  cities  seeking to enjoin the
    enforcement of the local taxes and to have the local ordinances  struck down
    because  the  ordinances  are beyond the  cities'  statutory  authority  and
    violate provisions of the North Carolina and United States Constitutions.

    On September  14, 2002,  the  Governor of North  Carolina  signed into law a
    provision  that prevents  cities and counties  from levying local  franchise
    taxes on electric  utilities.  This new  legislation  makes the lawsuit CP&L
    filed in August  against  certain  cities that were seeking to enforce local
    franchise  tax  ordinances  moot.  As a  result  of the  enactment  of  this
    legislation,  the parties  have agreed to an Order of  Dismissal by Consent,
    which has been  signed  by the  judge  and filed  with the Clerk of Court in
    Caswell County.

    3. As required under the Nuclear Waste Policy Act of 1982,  CP&L and Florida
    Power each entered  into a contract  with the DOE under which the DOE agreed
    to begin  taking spent  nuclear fuel by no later than January 31, 1998.  All
    similarly  situated  utilities  were  required  to sign  the  same  standard
    contract.

                                       122
<PAGE>

    In April 1995, the DOE issued a final interpretation that it did not have an
    unconditional  obligation to take spent nuclear fuel by January 31, 1998. In
    Indiana &  Michigan  Power v. DOE,  the Court of Appeals  vacated  the DOE's
    final interpretation and ruled that the DOE had an unconditional  obligation
    to begin  taking  spent  nuclear  fuel.  The Court did not  specify a remedy
    because the DOE was not yet in default.

    After the DOE failed to comply with the decision in Indiana & Michigan Power
    v. DOE, a group of  utilities  petitioned  the Court of Appeals in  Northern
    States  Power  (NSP) v. DOE,  seeking  an order  requiring  the DOE to begin
    taking spent  nuclear  fuel by January 31,  1998.  The DOE took the position
    that their delay was  unavoidable,  and the DOE was excused from performance
    under the terms and  conditions of the contract.  The Court of Appeals found
    that the  delay  was not  unavoidable,  but did not  order  the DOE to begin
    taking spent  nuclear  fuel,  stating that the  utilities  had a potentially
    adequate remedy by filing a claim for damages under the contract.

    After the DOE failed to begin taking spent nuclear fuel by January 31, 1998,
    a group of utilities filed a motion with the Court of Appeals to enforce the
    mandate in NSP v. DOE. Specifically, this group of utilities asked the Court
    to permit the utilities to escrow their waste fee payments, to order the DOE
    not to use the waste fund to pay damages to the utilities,  and to order the
    DOE to establish a schedule for disposal of spent  nuclear  fuel.  The Court
    denied  this motion  based  primarily  on the  grounds  that a review of the
    matter was premature,  and that some of the requested  remedies fell outside
    of the mandate in NSP v. DOE.

    Subsequently,  a number of utilities each filed an action for damages in the
    Federal Court of Claims.  In a recent  decision,  the U.S.  Circuit Court of
    Appeals  (Federal  Circuit) ruled that utilities may sue the DOE for damages
    in the Federal Court of Claims  instead of having to file an  administrative
    claim with the DOE.  CP&L and Florida Power are in the process of evaluating
    whether they should each file a similar action for damages.

    CP&L and Florida  Power also continue to monitor  legislation  that has been
    introduced  in Congress  which might provide some limited  relief.  CP&L and
    Florida Power cannot predict the outcome of this matter.

    With certain  modifications,  CP&L's spent  nuclear fuel storage  facilities
    will be  sufficient  to provide  storage  space for spent fuel  generated on
    CP&L's system through the expiration of the current  operating  licenses for
    all of CP&L's  nuclear  generating  units.  Subsequent to the  expiration of
    these licenses,  dry storage may be necessary.  CP&L obtained  approval from
    the U.S. Nuclear  Regulatory  Commission to use additional  storage space at
    the Harris Plant in December 2000.  Florida Power currently is storing spent
    nuclear  fuel  onsite in spent fuel  pools.  If Florida  Power does not seek
    renewal  of the CR3  operating  license,  CR3 will have  sufficient  storage
    capacity in place for fuel consumed through the end of the expiration of the
    license in 2016. If Florida Power  extends the CR3  operating  license,  dry
    storage may be necessary.

    4. The  Company and its  subsidiaries  are  involved  in various  litigation
    matters  in  the  ordinary  course  of  business,   some  of  which  involve
    substantial  amounts.   Where  appropriate,   accruals  have  been  made  in
    accordance with SFAS No. 5, "Accounting for  Contingencies,"  to provide for
    such matters. In the opinion of management, the final disposition of pending
    litigation  would  not  have a  material  adverse  effect  on the  Company's
    consolidated results of operations or financial position.

                                       123
<PAGE>
INDEPENDENT AUDITORS' REPORT


TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY:

     We have audited the accompanying  consolidated balance sheets and schedules
of capitalization of Carolina Power & Light Company and its subsidiaries  (CP&L)
as of December 31, 2002 and 2001,  and the related  consolidated  statements  of
income and comprehensive income,  retained earnings,  and cash flows for each of
the  three  years  in the  period  ended  December  31,  2002.  These  financial
statements are the responsibility of CP&L's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

     We conducted our audits in accordance  with  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

     In our opinion,  such consolidated  financial statements present fairly, in
all material  respects,  the financial position of CP&L at December 31, 2002 and
2001, and the results of its operations and its cash flows for each of the three
years in the period ended  December  31, 2002,  in  conformity  with  accounting
principles generally accepted in the United States of America.



/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003



                                       124
<PAGE>



CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


                                                                                Years ended December 31
(In thousands)                                                           2002              2001               2000
---------------------------------------------------------------------------------------------------------------------
Operating Revenues
   Electric                                                        $ 3,538,957       $ 3,343,720         $ 3,308,215
   Natural gas                                                               -                 -             147,448
   Diversified business                                                 14,863            16,441              72,783
---------------------------------------------------------------------------------------------------------------------
      Total Operating Revenues                                       3,553,820         3,360,161           3,528,446
---------------------------------------------------------------------------------------------------------------------
Operating Expenses
   Fuel used in electric generation                                    761,379           647,263             627,463
   Purchased power                                                     347,420           353,551             325,366
   Gas purchased for resale                                                  -                 -             103,734
   Operation and maintenance                                           792,660           701,703             741,466
   Depreciation and amortization                                       523,846           521,910             708,249
   Taxes other than on income                                          157,568           149,719             148,037
   Diversified business                                                115,733             9,985             135,258
---------------------------------------------------------------------------------------------------------------------
        Total Operating Expenses                                     2,698,606         2,384,131           2,789,573
---------------------------------------------------------------------------------------------------------------------
Operating Income                                                       855,214           976,030             738,873
---------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                       6,868            13,728              17,420
   Gain on sale of investment                                                -                 -             200,000
   Impairment of investment                                           (25,011)         (156,712)                   -
   Other, net                                                           12,757           (4,155)              17,089
---------------------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                                    (5,386)         (147,139)             234,509
---------------------------------------------------------------------------------------------------------------------
Interest Charges
   Interest charges                                                    217,010           257,141             240,620
   Allowance for borrowed funds used during construction                (5,474)          (15,714)            (18,537)
---------------------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                    211,536           241,427             222,083
---------------------------------------------------------------------------------------------------------------------
Income before Income Taxes                                             638,292           587,464             751,299
Income Tax Expense                                                     207,360           223,233             290,271
---------------------------------------------------------------------------------------------------------------------
Net Income                                                             430,932           364,231             461,028
Preferred Stock Dividend Requirement                                     2,964             2,964               2,966
---------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                                            $ 427,968         $ 361,267           $ 458,062
---------------------------------------------------------------------------------------------------------------------

Comprehensive Income, Net of Tax:
   Net Income                                                        $ 430,932         $ 364,231           $ 461,028
   SFAS No. 133 transition adjustment (net of tax of $474)                   -             (738)                   -
   Change in net unrealized losses on cash flow hedges (net of
       tax of $9,080 and $7,565, respectively)                         (14,144)          (11,784)                  -
   Reclassification adjustment for amounts included in net
       income (net of tax of $7,583 and $3,515, respectively)           11,811             5,476                   -
   Minimum pension liability adjustment (net of tax of $47,317)        (73,390)                -                   -
---------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                 $ 355,209         $ 357,185           $ 461,028
---------------------------------------------------------------------------------------------------------------------

</TABLE>

See Carolina Power & Light Company Notes to Consolidated Financial Statements.



                                       125

<PAGE>

CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


(In thousands)                                                                             December 31
Assets                                                                           2002                       2001
--------------------------------------------------------------------------------------------------------------------
Utility Plant
  Utility plant in service                                                 $ 12,675,761                $ 12,024,291
  Accumulated depreciation                                                   (6,356,933)                 (5,952,206)
--------------------------------------------------------------------------------------------------------------------
        Utility plant in service, net                                         6,318,828                   6,072,085
  Held for future use                                                             7,188                       7,105
  Construction work in progress                                                 325,695                     711,129
  Nuclear fuel, net of amortization                                             176,622                     200,332
--------------------------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                              6,828,333                   6,990,651
--------------------------------------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                                      18,284                      21,250
  Accounts receivable                                                           301,178                     302,781
  Unbilled accounts receivable                                                  151,352                     136,514
  Receivables from affiliated companies                                          36,870                      26,182
  Notes receivable from affiliated companies                                     49,772                         998
  Taxes receivable                                                                5,890                      17,543
  Inventory                                                                     342,886                     372,725
  Deferred fuel cost                                                            146,015                     131,505
  Prepayments and other current assets                                           94,658                      78,056
--------------------------------------------------------------------------------------------------------------------
        Total Current Assets                                                  1,146,905                   1,087,554
--------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                                             252,083                     277,550
  Nuclear decommissioning trust funds                                           423,293                     416,721
  Diversified business property, net                                              9,435                     111,802
  Miscellaneous other property and investments                                  209,657                     224,101
  Other assets and deferred debits                                              104,978                     150,306
--------------------------------------------------------------------------------------------------------------------

        Total Deferred Debits and Other Assets                                  999,446                   1,180,480
--------------------------------------------------------------------------------------------------------------------

           Total Assets                                                    $  8,974,684                $  9,258,685
--------------------------------------------------------------------------------------------------------------------

Capitalization and Liabilities
--------------------------------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of capitalization)
--------------------------------------------------------------------------------------------------------------------
  Common stock                                                             $  3,089,115                $  3,095,456
  Preferred stock - not subject to mandatory redemption                          59,334                      59,334
  Long-term debt, net                                                         3,048,466                   2,698,318
--------------------------------------------------------------------------------------------------------------------
        Total Capitalization                                                  6,196,915                   5,853,108
--------------------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                                   -                     600,000
  Accounts payable                                                              259,217                     300,829
  Payables to affiliated companies                                               98,572                     106,114
  Notes payable to affiliated companies                                               -                      47,913
  Interest accrued                                                               58,791                      61,124
  Short-term obligations                                                        437,750                     260,535
  Current portion of accumulated deferred income taxes                           66,088                      67,975
  Other current liabilities                                                      93,171                     140,670
--------------------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                             1,013,589                   1,585,160
--------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                                           1,179,689                   1,316,823
  Accumulated deferred investment tax credits                                   158,308                     170,302
  Regulatory liabilities                                                          7,774                       7,494
  Other liabilities and deferred credits                                        418,409                     325,798
--------------------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                          1,764,180                   1,820,417
--------------------------------------------------------------------------------------------------------------------

Commitments and Contingencies (Note 18)
--------------------------------------------------------------------------------------------------------------------
            Total Capitalization and Liabilities                           $  8,974,684                $  9,258,685
--------------------------------------------------------------------------------------------------------------------
</TABLE>


See Carolina Power & Light Company Notes to Consolidated Financial Statements.


                                       126
<PAGE>

CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of CASH FLOWS
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                           Years ended December 31
(In thousands)                                                                         2002           2001            2000
---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                            $ 430,932      $ 364,231         $ 461,028
Adjustments to reconcile net income to net cash provided by operating activities:
      Impairment of long-lived assets and investments                                   126,262        156,712                 -
      Depreciation and amortization                                                     631,401        616,206           803,211
      Deferred income taxes                                                             (81,916)      (149,895)          (83,554)
      Investment tax credit                                                             (11,994)       (14,928)           (4,511)
      Gain on sale of assets                                                                  -              -          (200,000)
      Deferred fuel credit                                                              (14,510)       (11,652)          (40,763)
      Net (increase) decrease in accounts receivable                                    222,293        304,106          (185,640)
      Net (increase) decrease in inventories                                              9,998       (139,854)           (3,699)
      Net (increase) decrease in prepayments and other current assets                  (14,953)         21,679            87,575
      Net increase (decrease) in accounts payable                                        20,490       (261,606)          314,267
      Net increase (decrease) in other current liabilities                               (2,332)        52,704           146,802
      Other                                                                              51,801         47,140            26,019
---------------------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                    1,367,472        984,843         1,320,735
---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions                                                               (624,202)      (823,952)         (821,991)
Nuclear fuel additions                                                                  (80,515)       (72,576)          (59,752)
Proceeds from sale of assets                                                                  -              -           200,000
Contributions to nuclear decommissioning trust                                          (30,708)       (30,678)          (30,727)
Diversified business property additions                                                 (11,836)       (13,500)          (56,489)
Investments in non-utility activities                                                   (17,053)       (32,674)         (111,516)
---------------------------------------------------------------------------------------------------------------------------------
          Net Cash Used in Investing Activities                                        (764,314)      (973,380)         (880,475)
---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt                                                542,290        296,124           783,052
Net increase (decrease) in short-term obligations                                       177,215       (225,762)          123,697
Net increase (decrease) in intercompany notes                                           (96,687)       187,560          (275,628)
Retirement of long-term debt                                                           (806,809)      (134,611)         (695,163)
Equity contribution from parent                                                               -        115,000                 -
Dividends paid to parent                                                               (396,680)      (255,630)                -
Dividends paid on preferred stock                                                        (2,964)        (2,964)           (2,966)
Dividends paid on common stock                                                                -              -          (432,325)
Other                                                                                   (22,489)             -            21,027
---------------------------------------------------------------------------------------------------------------------------------
           Net Cash Used in Financing Activities                                       (606,124)       (20,283)         (478,306)
---------------------------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents                                                (2,966)        (8,820)          (38,046)
---------------------------------------------------------------------------------------------------------------------------------
Decrease in Cash from Stock Distribution (See Note 1A)                                        -              -           (11,755)
Cash and Cash Equivalents at Beginning of Year                                           21,250         30,070            79,871
---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                               $ 18,284       $ 21,250          $ 30,070
---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                       $208,283       $230,828          $205,250
                            income taxes (net of refunds)                              $319,973       $395,433          $434,908
</TABLE>

Noncash Investing and Financing Activities
o    On June 28,  2000,  Caronet,  Inc.,  a  wholly  owned  subsidiary  of CP&L,
     contributed  net assets in the amount of $93 million in exchange  for a 35%
     ownership interest (15% voting interest) in a newly formed company.
o    On July 1, 2000, CP&L  distributed  its ownership  interest in the stock of
     North Carolina Natural Gas Corporation, Strategic Resource Solutions Corp.,
     Monroe Power Company and Progress Ventures,  Inc. to Progress Energy,  Inc.
     This  resulted in a noncash  dividend to its parent of  approximately  $556
     million (See Note 1A).
o    In  January  2001,  CP&L  transferred  certain  assets,  through  a noncash
     dividend to parent in the amount of $19 million, to Progress Energy Service
     Company, LLC.
o    In February 2002, CP&L  transferred  the Rowan plant to Progress  Ventures,
     Inc. The property and  inventory  transferred  totaled  approximately  $245
     million.

See Carolina Power & Light Company Notes to Consolidated Financial Statements.

                                       127
<PAGE>

CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES of CAPITALIZATION
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


                                                                                           December 31
 (In thousands except share data)                                                     2002             2001
 -------------------------------------------------------------------------------------------------------------
 Common Stock Equity
 Common stock without par value, authorized 200,000,000 shares,
      159,608,055 shares issued and outstanding at December 31                   $ 1,929,515      $ 1,904,246
 Unearned ESOP common stock                                                         (101,560)        (114,385)
 Accumulated other comprehensive loss                                                (82,769)          (7,046)
 Retained earnings                                                                 1,343,929        1,312,641
 -------------------------------------------------------------------------------------------------------------
         Total Common Stock Equity                                               $ 3,089,115      $ 3,095,456
 -------------------------------------------------------------------------------------------------------------
 Preferred Stock - not subject to mandatory redemption
 Authorized - 300,000 shares, cumulative, $100 par value Preferred
       Stock; 20,000,000 shares, cumulative, $100 par value Serial
       Preferred Stock
           $5.00 Preferred - 236,997 shares (redemption price $110.00)              $ 24,349         $ 24,349
           $4.20 Serial Preferred - 100,000 shares outstanding
               redemption price $102.00)                                              10,000           10,000
           $5.44 Serial Preferred -249,850 shares (redemption price
               $101.00)                                                               24,985           24,985
 -------------------------------------------------------------------------------------------------------------
        Total Preferred Stock                                                       $ 59,334         $ 59,334
 -------------------------------------------------------------------------------------------------------------
 Long-Term Debt (maturities and weighted-average interest rates as
      of December 31, 2002)
 First mortgage bonds, maturing 2004-2023                              6.92%     $ 1,550,000      $ 1,800,000
 Pollution control obligations, maturing 2010-2024                     1.86%         707,800          707,800
 Unsecured notes, maturing 2012                                        6.50%         500,000                -
 Extendible notes, maturing 2002                                           -               -          500,000
 Medium-term notes, maturing 2008                                      6.65%         300,000          300,000
 Miscellaneous notes                                                   6.44%           6,910            7,234
 Unamortized premium and discount, net                                               (16,244)         (16,716)
 Current portion of long-term debt                                                         -         (600,000)
 -------------------------------------------------------------------------------------------------------------
      Total Long-Term Debt, Net                                                    3,048,466        2,698,318
 -------------------------------------------------------------------------------------------------------------
         Total Capitalization                                                    $ 6,196,915      $ 5,853,108
 -------------------------------------------------------------------------------------------------------------

CONSOLIDATED STATEMENTS of RETAINED EARNINGS


Years ended December 31
(In thousands)                                                        2002              2001              2000
--------------------------------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year                           $ 1,312,641     $ 1,226,144      $ 1,807,345
Net income                                                           430,932         364,231          461,028
Preferred stock dividends at stated rates                             (2,964)         (2,964)          (2,966)
Common stock dividends                                              (396,680)       (274,770)      (1,039,263)
--------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year                                 $ 1,343,929     $ 1,312,641     $  1,226,144
--------------------------------------------------------------------------------------------------------------

CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

(In thousands)                               First Quarter    Second Quarter     Third Quarter     Fourth Quarter
-----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues                                 $ 814,871         $ 838,092      $ 1,049,484          $ 851,373
Operating income                                     193,185           210,022          240,051            211,956
Net income                                            85,119           131,152           94,139            120,522
-----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues                                 $ 826,603         $ 783,379        $ 976,891          $ 773,288
Operating income                                     231,641           184,390          322,477            237,522
Net income (loss)                                    120,845            84,879          167,874             (9,367)

</TABLE>

o    In the opinion of management,  all adjustments  necessary to fairly present
     amounts shown for interim periods have been made. Results of operations for
     an interim period may not give a true indication of results for the year.
o    Fourth  quarter  2001  includes  impairment  and other  charges  related to
     Interpath  Communications,  Inc. of $156.7 million ($107.2  million,  after
     tax) (See Note 5).
o    Third  quarter  2002  includes  impairment  and other  charges  related  to
     Caronet, Inc. and Interpath  Communications,  Inc. of $133.3 million ($87.4
     million, after tax) (See Note 5).

See Carolina Power & Light Company Notes to Consolidated Financial Statements.

                                       128
<PAGE>

CAROLINA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Organization and Summary of Significant Accounting Policies

    A.  Organization

    Carolina  Power & Light  Company  (CP&L)  is a  public  service  corporation
    primarily engaged in the generation, transmission,  distribution and sale of
    electricity  in portions of North Carolina and South  Carolina.  Through its
    wholly owned subsidiaries, CP&L is involved in several nonregulated business
    activities,   the  most  significant  of  which  is  its  telecommunications
    operation.  CP&L is a wholly owned subsidiary of Progress Energy,  Inc. (the
    Company  or  Progress  Energy),   which  was  formed  as  a  result  of  the
    reorganization  of CP&L into a holding  company  structure on June 19, 2000.
    All shares of common  stock of CP&L were  exchanged  for an equal  number of
    shares of CP&L  Energy,  Inc. On December 4, 2000,  the Company  changed its
    name from CP&L  Energy,  Inc.  to  Progress  Energy,  Inc.  The Company is a
    registered  holding  company under the Public Utility Holding Company Act of
    1935  (PUHCA).  Both the  Company  and its  subsidiaries  are subject to the
    regulatory provisions of PUHCA.

    On July 1, 2000,  CP&L  distributed  its ownership  interest in the stock of
    North Carolina Natural Gas Corporation (NCNG),  Strategic Resource Solutions
    Corp. (SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc.
    (PVI) to the Company.  As a result,  those companies are direct subsidiaries
    of Progress  Energy and are not included in CP&L's results of operations and
    financial position subsequent to July 1, 2000.

    Effective  January 1, 2003, CP&L began doing business under the assumed name
    Progress Energy Carolinas,  Inc. The legal name has not changed and there is
    no  restructuring  of any kind  related  to the  name  change.  The  current
    corporate and business unit structure remains unchanged.

    B.  Basis of Presentation

    The  consolidated  financial  statements  are  prepared in  accordance  with
    accounting  principles  generally  accepted in the United  States of America
    (GAAP)  and  include  the   activities   of  CP&L  and  its   majority-owned
    subsidiaries.  Significant  intercompany balances and transactions have been
    eliminated  in  consolidation  except as permitted by Statement of Financial
    Accounting  Standards (SFAS) No. 71,  "Accounting for the Effects of Certain
    Types of Regulation,"  which provides that profits on intercompany  sales to
    regulated affiliates are not eliminated if the sales price is reasonable and
    the future  recovery of the sales price  through the  ratemaking  process is
    probable.

    The accounting  records are maintained in accordance with uniform systems of
    accounts prescribed by the Federal Energy Regulatory  Commission (FERC), the
    North Carolina Utilities Commission (NCUC) and the Public Service Commission
    of South Carolina (SCPSC).

    Unconsolidated  investments  in  companies  over  which  CP&L  does not have
    control,  but has the  ability to  exercise  influence  over  operating  and
    financial policies (generally,  20% - 50% voting interest) are accounted for
    under  the  equity  method  of  accounting.  Other  investments  are  stated
    principally  at  cost.  These  equity  and  cost  investments,  which  total
    approximately  $95.0  million and $114.3  million at  December  31, 2002 and
    2001,  respectively,  are included as miscellaneous property and investments
    in the Consolidated Balance Sheets. The primary component of this balance is
    CP&L's  investments in affordable housing of $63.4 million and $54.3 million
    as of December 31, 2002 and 2001, respectively. Included in the December 31,
    2001 investment  balance is CP&L's  investment in Interpath  Communications,
    Inc. of $27.0 million (See Note 5).

    Certain  amounts for 2001 and 2000 have been  reclassified to conform to the
    2002 presentation.

    C.  Use of Estimates and Assumptions

    In  preparing  consolidated  financial  statements  that  conform with GAAP,
    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 consolidated financial statements and amounts
    of revenues and  expenses  reflected  during the  reporting  period.  Actual
    results could differ from those estimates.

                                       129
<PAGE>

    D.  Utility Plant

    Utility  plant in  service  is stated at  historical  cost less  accumulated
    depreciation.  CP&L  capitalizes all  construction-related  direct labor and
    material costs of units of property as well as indirect  construction costs.
    The costs of renewals and betterments are also capitalized.  Maintenance and
    repairs of property, and replacements and renewals of items determined to be
    less than units of property, are charged to maintenance expense as incurred.
    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 pledged as
    collateral for the first mortgage bonds of CP&L (See Note 6).

    The balances of utility plant in service at December 31 are listed below (in
    thousands), with a range of depreciable lives for each:

                                                      2002           2001
                                                 ------------   ------------

    Production plant  (7-33 years)                $ 7,629,539    $ 7,301,225
    Transmission plant  (30-75 years)               1,128,097      1,092,024
    Distribution plant  (12-50 years)               3,344,662      3,063,753
    General plant and other (8-75 years)              573,463        567,289
                                                 ------------   ------------
    Utility plant in service                     $ 12,675,761   $ 12,024,291
                                                 ============   ============

    Allowance  for  funds  used  during  construction   (AFUDC)  represents  the
    estimated  debt and equity costs of capital  funds  necessary to finance the
    construction  of new  regulated  assets.  As  prescribed  in the  regulatory
    uniform systems of accounts,  AFUDC is charged to the cost of the plant. The
    equity  funds  portion of AFUDC is credited to other income and the borrowed
    funds  portion is  credited  to  interest  charges.  Regulatory  authorities
    consider AFUDC an  appropriate  charge for inclusion in the rates charged to
    customers by the utilities over the service life of the property.  The total
    equity  funds  portion of AFUDC was $6.4  million,  $8.8  million  and $14.5
    million in 2002, 2001 and 2000,  respectively.  The composite AFUDC rate for
    CP&L's  electric  utility  plant  was 6.2% in both 2002 and 2001 and 8.2% in
    2000.

    E.  Depreciation and Amortization - Utility Plant

    For financial reporting purposes,  substantially all depreciation of utility
    plant other than nuclear fuel is computed on the straight-line  method based
    on the  estimated  remaining  useful  life  of the  property,  adjusted  for
    estimated net salvage.  Depreciation provisions,  including  decommissioning
    costs  (See Note 1G) and  excluding  accelerated  cost  recovery  of nuclear
    generating assets, as a percent of average  depreciable  property other than
    nuclear fuel, were approximately  3.8% in 2002, 2001 and 2000.  Depreciation
    and decommissioning provisions, including accelerated cost recovery, totaled
    $504.5  million,  $504.9 million and $688.8 million in 2002,  2001 and 2000,
    respectively.

    With  approval  from the  NCUC  and the  SCPSC,  CP&L  accelerated  the cost
    recovery of its nuclear  generating assets beginning January 1, 2000. During
    2002,  the NCUC and the  SCPSC  approved  modifications  to  CP&L's  ongoing
    accelerated  cost  recovery  of  its  nuclear  generating  assets  including
    extension  of  the  recovery  period.  Cumulative  accelerated  depreciation
    ranging  from $530  million to $750 million will be recorded by December 31,
    2009. The  accelerated  cost recovery of these assets resulted in additional
    depreciation  expense of  approximately  $53  million,  $75 million and $275
    million in 2002, 2001 and 2000, respectively. Total accelerated depreciation
    recorded  through  December 31, 2002 was $326 million for the North Carolina
    jurisdiction and $77 million for the South Carolina  jurisdiction  (See Note
    9B).

    Amortization of nuclear fuel costs, including disposal costs associated with
    obligations to the U.S. Department of Energy (DOE), is computed primarily on
    the units-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.  The total of these
    costs for the years  ended  December  31,  2002,  2001 and 2000 were  $109.1
    million, $101.0 million and $112.1 million, respectively.

                                       130
<PAGE>

    F.   Diversified Business Property

    Diversified   business   property   is  stated  at  cost  less   accumulated
    depreciation.  If CP&L recognizes an impairment of an asset,  the fair value
    becomes  its new cost  basis.  The costs of  renewals  and  betterments  are
    capitalized.  The cost of repairs and  maintenance  is charged to expense as
    incurred. Depreciation is computed on a straight-line basis.

    The following is a summary of diversified  business  property (in thousands)
    as of December 31, with ranges of depreciable lives:

                                                     2002          2001
                                                  ----------    ----------

    Telecommunications equipment (5 - 20 years)     $ 1,687      $ 94,164
    Other equipment (3 - 10 years)                    8,363        11,657
    Construction work in progress                       497        21,622
    Accumulated depreciation                        (1,112)      (15,641)
                                                  ----------    ----------

    Diversified business property, net              $ 9,435     $ 111,802
                                                  ==========    ==========

    The decrease  from 2001 to 2002 is  attributable  to an impairment of assets
    discussed  in Note 5.  Diversified  business  depreciation  expense was $3.6
    million, $6.4 million and $3.2 million in 2002, 2001 and 2000, respectively.

    G. Decommissioning and Dismantlement Provisions

    In CP&L'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  jurisdictions,  the provisions for
    nuclear  decommissioning  costs are approved by FERC.  Decommissioning  cost
    provisions,  which are included in depreciation  and  amortization  expense,
    were $30.7 million in 2002, 2001 and 2000.

    Accumulated   decommissioning  costs,  which  are  included  in  accumulated
    depreciation,  were $611.3  million and $604.8  million at December 31, 2002
    and 2001, respectively.  These costs include amounts retained internally and
    amounts funded in externally managed  decommissioning trusts. Trust earnings
    increase the trust balance with a corresponding  increase in the accumulated
    decommissioning  balance.  These  balances are  adjusted for net  unrealized
    gains and losses related to changes in the fair value of trust assets.

    CP&L's most recent  site-specific  estimates of  decommissioning  costs were
    developed  in 1998,  using  1998  cost  factors,  and are  based  on  prompt
    dismantlement  decommissioning,  which  reflects  the cost of removal of all
    radioactive  and other  structures  currently at the site, with such removal
    occurring shortly after operating license  expiration.  These estimates,  in
    1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million for
    Brunswick  Unit No. 1, $298.7  million for  Brunswick  Unit No. 2 and $328.1
    million for the Harris Plant. The estimates are subject to change based on a
    variety of factors including,  but not limited to, cost escalation,  changes
    in technology applicable to nuclear  decommissioning and changes in federal,
    state  or  local  regulations.   The  cost  estimates  exclude  the  portion
    attributable  to  North  Carolina  Eastern  Municipal  Power  Agency  (Power
    Agency),  which holds an undivided  ownership  interest in the Brunswick and
    Harris nuclear generating facilities.  Operating licenses for CP&L's nuclear
    units expire in the years 2010 for Robinson  Unit No. 2, 2016 for  Brunswick
    Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant.  An
    application  to extend the Robinson  license 20 years was  submitted in 2002
    and a similar  application  will be made for Brunswick in December  2004. An
    extension will also be sought for the Harris Plant, tentatively in 2009.

    Management believes that the  decommissioning  costs that have been and will
    be recovered  through  rates will be  sufficient to provide for the costs of
    decommissioning.

    The  Financial  Accounting  Standards  Board (FASB) has issued SFAS No. 143,
    "Accounting  for  Asset  Retirement   Obligations,"  that  will  impact  the
    accounting for decommissioning and dismantlement provisions (See Note 1P).

                                       131
<PAGE>

    H. Excise Taxes

    CP&L, as an agent for a state or local  government,  collects from customers
    certain  excise  taxes  levied  by the  state or local  government  upon the
    customer.  CP&L accounts for excise taxes on a gross basis. Excise taxes are
    included in CP&L's base rates.  For the years ended December 31, 2002,  2001
    and 2000, gross receipts tax and other excise taxes of  approximately  $79.3
    million,  $76.8  million and $75.1  million,  respectively,  are included in
    taxes  other  than on income on the  Consolidated  Statements  of Income and
    Comprehensive  Income.  These  approximate  amounts  are  also  included  in
    electric operating revenues.

    I. Inventory

    CP&L accounts for inventory using the  average-cost  method.  As of December
    31, inventory was comprised of (in thousands):

                                      2002           2001
                                   ----------     ----------

    Fuel                           $ 117,946      $ 137,236
    Materials and supplies           224,940        235,489
                                   ----------     ----------
    Total inventory                $ 342,886      $ 372,725
                                   ==========     ==========

    J. Other Policies

    CP&L  recognizes   electric  utility  revenue  as  service  is  rendered  to
    customers.  Operating  revenues include  unbilled  electric utility revenues
    earned  when  service  has been  delivered  but not billed by the end of the
    accounting  period.  Revenues related to design and construction of wireless
    infrastructure are recognized upon completion of services for each completed
    phase of design and construction.

    Fuel expense  includes  fuel costs or recoveries  that are deferred  through
    fuel clauses  established by CP&L's regulators.  These clauses allow CP&L to
    recover fuel costs and portions of purchased power costs through  surcharges
    on customer rates.

    CP&L maintains an allowance for doubtful accounts receivable,  which totaled
    approximately $11.3 million and $12.2 million at December 31, 2002 and 2001,
    respectively.

    Long-term debt premiums,  discounts and issuance  expenses for the utilities
    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  by the utilities are amortized over the remaining life of
    the original debt using the straight-line  method consistent with ratemaking
    treatment.

    CP&L  considers all highly liquid  investments  with original  maturities of
    three months or less to be cash equivalents.

    CP&L  participates  in a money pool  arrangement  with other Progress Energy
    subsidiaries to better manage cash and working capital  requirements.  Under
    this  arrangement,   subsidiaries  with  surplus  short-term  funds  provide
    short-term loans to participating affiliates (See Note 4).

    The Company follows the guidance in SFAS No. 87, "Employers'  Accounting for
    Pensions," to account for its defined benefit  retirement plans. In addition
    to pension  benefits,  the Company  provides other  postretirement  benefits
    which are  accounted  for under SFAS No.  106,  "Employers'  Accounting  for
    Postretirement  Benefits  Other  Than  Pensions."  See  Note 13 for  related
    disclosures for these plans.

    K. Impairment of Long-Lived Assets and Investments

    CP&L reviews the recoverability of long-lived and intangible assets whenever
    indicators  exist.  Examples  of these  indicators  include  current  period
    losses,  combined  with a history of losses or a  projection  of  continuing
    losses, or a significant  decrease in the market price of a long-lived asset
    group.  If  an  indicator  exists,  then  the  asset  group  is  tested  for
    recoverability  by comparing the carrying  value to the sum of  undiscounted
    expected future cash flows directly  attributable to the asset group. If the
    asset group is not  recoverable  through  undiscounted  cash flows,  then an
    impairment loss is recognized for the difference  between the carrying value
    and the fair value of the asset group.  The  accounting  for  impairment  of
    assets is based on SFAS No. 144,  "Accounting for the Impairment or Disposal
    of Long-Lived  Assets," which was adopted by CP&L effective January 1, 2002.
    Prior to the adoption of this standard, impairments were accounted for under

                                       132
<PAGE>

    SFAS No. 121,  "Accounting  for the Impairment of Long-Lived  Assets and for
    Long-Lived  Assets to be Disposed Of," which was superceded by SFAS No. 144.
    See Note 5 for  discussion of impairment  evaluations  performed and charges
    taken.

    L. Income Taxes

    Progress  Energy and its affiliates  file a consolidated  federal income tax
    return. The consolidated  income tax of Progress Energy is allocated to CP&L
    in accordance with the Inter-company  Income Tax Allocation  Agreement.  The
    agreement  provides an  allocation  that  recognizes  positive  and negative
    corporate taxable income.  The agreement provides for an equitable method of
    apportioning the carry over of uncompensated  tax benefits.  Progress Energy
    Holding Company tax benefits not related to acquisition interest expense are
    allocated to profitable subsidiaries,  beginning in 2002, in accordance with
    a PUHCA order. Income taxes are provided as if CP&L filed a separate return.

    Deferred  income taxes have been provided for temporary  differences.  These
    occur when there are differences  between the book and tax carrying  amounts
    of assets and  liabilities.  Investment  tax  credits  related to  regulated
    operations  have been  deferred and are being  amortized  over the estimated
    service life of the related properties (See Note 14).

    M. Derivatives

    Effective  January 1, 2001,  CP&L  adopted  SFAS No.  133,  "Accounting  for
    Derivative  Instruments and Hedging Activities," as amended by SFAS No. 138.
    SFAS No. 133, as amended, establishes accounting and reporting standards for
    derivative instruments, including certain derivative instruments embedded in
    other contracts,  and for hedging activities.  SFAS No. 133 requires that an
    entity  recognize all  derivatives  as assets or  liabilities in the balance
    sheet  and  measure  those  instruments  at  fair  value.  See  Note  10 for
    information    regarding   risk   management   activities   and   derivative
    transactions.

    In connection  with the January 2003 FASB Emerging  Issues Task Force (EITF)
    meeting,  the FASB was requested to reconsider an interpretation of SFAS No.
    133.   The   interpretation,   which  is   contained   in  the   Derivatives
    Implementation  Group's C11  guidance,  relates to the pricing of  contracts
    that include broad market indices.  In particular,  that guidance  discusses
    whether the pricing in a contract that contains  broad market indices (e.g.,
    CPI) could qualify as a normal purchase or sale (the normal purchase or sale
    term is a defined  accounting  term,  and may not,  in all  cases,  indicate
    whether the contract would be "normal" from an operating entity  viewpoint).
    CP&L is currently reevaluating which contracts, if any, that have previously
    been designated as normal  purchases or sales would now not qualify for this
    exception.  CP&L is currently evaluating the effects that this guidance will
    have on its results of operation and financial position.

    N. Environmental

    The Company accrues environmental  remediation liabilities when the criteria
    for SFAS No. 5, "Accounting for Contingencies," has been met.  Environmental
    expenditures  are  expensed as incurred or  capitalized  depending  on their
    future economic benefit.  Expenditures that relate to an existing  condition
    caused by past  operations  and that have no future  economic  benefits  are
    expensed.  Accruals  for  estimated  losses from  environmental  remediation
    obligations  generally  are  recognized  no  later  than  completion  of the
    remedial  feasibility  study.  Such  accruals  are  adjusted  as  additional
    information  develops or circumstances  change. Costs of future expenditures
    for  environmental  remediation  obligations  are not  discounted  to  their
    present  value.  Recoveries of  environmental  remediation  costs from other
    parties are recognized when their receipt is deemed probable (See Note 18D).

    O. Cost-Based Regulation

    CP&L's regulated  operations are subject to SFAS No. 71, "Accounting for the
    Effects  of Certain  Types of  Regulation."  SFAS No. 71 allows a  regulated
    company to record  costs that have been or are expected to be allowed in the
    ratemaking  process in a period different from the period in which the costs
    would be charged to expense by a nonregulated enterprise.  Accordingly, CP&L
    records  assets and  liabilities  that result from the regulated  ratemaking
    process  that would not be recorded  under GAAP for  nonregulated  entities.
    These  regulatory  assets and liabilities  represent  expenses  deferred for
    future  recovery from  customers or  obligations to be refunded to customers
    and are primarily classified in the accompanying Consolidated Balance Sheets
    as regulatory assets and regulatory liabilities (See Note 9A).

                                       133
<PAGE>

    P. Impact of New Accounting Standards

    SFAS No. 143, "Accounting for Asset Retirement Obligations"
    The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
    in July 2001. This statement provides accounting and disclosure requirements
    for  retirement   obligations  associated  with  long-lived  assets  and  is
    effective January 1, 2003. This statement requires that the present value of
    retirement  costs for  which  CP&L has a legal  obligation  be  recorded  as
    liabilities  with  an  equivalent   amount  added  to  the  asset  cost  and
    depreciated over an appropriate  period. The liability is then accreted over
    time  by  applying  an  interest  method  of  allocation  to the  liability.
    Cumulative accretion and accumulated depreciation will be recognized for the
    time period from the date the liability  would have been  recognized had the
    provisions of this statement been in effect, to the date of adoption of this
    Statement.   The  cumulative   effect  of  implementing  this  Statement  is
    recognized  as a  change  in  accounting  principle.  The  adoption  of this
    statement  will have no impact on CP&L's  net  income,  as the  effects  are
    expected  to be  offset  by  the  establishment  of  regulatory  assets  and
    liabilities pursuant to SFAS No. 71.

    CP&L's  review   identified   legal   retirement   obligations  for  nuclear
    decommissioning of radiated plant. CP&L will record liabilities  pursuant to
    SFAS No. 143 beginning in 2003.  CP&L used an expected cash flow approach to
    measure the obligations. The proforma amounts for nuclear decommissioning of
    radiated  plant as if SFAS No. 143 had been  applied  during all periods are
    $879.7   million  and  $830.5   million  at  December  31,  2002  and  2001,
    respectively.

    Nuclear   decommissioning  has  previously-recorded   liabilities.   Amounts
    recorded for nuclear  decommissioning  of radiated plant were $491.3 million
    and $460.9 million at December 31, 2002 and 2001, respectively.

    Proforma net income has not been  presented for the years ended December 31,
    2002,  2001 and 2000  because the  proforma  application  of SFAS No. 143 to
    prior periods would result in proforma net income not  materially  different
    from the actual  amounts  reported  for those  periods  in the  accompanying
    Consolidated Statements of Income and Comprehensive Income.

    CP&L has identified but not recognized  asset  retirement  obligation  (ARO)
    liabilities   related  to  electric   transmission   and   distribution  and
    telecommunications assets as the result of easements over property not owned
    by CP&L. These easements are generally perpetual and only require retirement
    action  upon  abandonment  or  cessation  of  use of the  property  for  the
    specified purpose.  The ARO liability is not estimable for such easements as
    CP&L intends to utilize  these  properties  indefinitely.  In the event CP&L
    decides  to  abandon  or  cease  the use of a  particular  easement,  an ARO
    liability would be recorded at that time.

    CP&L has previously  recognized removal costs as a component of depreciation
    in accordance with regulatory treatment.  To the extent these amounts do not
    represent SFAS No. 143 legal retirement obligations,  they will be disclosed
    as regulatory liabilities upon adoption of the standard.

    SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
    FASB  Statement No. 13, and Technical  Corrections"  In April 2002, the FASB
    issued  SFAS No.  145,  "Rescission  of FASB  Statements  No. 4, 44, and 64,
    Amendment of FASB Statement No. 13, and Technical  Corrections."  This newly
    issued  statement  rescinds  SFAS No. 4,  "Reporting  Gains and Losses  from
    Extinguishment of Debt (an amendment of APB Opinion No. 30)," which required
    all gains and losses from the  extinguishment  of debt to be aggregated and,
    if material,  classified as an extraordinary item, net of related income tax
    effect.  As a result,  the  criteria set forth by APB Opinion 30 will now be
    used to classify those gains and losses.  Any gain or loss on extinguishment
    will be  recorded  in the most  appropriate  line  item to which it  relates
    within net income before extraordinary items. For CP&L, 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
    consistent with ratemaking  treatment.  SFAS No. 145 also amends SFAS No. 13
    to require that  certain  lease  modifications  that have  economic  effects
    similar to  sale-leaseback  transactions be accounted for in the same manner
    as  sale-leaseback  transactions.  In  addition,  SFAS No. 145 amends  other
    existing authoritative pronouncements to make various technical corrections,
    clarify meanings or describe their  applicability  under changed conditions.
    For the provisions  related to the rescission of SFAS No. 4, SFAS No. 145 is
    effective for CP&L beginning in fiscal year 2004.  The remaining  provisions
    of SFAS  No.  145 are  effective  for  CP&L in  fiscal  year  2003.  CP&L is
    currently  evaluating the effects,  if any, that this statement will have on
    its results of operations and financial position.

                                       134
<PAGE>

    SFAS No. 148,  "Accounting  for  Stock-Based  Compensation  - Transition and
    Disclosure"
    In December 2002, the FASB issued SFAS No. 148,  "Accounting for Stock-Based
    Compensation  - Transition  and Disclosure -- an Amendment of FASB Statement
    No. 123," and provided  alternative  methods of  transition  for a voluntary
    change to the fair value-based method of accounting for stock-based employee
    compensation. In addition, this statement amends the disclosure requirements
    of SFAS No.  123,  "Accounting  for  Stock-Based  Compensation,"  to require
    prominent  disclosures in both annual and interim financial statements about
    the method of  accounting  for  stock-based  employee  compensation  and the
    effect of the method used on reported results.  This statement requires that
    companies  having a year-end  after  December 15, 2002 follow the prescribed
    format and provide the additional  disclosures in their annual reports. CP&L
    applies the recognition  and  measurement  principles of APB Opinion No. 25,
    "Accounting  for Stock Issued to  Employees" as allowed by SFAS Nos. 123 and
    148,  and  related   interpretations   in  accounting  for  its  stock-based
    compensation plans as described in Note 12.

    The following table  illustrates the effect on CP&L's net income if CP&L had
    applied the fair value  recognition  provisions of SFAS No. 123 to the stock
    option plan. The stock option plan was not in effect in 2000.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

    (In thousands)                                     2002       2001       2000
                                                    ---------  ---------  ---------
    Net income, as reported                         $ 430,932  $ 364,231  $ 461,028
    Deduct:  Total stock option expense
      determined under fair value method
      for all awards, net of related tax effects        4,704      1,200          -
                                                    ---------  ---------  ---------

    Proforma net income                             $ 426,228  $ 363,031  $ 461,028
                                                    =========  =========  =========
</TABLE>

    FIN  No.  45,  "Guarantor's   Accounting  and  Disclosure  Requirements  for
    Guarantees, Including Indirect Guarantees of Indebtedness of Others"
    In  November  2002,  the FASB  issued  Interpretation  No. 45,  "Guarantor's
    Accounting and Disclosure  Requirements for Guarantees,  Including  Indirect
    Guarantees of Indebtedness of Others - an  Interpretation of FASB Statements
    No. 5, 57 and 107 and  Rescission  of FASB  Interpretation  No. 34" (FIN No.
    45). This interpretation clarifies the disclosures to be made by a guarantor
    in its interim  and annual  financial  statements  about  obligations  under
    certain guarantees that it has issued. It also clarifies that a guarantor is
    required to recognize,  at the inception of certain guarantees,  a liability
    for the fair value of the  obligation  undertaken in issuing the  guarantee.
    The  initial  recognition  and  initial   measurement   provisions  of  this
    interpretation are applicable on a prospective basis to guarantees issued or
    modified after December 31, 2002. The disclosure  requirements are effective
    for financial  statements of interim or annual periods ending after December
    15, 2002. The applicable  disclosures  required by FIN No. 45 have been made
    in Note 18B.  CP&L is currently  evaluating  the effects,  if any, that this
    interpretation  will  have  on  its  results  of  operations  and  financial
    position.

    FIN No. 46, "Consolidation of Variable Interest Entities"
    In January 2003, the FASB issued  Interpretation  No. 46,  "Consolidation of
    Variable  Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
    This  interpretation  provides  guidance  related  to  identifying  variable
    interest entities (previously known as special purpose entities or SPEs) and
    determining   whether  such  entities   should  be   consolidated.   Certain
    disclosures  are  required  when  FIN  No.  46  becomes  effective  if it is
    reasonably possible that a company will consolidate or disclose  information
    about a variable  interest entity when it initially applies FIN No. 46. This
    interpretation  must be applied  immediately to variable  interest  entities
    created or obtained  after  January 31, 2003.  For those  variable  interest
    entities  created or obtained on or before January 31, 2003, CP&L must apply
    the provisions of FIN No. 46 in the third quarter of 2003. CP&L is currently
    evaluating  what  effects,  if any,  this  interpretation  will  have on its
    results of operations and financial position.

    EITF Issue 02-03,  "Accounting for Contracts  Involved in Energy Trading and
    Risk Management Activities"
    In June 2002,  the EITF  reached a  consensus  on a portion of Issue  02-03,
    "Accounting  for Contracts  Involved in Energy  Trading and Risk  Management
    Activities."  EITF Issue 02-03  requires  all gains and losses  (realized or
    unrealized)  on  energy  trading  contracts  to be shown  net in the  income
    statement.  CP&L's  policy  already  required  the  gains  and  losses to be
    recorded  on a net basis.  The net of the gains and losses are  recorded  in
    other,  net on the  Consolidated  Statements  of  Income  and  Comprehensive

                                       135
<PAGE>

    Income.  CP&L does not recognize a dealer profit or unrealized  gain or loss
    at the inception of a derivative  unless the fair value of that  instrument,
    in its  entirety,  is evidenced by quoted  market  prices or current  market
    transactions.

2.  Divestitures

    In September 2000,  Caronet,  Inc.  (Caronet),  a wholly owned subsidiary of
    CP&L, sold its 10% limited  partnership  interest in BellSouth Carolinas PCS
    for $200 million. The sale resulted in an after-tax gain of $121.1 million.

3.  Financial Information by Business Segment

    As described in Note 1A, on July 1, 2000,  CP&L  distributed  its  ownership
    interest  in the  stock of NCNG,  SRS,  Monroe  Power  and PVHI to  Progress
    Energy.  As a result,  those  companies are direct  subsidiaries of Progress
    Energy and are not included in CP&L's  results of  operations  and financial
    position subsequent to July 1, 2000.

    Through  June 30,  2000,  the business  segments,  operations  and assets of
    Progress Energy and CP&L were substantially the same.  Subsequent to July 1,
    2000, CP&L's operations consisted primarily of the CP&L Electric segment.

    The financial  information for the CP&L Electric segment for the years ended
    December 31, 2002, 2001 and 2000 is as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                             Year Ended           Year Ended         Year Ended
(In thousands)                           December 31, 2002    December 31, 2001   December 31, 2000
----------------------------------------------------------------------------------------------------

Revenues                                         $3,538,957          $ 3,343,720        $ 3,308,215
Depreciation and amortization                       523,846              521,910            698,633
Net interest charges                                211,536              241,427            221,856
Income taxes                                        237,362              264,078            227,705
Net income                                          513,115              468,328            373,764
Total segment assets                              8,659,297            8,884,385          8,840,736
Capital and investment expenditures                 624,202              823,952            821,991
====================================================================================================
</TABLE>

    The  primary  differences  between  the CP&L  Electric  segment and the CP&L
    consolidated  financial information relate to other non-electric  operations
    and elimination entries. CP&L's non-electric operations had combined revenue
    of $14.9 million in 2002 and assets of $315.4  million at December 31, 2002.
    Included  in  the  2002  operations  of the  telecommunications  subsidiary,
    Caronet,  is an  impairment  of assets  and  investments  of $87.4  million,
    after-tax (See Note 5A).  Excluding this impairment,  the earnings of CP&L's
    non-electric operations are negligible.

4.  Related Party Transactions

    CP&L participates in an internal money pool, operated by Progress Energy, to
    more  effectively  utilize cash resources and to reduce  outside  short-term
    borrowings.  Short-term  borrowing needs are met first by available funds of
    the money pool  participants.  Borrowing  companies  pay  interest at a rate
    designed  to  approximate  the  cost  of  outside   short-term   borrowings.
    Subsidiaries  which  invest  in the  money  pool  earn  interest  on a basis
    proportionate to their average monthly investment. The interest rate used to
    calculate  earnings  approximates  external  interest  rates.  Funds  may be
    withdrawn  from or repaid to the pool at any time without prior  notice.  At
    December 31, 2002,  CP&L had $49.8  million of amounts  receivable  from the
    money pool that are included in notes  receivable from affiliated  companies
    on the  Consolidated  Balance  Sheets.  At December 31, 2001, CP&L had $47.9
    million of amounts  payable  to the money  pool that are  included  in notes
    payable to affiliated  companies on the  Consolidated  Balance  Sheets.  The
    weighted-average  interest  rates  associated  with such money pool balances
    were  2.18% and 4.47% at  December  31,  2002 and 2001,  respectively.  CP&L
    recorded  $0.3 million and $1.6 million of interest  income and $1.6 million
    and $1.7 million of interest  expense related to the money pool for 2002 and
    2001,  respectively.  Amounts  recorded  for  interest  income and  interest
    expense related to the money pool for 2000 were not significant.

    During 2000, the Company formed Progress Energy Service Company,  LLC (PESC)
    to  provide  specialized   services,   at  cost,  to  the  Company  and  its
    subsidiaries,  as approved by the U.S.  Securities  and Exchange  Commission
    (SEC).  CP&L has an  agreement  with PESC under  which  services,  including
    purchasing, accounting, treasury, tax, marketing, legal and human resources,
    are  rendered  to CP&L at cost.  Amounts  billed  to CP&L by PESC for  these

                                       136
<PAGE>

    services  during  2002,  2001 and 2000  amounted to $260.5  million,  $173.9
    million and $52.4 million, respectively. At December 31, 2002 and 2001, CP&L
    had net payables of $63.2 million and $46.0 million,  respectively,  to PESC
    that are included in payables to  affiliated  companies on the  Consolidated
    Balance  Sheets.  Subsidiaries  of CP&L had amounts  payable to PESC of $0.5
    million at  December  31,  2002 and  amounts  receivable  from PESC of $13.7
    million at December 31,  2001.  During  2002,  the Office of Public  Utility
    Regulation  within the SEC completed an audit  examination  of the Company's
    books and  records.  This  examination  is a standard  process for all PUHCA
    registrants.  Based on the review,  the method for allocating  PESC costs to
    the Company and its affiliates will change in 2003. CP&L does not anticipate
    the  reallocation  of costs  will have a material  impact on the  results of
    operations.

    During the years ended December 31, 2002, 2001 and 2000, gas sales from NCNG
    to  CP&L  amounted  to  $18.2  million,  $14.7  million  and  $5.9  million,
    respectively.

    In August 2002, CP&L transferred reservation payments for the manufacture of
    two  combustion  turbines to Florida  Power at CP&L's  original  cost of $20
    million.

    For the year ended  December  31,  2001 and the period  from July 1, 2000 to
    December 31, 2000, the Consolidated  Statements of Income and  Comprehensive
    Income  contain  interest  income  received  from NCNG in the amount of $4.8
    million  and  $4.1  million,  respectively,  related  to  a  note  that  was
    outstanding  between the two companies.  Prior to July 1, 2000, the interest
    income  received from NCNG was  eliminated in  consolidation.  There were no
    balances outstanding on the note at December 31, 2002 and 2001.

    At December 31, 2001, CP&L had a payable to Progress Energy in the amount of
    $40.2 million related to a short-term  cash advance.  This amount was repaid
    during  February  2002.  The  remaining  receivables  from and  payables  to
    affiliated  companies at December 31, 2002 and 2001  represent  intercompany
    amounts generated through CP&L's normal course of operations.

5.  Impairments of Long-Lived Assets and Investments

    Effective  January 1, 2002,  CP&L adopted SFAS No. 144,  "Accounting for the
    Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides guidance
    for the  accounting  and  reporting of  impairment or disposal of long-lived
    assets.  The  statement   supersedes  SFAS  No.  121,  "Accounting  for  the
    Impairment of  Long-Lived  Assets and for  Long-Lived  Assets to be Disposed
    Of."  In  2002  and  2001,  CP&L  recorded   pre-tax  asset  and  investment
    impairments   of   approximately   $133.3   million   and  $156.7   million,
    respectively. There were no impairments recorded in 2000.

    A. Long-Lived Assets

    Due  to  the  decline  of  the  telecommunications  industry  and  continued
    operating  losses,  CP&L initiated an independent  valuation study to assess
    the recoverability of Caronet's long-lived assets. Based on this assessment,
    CP&L recorded  asset  impairments  of $101.2  million on a pre-tax basis and
    other  charges  of $7.1  million  on a pre-tax  basis  primarily  related to
    inventory  adjustments  in the third  quarter  of 2002.  These  amounts  are
    included in diversified business expenses on the Consolidated  Statements of
    Income and Comprehensive  Income. This write-down  constitutes a significant
    reduction in the book value of these long-lived assets.

    The long-lived asset  impairments  include an impairment of property,  plant
    and  equipment,  construction  work in process and  intangible  assets.  The
    impairment  charge  represents  the  difference  between  the fair value and
    carrying amount of these long-lived  assets.  The fair value of these assets
    was determined  using a valuation  study heavily  weighted on the discounted
    cash  flow   methodology,   while  using  market  approaches  as  supporting
    information.

    B. Investments

    CP&L continually  reviews its investments to determine  whether a decline in
    fair value below the cost basis is other than temporary.  Effective June 28,
    2000,  Caronet  entered  into an  agreement  with Bain  Capital  whereby  it
    contributed the net assets used in its application service provider business
    to a newly formed company, named Interpath Communications, Inc. (Interpath),
    in exchange for a 35% ownership interest (15% voting interest) in Interpath.

                                       137
<PAGE>

    CP&L obtained a valuation  study to assess its investment in Interpath based
    on current  valuations  in the  technology  sector during 2001. As a result,
    CP&L recorded investment  impairments for  other-than-temporary  declines in
    the fair value of its investment in Interpath. The investment write-down was
    $156.7  million on a pre-tax basis for the year ended  December 31, 2001. In
    May 2002, Interpath merged with a third party.  Pursuant to the terms of the
    merger  agreement  and due to  additional  funds being  contributed  by Bain
    Capital,  CP&L's ownership was diluted to approximately 19% of Interpath (7%
    voting interest).  As a result,  CP&L reviewed the Interpath  investment for
    impairment and wrote off the remaining  amount of its cost-basis  investment
    in Interpath,  recording a pre-tax  impairment of $25.0 million in the third
    quarter of 2002.  In the fourth  quarter  of 2002,  CP&L sold its  remaining
    interest in Interpath for a nominal amount.

6.  Debt and Credit Facilities

    A. Lines of Credit

    At December 31,  2002,  CP&L had  committed  lines of credit  totaling  $570
    million,  all of which are used to support its commercial paper  borrowings.
    CP&L is required  to pay  minimal  annual  commitment  fees to maintain  its
    credit  facilities.  The following table summarizes CP&L's credit facilities
    used to support the issuance of commercial paper (in millions):

                            Description                           Total
        ----------------------------------------------------------------------

        364-Day (expiring 7/30/03)                                 $   285
        3-Year (expiring 7/31/05)                                      285
                                                             -----------------
                                                                   $   570
                                                             =================

    There were no loans outstanding under these facilities at December 31, 2002.

    As of  December  31,  2002 and 2001,  CP&L had  $437.8  million  and  $260.5
    million,  respectively, of outstanding commercial paper and other short term
    debt classified as short term  obligations.  The weighted  average  interest
    rates of such  short-term  obligations  at  December  31, 2002 and 2001 were
    1.74% and 3.07%, respectively.  CP&L no longer reclassifies commercial paper
    to long term  debt.  Certain  amounts  for 2001 have  been  reclassified  to
    conform to 2002  presentation,  with no effect on  previously  reported  net
    income or common stock equity.

    The combined aggregate  maturities of long-term debt for 2004, 2005 and 2007
    are approximately $300 million, $307 million and $200 million, respectively.
    There are no maturities of debt scheduled for 2003 or 2006.

    B. Covenants and Default Provisions

    Financial Covenants
    CP&L's credit line contains  various terms and conditions  that could affect
    CP&L's  ability to borrow under these  facilities.  These  include a maximum
    debt to  total  capital  ratio,  a  material  adverse  change  clause  and a
    cross-default provision.

    CP&L's  credit line  requires a maximum total debt to total capital ratio of
    65%.  Indebtedness as defined by the bank agreement includes certain letters
    of credit and guarantees which are not recorded on the Consolidated  Balance
    Sheets.  As of December 31, 2002,  CP&L's total debt to total  capital ratio
    was 52.7%.

    Material adverse change clause
    The credit  facility of CP&L includes a provision  under which lenders could
    refuse to  advance  funds in the event of a material  adverse  change in the
    borrower's financial condition.

    Default provisions
    CP&L's  credit  lines  include  cross-default  provisions  for  defaults  of
    indebtedness in excess of $10 million. CP&L's cross-default  provisions only
    apply  to  defaults   of   indebtedness   by  CP&L  and  its   subsidiaries,
    respectively,  and not to other affiliates of CP&L. In addition,  the credit
    lines  of  the  Company  include  a  similar  provision.  Progress  Energy's
    cross-default  provisions only apply to defaults of indebtedness by Progress
    Energy and its significant subsidiaries, which includes CP&L.

                                       138
<PAGE>

    The lenders may accelerate  payment of any outstanding debt if cross-default
    provisions  are  triggered.  Any such  acceleration  would  cause a material
    adverse  change in the respective  company's  financial  condition.  Certain
    agreements underlying CP&L's indebtedness also limit CP&L's ability to incur
    additional   liens  or  engage  in  certain  types  of  sale  and  leaseback
    transactions.

    Other restrictions
    CP&L's mortgage  indenture provides that so long as any first mortgage bonds
    are  outstanding,  cash dividends and  distributions on CP&L's common stock,
    and purchases of CP&L's common stock, are restricted to aggregate net income
    available  for CP&L,  since  December  31, 1948,  plus $3 million,  less the
    amount of all preferred  stock dividends and  distributions,  and all common
    stock  purchases,  since  December 31, 1948.  At December 31, 2002,  none of
    CP&L's retained earnings of $1.3 billion was restricted.

    Refer to Note 11 for  additional  dividend  restrictions  related  to CP&L's
    Articles of Incorporation.

    C. Secured Obligations

    CP&L's  first  mortgage  bonds  are  secured  by their  respective  mortgage
    indentures. CP&L's mortgage constitutes a first lien on substantially all of
    its  fixed  properties,   subject  to  certain  permitted  encumbrances  and
    exceptions.  The  CP&L  mortgage  also  constitutes  a lien on  subsequently
    acquired property. At December 31, 2002, CP&L had approximately $2.3 billion
    in first mortgage  bonds  outstanding  including  those related to pollution
    control  obligations.  The CP&L  mortgage  allows the issuance of additional
    mortgage bonds upon the satisfaction of certain conditions.

    D. Hedging Activities

    CP&L uses  interest rate  derivatives  to adjust the fixed and variable rate
    components  of its debt  portfolio and to hedge cash flow risk of fixed rate
    debt to be issued in the  future.  See  discussion  of risk  management  and
    derivative transactions at Note 10.

7.  Leases

    CP&L  leases  office  buildings,  computer  equipment,  vehicles,  and other
    property and equipment with various terms and expiration dates. Rent expense
    (under  operating  leases)  totaled $9.5  million,  $21.7  million and $13.8
    million for 2002, 2001 and 2000, respectively.

    Assets recorded under capital leases consist of (in thousands):

                                            2002          2001
                                           --------     --------
    Buildings                              $ 27,633     $ 27,626
    Less:  Accumulated amortization         (9,329)      (8,752)
                                           --------     --------
                                           $ 18,304     $ 18,874
                                           ========     ========

    Minimum annual rental payments,  excluding  executory costs such as property
    taxes, insurance and maintenance, under long-term noncancelable leases as of
    December 31, 2002 are (in thousands):

                                                     Capital     Operating
                                                     Leases       Leases
    2003                                            $ 2,189      $ 9,557
    2004                                              2,189        7,695
    2005                                              2,189        6,302
    2006                                              2,189        3,835
    2007                                              2,189        3,829
    Thereafter                                       20,274       13,142
                                                    -------     --------
                                                    $31,219      $44,360
                                                                 =======
    Less amount representing imputed interest       (12,214)
                                                    --------
    Present value of net minimum lease payments
       under capital leases                         $19,005
                                                    =======

                                       139
<PAGE>

    CP&L is the lessor of electric  poles and  streetlights.  Rents received are
    contingent  upon usage and totaled  $28.4  million,  $30.9 million and $23.3
    million for 2002, 2001 and 2000, respectively.

8.  Fair Value of Financial Instruments

    The carrying amounts of cash and cash equivalents and short-term obligations
    approximate fair value due to the short maturities of these instruments.  At
    December 31, 2002 and 2001, there were miscellaneous  investments consisting
    primarily of investments in  company-owned  life insurance and other benefit
    plan assets with carrying amounts totaling  approximately  $54.2 million and
    $50.0 million,  respectively,  included in miscellaneous  other property and
    investments.  The carrying  amount of these  investments  approximates  fair
    value due to the short maturity of certain  instruments.  Other  instruments
    are presented at fair value in accordance  with GAAP. The carrying amount of
    CP&L's long-term debt,  including  current  maturities,  was $3.1 billion at
    December 31, 2002 and $3.3 billion at December 31, 2001.  The estimated fair
    value of this debt,  as obtained  from quoted  market prices for the same or
    similar  issues,  was $3.3 billion and $3.4 billion at December 31, 2002 and
    2001, respectively.

    External funds have been established as a mechanism to fund certain costs of
    nuclear  decommissioning (See Note 1G). These nuclear  decommissioning trust
    funds  are  invested  in  stocks,   bonds  and  cash  equivalents.   Nuclear
    decommissioning  trust funds are presented at amounts that  approximate fair
    value.  Fair value is  obtained  from quoted  market  prices for the same or
    similar investments.

9.  Regulatory Matters

    A. Regulatory Assets and Liabilities

    As a regulated  entity,  CP&L is subject to the  provisions  of SFAS No. 71,
    "Accounting  for the Effects of Certain Types of  Regulation."  Accordingly,
    CP&L records  certain assets and  liabilities  resulting from the effects of
    the  ratemaking  process,  which  would  not  be  recorded  under  GAAP  for
    nonregulated  entities.  CP&L's ability to continue to meet the criteria for
    application  of SFAS No. 71 may be  affected  in the  future by  competitive
    forces and restructuring in the electric utility industry. In the event that
    SFAS No. 71 no longer applied to a separable  portion of CP&L's  operations,
    related  regulatory  assets and  liabilities  would be eliminated  unless an
    appropriate regulatory recovery mechanism was provided.  Additionally, these
    factors  could result in an impairment of utility plant assets as determined
    pursuant  to SFAS No. 144,  "Accounting  for the  Impairment  or Disposal of
    Long-Lived Assets" (See Note 5).

    At December  31, 2002 and 2001,  the  balances of CP&L's  regulatory  assets
    (liabilities) were as follows (in thousands):

                                                            2002         2001
                                                         ---------    ---------
    Deferred fuel (included in current assets)           $ 146,015    $ 131,505
                                                         ---------    ---------

    Income taxes recoverable through future rates          197,402      208,702
    Harris Plant deferred costs                             16,888       32,476
    Loss on reacquired debt                                 13,223        5,801
    Deferred DOE enrichment facilities-related costs        24,570       30,571
                                                         ---------    ---------
       Total long-term regulatory assets                   252,083      277,550
                                                         ---------    ---------

    Emission allowance gains                               (7,774)      (7,494)
                                                         ---------    ---------

         Net regulatory assets                           $ 390,324    $ 401,561
                                                         =========    =========

    Except for portions of deferred fuel, all regulatory assets earn a return or
    the cash has not yet been expended,  in which case, the assets are offset by
    liabilities that do not incur a carrying cost.

    B. Retail Rate Matters

    The NCUC and SCPSC approved  proposals to accelerate cost recovery of CP&L's
    nuclear  generating assets beginning January 1, 2000, and continuing through
    2004. On June 14, 2002,  the NCUC approved  modification  of CP&L's  ongoing
    accelerated  cost  recovery  of its  nuclear  generating  assets.  Effective
    January  1,  2003,  the  NCUC  will  no  longer  require  a  minimum  annual
    depreciation.  The  aggregate  minimum  and maximum  amounts of  accelerated

                                       140
<PAGE>

    depreciation, $415 million and $585 million respectively, are unchanged from
    the  original  NCUC  order.  The date by which the  minimum  amount  must be
    depreciated  was extended  from  December 31, 2004 to December 31, 2009.  On
    October 29, 2002, the SCPSC approved  similar  modifications.  The order was
    effective  November 1, 2002,  and the aggregate  minimum and maximum of $115
    million and $165 million  established for  accelerated  cost recovery by the
    SCPSC is unchanged.  The accelerated  cost recovery of these assets resulted
    in additional depreciation expense of approximately $53 million, $75 million
    and $275 million in 2002, 2001 and 2000, respectively.  Recovering the costs
    of its  nuclear  generating  assets  on an  accelerated  basis  will  better
    position CP&L for the uncertainties  associated with potential restructuring
    of the electric utility industry.  Total accelerated  depreciation  recorded
    through   December  31,  2002  was  $326  million  for  the  North  Carolina
    jurisdiction and $77 million for the South Carolina jurisdiction.

    On May 30, 2001,  the NCUC issued an order allowing CP&L to offset a portion
    of its annual  accelerated cost recovery of nuclear generating assets by the
    amount of sulfur  dioxide  (SO2)  emission  allowance  expense.  CP&L offset
    accelerated  depreciation  expense  against  emission  allowance  expense by
    approximately  $5.8  million  in  2002.  CP&L  did  not  offset  accelerated
    depreciation  expense against  emission  allowance  expense in 2001. CP&L is
    allowed  to recover  emission  allowance  expense  through  the fuel  clause
    adjustment in its South Carolina retail jurisdiction.

    In conjunction  with the acquisition of NCNG, CP&L agreed to cap base retail
    electric rates in North Carolina and South Carolina  through  December 2004.
    The cap on base retail  electric  rates in South  Carolina  was  extended to
    December  2005 in  conjunction  with  regulatory  approval to form a holding
    company.  In North  Carolina,  legislation  enacted  pursuant  to the  North
    Carolina  Clean Air Act in June of 2002  freezes  CP&L's base rates for five
    years, subject to certain conditions. See Note 18D for further discussion of
    this matter.

    In conjunction with the Company's merger with Florida Progress  Corporation,
    CP&L  reached a  settlement  with the  Public  Staff of the NCUC in which it
    agreed to reduce rates to all of its non-real time pricing customers by $3.0
    million in 2002, $4.5 million in 2003, $6.0 million in 2004 and $6.0 million
    in 2005. CP&L also agreed to write off and forego recovery of $10 million of
    unrecovered fuel costs in each of its 2000 NCUC and SCPSC fuel cost recovery
    proceedings.

10. Risk Management Activities and Derivatives Transactions

    Under its risk  management  policy,  CP&L may use a variety of  instruments,
    including  swaps,  options  and  forward  contracts,  to manage  exposure to
    fluctuations  in  commodity  prices and  interest  rates.  Such  instruments
    contain credit risk if the counterparty fails to perform under the contract.
    CP&L  minimizes such risk by performing  credit  reviews using,  among other
    things, publicly available credit ratings of such counterparties.  Potential
    non-performance  by counterparties is not expected to have a material effect
    on the consolidated financial position or consolidated results of operations
    of CP&L.

    A. Commodity Contracts - General

    Most of CP&L's commodity  contracts  either are not derivatives  pursuant to
    SFAS No. 133 or qualify as normal  purchases  or sales  pursuant to SFAS No.
    133. Therefore, such contracts are not recorded at fair value.

    B. Commodity Derivatives - Economic Hedges and Trading

    Nonhedging derivatives, primarily electricity forward contracts, are entered
    into  for  trading  purposes  and  for  economic  hedging  purposes.   While
    management  believes the economic hedges mitigate  exposures to fluctuations
    in commodity  prices,  these  instruments  are not  designated as hedges for
    accounting  purposes and are monitored  consistent  with trading  positions.
    CP&L manages open positions with strict  policies that limit its exposure to
    market risk and require daily reporting to management of potential financial
    exposures.  Gains and losses from such  contracts  were not material  during
    2002, 2001 or 2000, and CP&L did not have material outstanding  positions in
    such contracts at December 31, 2002 or 2001.

    C. Interest Rate Derivatives - Fair Value or Cash Flow Hedges

    CP&L  manages  its  interest  rate  exposure  in  part  by  maintaining  its
    variable-rate  and fixed-rate  exposures within defined limits. In addition,
    CP&L also enters into financial derivative  instruments  including,  but not
    limited to,  interest rate swaps and lock  agreements to manage and mitigate
    interest rate risk exposure.

                                       141
<PAGE>

    CP&L uses cash flow hedging  strategies to hedge variable  interest rates on
    long-term debt and to hedge interest rates with regard to future  fixed-rate
    debt  issuances.  At December 31, 2002, CP&L held no interest rate cash flow
    hedges.  As of December 31, 2002,  $0.8  million of net  after-tax  deferred
    losses in  accumulated  other  comprehensive  income,  related to terminated
    hedges,  will be  reclassified  to earnings during the next 12 months as the
    hedged  interest  payments  occur.  At December 31, 2001, CP&L held interest
    rate cash flow hedges with notional  amounts  totaling  $500.0 million and a
    total fair value of $18.5 million liability position.

    CP&L uses fair value  hedging  strategies  to manage its  exposure  to fixed
    interest rates on long-term debt. At December 31, 2002 and 2001, CP&L had no
    open interest rate fair value hedges.

    The notional  amounts of interest rate  derivatives are not exchanged and do
    not  represent  exposure  to  credit  loss.  In the  event of  default  by a
    counterparty,  the risk in these  transactions  is the cost of replacing the
    agreements at current market rates.

11. Capitalization

    As of December  31, 2002,  CP&L was  authorized  to issue up to  200,000,000
    shares of common stock.  All shares issued and  outstanding  are held by the
    Company, effective with the share exchange on June 19, 2000 (See Note 1A).

    There are various  provisions  limiting the use of retained earnings for the
    payment of dividends under certain  circumstances.  As of December 31, 2002,
    there were no significant restrictions on the use of retained earnings.

    CP&L's Articles of Incorporation provide that cash dividends on common stock
    shall be limited  to 75% of net income  available  for  dividends  if common
    stock equity falls below 25% of total  capitalization,  and to 50% if common
    stock  equity falls below 20%. On December  31,  2002,  CP&L's  common stock
    equity was approximately 46.6% of total capitalization.

    Refer to Note 6 for  additional  dividend  restrictions  related  to  CP&L's
    mortgage.

12. Stock-Based Compensation Plans

    CP&L accounts for stock-based compensation in accordance with the provisions
    of Accounting  Principles Board Opinion No. 25, "Accounting for Stock Issued
    to Employees," and related  interpretations as permitted under SFAS No. 123,
    "Accounting for Stock-Based Compensation."

    A. Employee Stock Ownership Plan

    Progress  Energy  sponsors  the  Progress  Energy  401(k)  Savings and Stock
    Ownership Plan (401(k)) for which substantially all full-time non-bargaining
    unit  employees  and  certain  part-time   non-bargaining  employees  within
    participating  subsidiaries are eligible. CP&L is a participating subsidiary
    of the 401(k),  which has matching and incentive goal  features,  encourages
    systematic  savings by employees and provides a method of acquiring Progress
    Energy common stock and other diverse investments. The 401(k), as amended in
    1989,  is an  Employee  Stock  Ownership  Plan  (ESOP)  that can enter  into
    acquisition  loans to acquire Progress Energy common stock to satisfy 401(k)
    common  stock  needs.  Qualification  as an ESOP did not change the level of
    benefits received by employees under the 401(k).  Common stock acquired with
    the  proceeds  of an ESOP loan is held by the  401(k)  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
    Progress  Energy  matching and  incentive  contributions  and/or  reinvested
    dividends.

    There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
    and 2001,  respectively,  with a fair  value of $200.1  million  and  $234.1
    million, respectively.  CP&L's matching and incentive goal compensation cost
    under the 401(k) is determined  based on matching  percentages and incentive
    goal attainment as defined in the plan. Such  compensation cost is allocated
    to participants'  accounts in the form of Progress Energy common stock, with
    the number of shares determined by dividing  compensation cost by the common
    stock market value at the time of allocation.  The 401(k) common stock share
    needs are met with open market purchases, with shares released from the ESOP

                                       142
<PAGE>

    suspense account and with newly issued shares. CP&L's matching and incentive
    cost  met  with  shares   released   from  the  suspense   account   totaled
    approximately  $13.3 million,  $12.7 million and $14.7 million for the years
    ended December 31, 2002, 2001 and 2000,  respectively.  CP&L has a long-term
    note  receivable  from the 401(k) Trustee  related to the purchase of common
    stock from CP&L in 1989 (now Progress  Energy common stock).  The balance of
    the note receivable from the 401(k) Trustee is included in the determination
    of unearned ESOP common stock,  which reduces common stock equity.  Interest
    income on the note  receivable is not  recognized  for  financial  statement
    purposes.

    B. Stock Option Agreements

    Pursuant to Progress  Energy's  1997 Equity  Incentive  Plan and 2002 Equity
    Incentive Plan, as amended and restated as of July 10, 2002, Progress Energy
    may grant options to purchase shares of common stock to directors,  officers
    and eligible employees.  During 2002 and 2001, approximately 2.9 million and
    2.4  million   common  stock  options  were  granted.   Of  these   amounts,
    approximately  1.2  million  and 1.0 million  were  granted to officers  and
    eligible employees of CP&L in 2002 and 2001,  respectively.  No compensation
    expense was recognized  under the provisions of Accounting  Principles Board
    Opinion No. 25,  "Accounting  for Stock  Issued to  Employees,"  and related
    interpretations.  For purposes of the proforma  disclosures required by SFAS
    No. 123,  the  estimated  fair value of the options is  amortized to expense
    over the options' vesting period.  Under SFAS No. 148,  compensation expense
    would  have  been  $7.9   million  and  $2.0   million  in  2002  and  2001,
    respectively.

    C. Other Stock-Based Compensation Plans

    Progress  Energy has  additional  compensation  plans for  officers  and key
    employees that are  stock-based in whole or in part.  CP&L  participates  in
    these plans. The two primary active  stock-based  compensation  programs are
    the  Performance  Share  Sub-Plan  (PSSP) and the  Restricted  Stock  Awards
    program (RSA), both of which were established  pursuant to Progress Energy's
    1997  Equity  Incentive  Plan  and were  continued  under  the  2002  Equity
    Incentive Plan, as amended and restated as of July 10, 2002.

    Under  the  terms  of the  PSSP,  officers  and key  employees  are  granted
    performance   shares  on  an  annual  basis  that  vest  over  a  three-year
    consecutive period. Each performance share has a value that is equal to, and
    changes with, the value of a share of Progress  Energy's  common stock,  and
    dividend  equivalents  are accrued on, and  reinvested  in, the  performance
    shares.  The PSSP has two equally  weighted  performance  measures,  both of
    which are based on Progress  Energy's results as compared to a peer group of
    utilities.  Compensation expense is recognized over the vesting period based
    on the expected ultimate cash payout and is reduced by any forfeitures.

    The RSA allows the Company to grant  shares of  restricted  common  stock to
    officers and key employees of the Company.  The restricted  shares generally
    vest  on  a  graded  vesting   schedule  over  a  minimum  of  three  years.
    Compensation  expense,  which is based on the fair value of common  stock at
    the grant date,  is recognized  over the  applicable  vesting  period and is
    reduced by any forfeitures.

    The total amount expensed by CP&L for other stock-based  compensation  plans
    was $6.9  million,  $5.9  million and $9.8  million in 2002,  2001 and 2000,
    respectively.

13. Postretirement Benefit Plans

    CP&L and some of its subsidiaries  have a  non-contributory  defined benefit
    retirement  (pension) plan for  substantially all eligible  employees.  CP&L
    also has a supplementary defined benefit pension plan that provides benefits
    to higher-level employees.

    The components of net periodic pension cost are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                    2002           2001           2000
                                                   ----------     ----------    ---------

Expected return on plan assets                     $ (72,876)     $ (71,955)    $(76,508)
Service cost                                          19,343         16,960        18,804
Interest cost                                         50,717         46,729        49,821
Amortization of transition obligation                     97            116           121
Amortization of prior service (benefit) cost             195         (1,230)       (1,282)
Amortization of actuarial (gain) loss                    440         (4,352)       (5,607)
                                                   ----------     ----------    ----------
     Net periodic pension benefit                  $  (2,084)     $ (13,732)    $ (14,651)
                                                   ==========     ==========    ==========
</TABLE>
                                       143
<PAGE>

    In  addition  to the net  periodic  benefit  reflected  above,  in 2000 CP&L
    recorded a charge of approximately $14.1 million to adjust its supplementary
    defined  benefit pension plan. The effect of the adjustment for this plan is
    reflected   in  the   actuarial   loss  line  in  the   pension   obligation
    reconciliation below.

    Prior service costs and benefits are amortized on a straight-line basis over
    the average remaining service period of active participants. Actuarial gains
    and losses in excess of 10% of the greater of the pension  obligation or the
    market-related  value of assets are  amortized  over the  average  remaining
    service period of active participants.

    Reconciliations  of the changes in the plan's  benefit  obligations  and the
    plan's funded status are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                            2002             2001
                                                                         ----------       ----------
       Projected benefit obligation at  January 1                        $ 681,989        $ 638,067
           Interest cost                                                    50,717           46,729
           Service cost                                                     19,343           16,960
           Benefit payments                                                (46,059)         (43,636)
           Actuarial loss                                                   96,929            5,621
           Transfers                                                          (635)               -
           Plan amendments                                                    -              18,248
                                                                        -----------       ----------
       Projected benefit obligation at December 31                      $  802,284        $ 681,989
       Fair value of plan assets at December 31                            574,367          716,799
                                                                        -----------       ----------
       Funded status                                                    $ (227,917)       $  34,810
       Unrecognized transition obligation                                      241              338
       Unrecognized prior service cost                                       3,928            4,123
       Unrecognized actuarial (gain) loss                                  237,864          (28,416)
       Minimum pension liability adjustment                               (124,867)               -
                                                                        -----------       ----------
       Prepaid (accrued) pension cost at December 31, net               $ (110,751)       $  10,855
                                                                        ===========       ==========
</TABLE>

    The  accrued  pension  cost at  December  31,  2002  is  included  in  other
    liabilities and deferred  credits in the accompanying  Consolidated  Balance
    Sheets.  The net prepaid  pension cost of $10.9 million at December 31, 2001
    is  included  in the  accompanying  Consolidated  Balance  Sheets as prepaid
    pension  cost of $25.7  million,  which is  included  in  other  assets  and
    deferred  debits,  and  accrued  benefit  cost of  $14.8  million,  which is
    included in other  liabilities  and deferred  credits.  The defined  benefit
    plans with  accumulated  benefit  obligations  in excess of plan  assets had
    projected benefit  obligations  totaling $802.3 million and $16.0 million at
    December  31,  2002 and 2001,  respectively.  Those  plans  had  accumulated
    benefit obligations totaling $685.1 million and $15.4 million, respectively,
    plan assets totaling $574.4 million at December 31, 2002, and no plan assets
    at December 31, 2001.

    Due to a  combination  of  decreases  in the fair value of plan assets and a
    decrease in the  discount  rate used to measure the  pension  obligation,  a
    minimum  pension  liability  adjustment  of $124.9  million was  recorded at
    December 31, 2002. This  adjustment  resulted in a charge of $4.2 million to
    intangible  assets,  included  in other  assets and  deferred  debits in the
    accompanying  Consolidated  Balance  Sheets,  and a pre-tax charge of $120.7
    million to accumulated other comprehensive loss, a component of common stock
    equity.

                                       144
<PAGE>

    Reconciliations of the fair value of pension plan assets are (in thousands):

                                                         2002           2001
                                                      ----------     ----------
    Fair value of plan assets at January 1            $ 716,799      $ 777,435
    Actual return on plan assets                        (96,915)       (18,160)
    Benefit payments                                    (46,059)       (43,636)
    Employer contributions                                1,177          1,160
    Transfers                                              (635)             -
                                                      ----------     ----------
    Fair value of plan assets at December 31          $ 574,367      $ 716,799
                                                      ==========     ==========

    The  weighted-average  discount rate used to measure the pension  obligation
    was 6.6% in 2002 and 7.5% in 2001.  The  assumed  rate of increase in future
    compensation  used to measure  the pension  obligation  was 4.0% in 2002 and
    2001.  The expected  long-term rate of return on pension plan assets used in
    determining the net periodic pension cost was 9.25% in 2002, 2001 and 2000.

    In addition to pension benefits,  CP&L and some of its subsidiaries  provide
    contributory  postretirement benefits (OPEB),  including certain health care
    and life  insurance  benefits,  for  retired  employees  who meet  specified
    criteria.

    The components of net periodic OPEB cost are (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                     2002                2001             2000
                                                   ---------           ---------        --------
    Expected return on plan assets                 $ (3,532)           $ (3,676)        $(3,852)

    Service cost                                      6,301               7,374           8,868
    Interest cost                                    14,308              14,191          13,677
    Amortization of prior service cost                    -                   -              54
    Amortization of transition obligation             2,708               4,298           5,551
    Amortization of actuarial gain                     (851)               (531)           (779)
                                                   ---------           ---------        --------
        Net periodic OPEB cost                     $ 18,934            $ 21,656         $23,519
                                                   =========           =========        ========
</TABLE>

    Prior service costs and benefits are amortized on a straight-line basis over
    the average remaining service period of active participants. Actuarial gains
    and  losses in excess of 10% of the  greater of the OPEB  obligation  or the
    market-related  value of assets are  amortized  over the  average  remaining
    service period of active participants.

    Reconciliations  of the changes in the plan's  benefit  obligations  and the
    plan's funded status are (in thousands):


                                                         2002           2001
                                                     ----------     ----------
       OPEB obligation at January 1                  $ 192,088      $ 187,563
           Interest cost                                14,308         14,191
           Service cost                                  6,301          7,374
           Benefit payments                             (9,003)        (7,137)
           Actuarial loss                               30,222         19,242
           Transfers                                      (179)             -
           Plan amendment                                    -        (29,145)
                                                     ----------     ----------
       OPEB obligation at December 31                $ 233,737      $ 192,088
       Fair value of plan assets at December 31         32,890         38,182
                                                     ----------     ----------
       Funded status                                 $(200,847)     $(153,906)
       Unrecognized transition obligation               25,555         28,263
       Unrecognized actuarial (gain) loss               38,434         (1,284)
                                                     ---------      ----------
       Accrued OPEB cost at December 31              $(136,858)     $(126,927)
                                                     ==========     ==========

    The accrued OPEB cost is included in other  liabilities and deferred credits
    in the accompanying Consolidated Balance Sheets. The plan amendment in 2001,
    which resulted in a 15.5% reduction in the OPEB liability, implemented a cap
    on CP&L's contributions toward future medical cost increases.

                                       145
<PAGE>

    Reconciliations of the fair value of OPEB plan assets are (in thousands):

                                                         2002           2001
                                                       ---------      ---------

    Fair value of plan assets at January 1             $ 38,182       $ 39,048
    Actual return on plan assets                         (5,292)          (866)
    Employer contributions                                9,003          7,137
    Benefits paid                                        (9,003)        (7,137)
                                                       ---------      ---------
    Fair value of plan assets at December 31           $ 32,890       $ 38,182
                                                       =========      =========

    The assumptions used to measure the OPEB obligation are:

                                                           2002         2001
                                                          ------       ------

    Weighted-average discount rate                         6.60%        7.50%
    Initial medical cost trend rate for
       pre-Medicare benefits                               7.50%        7.50%
    Initial medical cost trend rate for
       post-Medicare benefits                              7.50%        7.50%
    Ultimate medical cost trend rate                       5.25%        5.00%
    Year ultimate medical cost trend rate is achieved      2009         2008


    The expected  weighted-average  long-term rate of return on plan assets used
    in determining  the net periodic OPEB cost was 9.25% in 2002, 2001 and 2000.
    The medical  cost trend rates were  assumed to decrease  gradually  from the
    initial rates to the ultimate  rates.  Assuming a 1% increase in the medical
    cost trend rates,  the aggregate of the service and interest cost components
    of the net periodic OPEB cost for 2002 would  increase by $3.2 million,  and
    the OPEB  obligation at December 31, 2002,  would increase by $23.1 million.
    Assuming a 1% decrease in the medical cost trend rates, the aggregate of the
    service and interest cost  components of the net periodic OPEB cost for 2002
    would decrease by $2.8 million and the OPEB obligation at December 31, 2002,
    would decrease by $21.0 million.

14. Income Taxes

    Deferred  income taxes are provided for temporary  differences  between book
    and tax bases of assets and  liabilities.  Investment tax credits related to
    regulated  operations  are  amortized  over the service  life of the related
    property. A regulatory asset or liability has been recognized for the impact
    of tax  expenses or benefits  that are  recovered  or refunded in  different
    periods by the utilities pursuant to rate orders.

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

                                                         2002           2001
    Accelerated depreciation and property
       cost differences                              $ 1,313,604    $ 1,359,083
    Minimum pension liability                            (47,317)             -
    Deferred costs, net                                   (9,771)        42,688
    Income tax credit carryforward                       (10,384)          (640)
    Valuation allowance                                    8,167          3,767
    Miscellaneous other temporary differences, net        (8,522)       (20,100)
                                                     ------------   ------------

    Net accumulated deferred income tax liability    $ 1,245,777    $ 1,384,798
                                                     ============   ============

    Total deferred income tax liabilities were $1.952 billion and $2.046 billion
    at  December  31, 2002 and 2001,  respectively.  Total  deferred  income tax
    assets  were $706  million and $661  million at December  31, 2002 and 2001,
    respectively. The net of deferred income tax liabilities and deferred income
    tax assets is included on the Consolidated Balance Sheets under the captions
    other current liabilities and accumulated deferred income taxes.

    CP&L had a valuation  allowance  of $3.8  million at  December  31, 2001 and
    established  additional valuation allowances of $4.4 million during 2002 due
    to the  uncertainty  of realizing  certain future state income tax benefits.
    CP&L  believes  that it is more  likely  than not that the results of future
    operations  will  generate  sufficient  taxable  income  to  allow  for  the
    utilization of the remaining deferred tax assets.

                                       146
<PAGE>

    Reconciliations of CP&L's effective income tax rate to the statutory federal
    income tax rate are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                            2002          2001         2000
                                                         ----------    ----------   ----------

    Effective income tax rate                               32.5%         38.0%        38.6%
    State income taxes, net of federal benefit              (3.1)         (3.2)        (4.5)
    Investment tax credit amortization                       1.9           2.5          3.7
    Progress Energy tax benefit allocation (Note 1L)         5.0            -            -
    Other differences, net                                  (1.3)         (2.3)        (2.8)
                                                         ----------    ----------   ----------

    Statutory federal income tax rate                       35.0%         35.0%        35.0%
                                                         ==========     =========   ==========
</TABLE>

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

                                            2002          2001           2000
                                        ----------     ----------     ----------
    Income tax expense (credit):
    Current   - federal                 $ 265,231      $ 348,921      $ 328,982
                state                      36,039         39,135         62,228
    Deferred  - federal                   (75,784)      (140,486)       (71,929)
                state                      (6,132)        (9,409)       (11,625)
    Investment tax credit                 (11,994)       (14,928)       (17,385)
                                        ----------     ----------     ----------

       Total income tax expense         $ 207,360      $ 223,233      $ 290,271
                                        ==========     ==========     ==========

15. Joint Ownership of Generating Facilities

    CP&L holds undivided ownership interests in certain jointly owned generating
    facilities.  CP&L is entitled  to shares of the  generating  capability  and
    output of each unit equal to their respective ownership interests. CP&L also
    pays its ownership share of additional  construction  costs,  fuel inventory
    purchases and operating  expenses.  CP&L's share of expenses for the jointly
    owned facilities is included in the appropriate expense category.

    CP&L's  ownership  interest in the  jointly-owned  generating  facilities is
    listed  below with  related  information  as of  December  31, 2002 and 2001
    (dollars in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

    2002
                                        Company                                                         Construction
                          Megawatt     Ownership       Plant       Accumulated        Accumulated          Work in
       Facility           Capability    Interest     Investment    Depreciation      Decommissioning      Progress
       --------           ----------    --------     ----------    ------------      ---------------      --------

    Mayo Plant               745         83.83%      $  464,202     $  239,971          $   -             $14,089
    Harris Plant             900         83.83%       3,159,946      1,432,245            95,643            6,117
    Brunswick Plant        1,683         81.67%       1,476,534        867,530           339,521           26,436
    Roxboro Unit No. 4       700         87.06%         316,491        138,408              -               8,079


    2001
                                        Company                                                         Construction
                          Megawatt     Ownership       Plant       Accumulated        Accumulated          Work in
       Facility           Capability    Interest     Investment    Depreciation      Decommissioning      Progress
       --------           ----------    --------     ----------    ------------      ---------------      --------

    Mayo Plant               745         83.83%      $  460,026      $ 230,630          $   -             $ 7,116
    Harris Plant             860         83.83%       3,154,183      1,321,694            93,637           14,416
    Brunswick Plant        1,631         81.67%       1,427,842        828,480           339,945           41,455
    Roxboro Unit No. 4       700         87.06%         309,032        126,007              -               7,881
</TABLE>

    In the tables above,  plant investment and accumulated  depreciation are not
    reduced by the regulatory disallowances related to the Harris Plant.

                                       147
<PAGE>

16. Other Income and Other Expense

    Other  income and  expense  includes  interest  income,  gain on the sale of
    investments, impairment of investments and other income and expense items as
    discussed  below.  The components of other, net as shown on the Consolidated
    Statements of Income and  Comprehensive  Income for years ended December 31,
    are as follows (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                           2002          2001        2000
                                                         ---------    ---------    ---------
Other income
Net financial trading gain (loss)                        $ (1,942)    $  3,262     $ 15,603
Net energy purchased for resale gain                        1,248        3,074        2,132
Nonregulated energy and delivery services income           11,816       11,528       23,996
Investment gains                                           22,218        2,500        6,722
AFUDC equity                                                6,432        8,764       14,502
Other                                                      19,891       12,963       11,594
                                                         ---------    ---------    ---------
    Total other income                                   $ 59,663     $ 42,091     $ 74,549
                                                         ---------    ---------    ---------

Other expense
Nonregulated energy and delivery services expenses         13,625       21,352       23,554
Donations                                                   7,594       11,045        9,219
Investment losses                                          14,389        4,365        6,672
Other                                                      11,298        9,484       18,015
                                                         ---------    ---------    --------
   Total other expense                                   $ 46,906      $ 46,246    $ 57,460
                                                         ---------    ---------    ---------

Other, net                                               $ 12,757      $(4,155)    $ 17,089
                                                         =========    =========    =========
</TABLE>

    Net  financial  trading gain (loss)  represents  non-asset-backed  trades of
    electricity and gas. Nonregulated energy and delivery services include power
    protection  services and mass market programs (surge  protection,  appliance
    services and area light sales) and  delivery,  transmission  and  substation
    work for other utilities.

17. Accumulated Other Comprehensive Loss

    Components  of  accumulated  other  comprehensive  loss are as  follows  (in
    thousands):

                                                            2002         2001
                                                         ----------   ---------

    Loss on cash flow hedges                             $  (9,379)   $ (7,046)
    Minimum pension liability adjustments                  (73,390)          -
                                                         ----------   ---------
    Total accumulated other comprehensive loss           $ (82,769)   $ (7,046)
                                                         ==========   =========

18. Commitments and Contingencies

    A. Fuel and Purchased Power

    Pursuant to the terms of the 1981 Power Coordination  Agreement, as amended,
    between CP&L and Power Agency, CP&L is obligated to purchase a percentage of
    Power Agency's  ownership capacity of, and energy from, the Harris Plant. In
    1993,  CP&L 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,  CP&L  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  capacity  costs,  total  approximately  $32  million.  These
    contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
    for 2002,  2001 and 2000,  respectively.  In 1987,  the NCUC ordered CP&L 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,  2002 and 2001,  CP&L had  deferred
    purchased  capacity costs,  including carrying costs accrued on the deferred
    balances,  of $16.9  million  and  $32.5  million,  respectively.  Increased
    purchases (which are not being deferred for future recovery)  resulting from
    the 1993 agreement with Power Agency were approximately $32.2 million, $28.6
    million and $26.0 million for 2002, 2001 and 2000, respectively.

                                       148
<PAGE>

    CP&L  has a  long-term  agreement  for the  purchase  of power  and  related
    transmission  services from Indiana  Michigan Power Company's  Rockport Unit
    No. 2 (Rockport).  The agreement  provides for the purchase of 250 megawatts
    of  capacity  through  2009  with  estimated   minimum  annual  payments  of
    approximately  $31 million,  representing  capital-related  capacity  costs.
    Total  purchases  (including  transmission  use charges)  under the Rockport
    agreement  amounted to $58.6  million,  $62.8  million and $61.0 million for
    2002, 2001 and 2000, respectively.

    Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
    of power from Skygen Energy LLC's Broad River facility  (Broad  River).  The
    agreement  provides  for the  purchase of  approximately  500  megawatts  of
    capacity   through  2021  with  an  original   minimum   annual  payment  of
    approximately $16 million,  primarily representing  capital-related capacity
    costs. A separate long-term  agreement for additional power from Broad River
    commenced June 1, 2002. This agreement provided for the additional  purchase
    of  approximately  300  megawatts of capacity  through 2022 with an original
    minimum   annual   payment  of   approximately   $16  million   representing
    capital-related  capacity  costs.  Total  purchases  under the  Broad  River
    agreements  amounted to $37.7  million  and $21.2  million in 2002 and 2001,
    respectively.

    CP&L has various pay-for-performance  purchased power contracts with certain
    cogenerators  (qualifying  facilities)  for  approximately  300 megawatts of
    capacity  expiring at various  times  through 2009.  These  purchased  power
    contracts  generally provide for capacity and energy payments.  Payments for
    both  capacity and energy are  contingent  upon the  qualifying  facilities'
    ability to generate. Payments made under these contracts were $144.5 million
    in 2002, $145.1 million in 2001 and $168.4 million in 2000.

    CP&L has entered  into various  long-term  contracts  for coal,  gas and oil
    requirements   of  its  generating   plants.   Total  payments  under  these
    commitments were $694.0 million,  $675.2 million and $558.9 million in 2002,
    2001 and 2000, respectively.  Estimated annual payments for firm commitments
    of fuel  purchases  and  transportation  costs  under  these  contracts  are
    approximately $499.7 million, $434.0 million, $351.1 million, $312.1 million
    and $199.0 million for 2003 through 2007, respectively.

    B. Guarantees

    As a part of normal business,  CP&L enters into various agreements providing
    financial or  performance  assessments  to third  parties.  Such  agreements
    include,  for  example,  guarantees,  stand-by  letters of credit and surety
    bonds. These agreements are entered into primarily to support or enhance the
    creditworthiness  otherwise  attributed  to a  subsidiary  on a  stand-alone
    basis, thereby facilitating the extension of sufficient credit to accomplish
    the subsidiaries' intended commercial purposes.

    At  December  31, 2002 and 2001,  outstanding  guarantees  consisted  of the
    following (in millions):

                                December 31, 2002         December 31, 2001
                                -----------------         -----------------
    Standby letters of credit         $ 4.7                     $ 4.9
    Surety bonds                        0.6                       2.0
                                -----------------         -----------------
       Total                          $ 5.3                     $ 6.9
                                =================         =================

    Stand-by Letters of Credit
    CP&L has issued stand-by letters of credit to financial institutions for the
    benefit  of third  parties  that have  extended  credit to CP&L and  certain
    subsidiaries.  These  letters of credit have been issued  primarily  for the
    purpose of supporting payments of trade payables, securing performance under
    contracts  and  interest  payments on  outstanding  debt  obligations.  If a
    subsidiary  does not pay  amounts  when due  under a covered  contract,  the
    counterparty may present its claim for payment to the financial institution,
    which will in turn  request  payment  from  CP&L.  Any  amounts  owed by its
    subsidiaries are reflected in the Consolidated Balance Sheets.

    Surety Bonds
    At  December  31,  2002,  CP&L had $0.6  million in surety  bonds  purchased
    primarily for purposes such as providing  worker  compensation  coverage and
    obtaining licenses, permits and rights-of-way. To the extent liabilities are
    incurred,  as a result of the activities  covered by the surety bonds,  such
    liabilities are included in the Consolidated Balance Sheets.

                                       149
<PAGE>

    As of December 31, 2002,  management does not believe  conditions are likely
    for performance under these agreements.

    C. Insurance

    CP&L 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, CP&L 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 $2.0 billion on
    the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.

    Insurance coverage against  incremental costs of replacement power resulting
    from  prolonged  accidental  outages  at  nuclear  generating  units is also
    provided through membership in NEIL. CP&L is insured thereunder, following a
    twelve-week  deductible  period,  for 52 weeks in the amount of $3.5 million
    per week at each of the nuclear  units.  An additional 110 weeks of coverage
    is  provided  at 80% of the above  weekly  amount.  For the  current  policy
    period,  CP&L is  subject  to  retrospective  premium  assessments  of up to
    approximately  $24.1  million  with respect to the primary  coverage,  $25.7
    million  with  respect to the  decontamination,  decommissioning  and excess
    property coverage,  and $17.4 million for the incremental  replacement power
    costs  coverage,  in the event covered losses at insured  facilities  exceed
    premiums,  reserves,  reinsurance  and other  NEIL  resources.  Pursuant  to
    regulations of the Nuclear  Regulatory  Commission  (NRC),  CP&L'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 decontaminate,  before any proceeds can be used for
    decommissioning,  plant repair or  restoration.  CP&L is  responsible to the
    extent losses may exceed limits of the coverage described above.

    CP&L is insured against public  liability for a nuclear incident up to $9.55
    billion per occurrence.  Under the current  provisions of the Price Anderson
    Act, which limits liability for accidents at nuclear power plants,  CP&L, as
    an owner of nuclear units,  can be assessed for a portion of any third-party
    liability  claims arising from an accident at any  commercial  nuclear power
    plant in the United States.  In the event that public  liability claims from
    an insured nuclear incident exceed $300 million (currently available through
    commercial insurers), CP&L would be subject to pro rata assessments of up to
    $88.1  million  for each  reactor  owned  per  occurrence.  Payment  of such
    assessments would be made over time as necessary to limit the payment in any
    one year to no more than $10 million per reactor owned. Congress is expected
    to approve revisions to the Price Anderson Act in the first quarter of 2003,
    that will include  increased  limits and assessments per reactor owned.  The
    final outcome of this matter cannot be predicted at this time.

    There have been recent  revisions  made to the nuclear  property and nuclear
    liability insurance policies regarding the maximum recoveries  available for
    multiple  terrorism  occurrences.  Under the NEIL  policies,  if there  were
    multiple  terrorism  losses  occurring  within one year after the first loss
    from  terrorism,  NEIL would make available one industry  aggregate limit of
    $3.2  billion,   along  with  any  amounts  it  recovers  from  reinsurance,
    government indemnity or other sources up to the limits for each claimant. If
    terrorism  losses occurred beyond the one-year  period,  a new set of limits
    and  resources  would apply.  For nuclear  liability  claims  arising out of
    terrorist acts, the primary level available through  commercial  insurers is
    now subject to an industry aggregate limit of $300 million. The second level
    of coverage obtained through the assessments  discussed above would continue
    to apply to losses  exceeding  $300  million and would  provide  coverage in
    excess of any diminished primary limits due to the terrorist acts aggregate.

    CP&L  self-insures its transmission and distribution  lines against loss due
    to storm damage and other natural disasters.

    D. Claims and Uncertainties

    1. CP&L is  subject  to  federal,  state and  local  regulations  addressing
    hazardous  and  solid  waste  management,  air and water  quality  and other
    environmental matters.

                                       150
<PAGE>

    Hazardous and Solid Waste Management

    Various  organic  materials  associated  with the production of manufactured
    gas,  generally  referred to as coal tar, are  regulated  under  federal and
    state  laws.  The  principal  regulatory  agency that is  responsible  for a
    specific former  manufactured  gas plant (MGP) site depends largely upon the
    state in which the site is  located.  There are  several  MGP sites to which
    CP&L  has some  connection.  In this  regard,  CP&L  and  other  potentially
    responsible  parties,  are participating in investigating and, if necessary,
    remediating  former MGP sites with several regulatory  agencies,  including,
    but not limited to, the U.S.  Environmental  Protection Agency (EPA) and the
    North Carolina Department of Environment and Natural Resources,  Division of
    Waste  Management  (DWM).  In  addition,  CP&L is  periodically  notified by
    regulators  such as the EPA and various state agencies of their  involvement
    or potential  involvement in sites,  other than MGP sites,  that may require
    investigation and/or remediation.

    There are 12 former MGP sites and 14 other sites  associated  with CP&L that
    have required or are anticipated to require investigation and/or remediation
    costs.  CP&L received  insurance  proceeds to address costs  associated with
    CP&L  environmental  liabilities  related to its involvement with MGP sites.
    All eligible  expenses  related to these are charged against a specific fund
    containing  these  proceeds.  As of December  31, 2002,  approximately  $8.0
    million  remains  in this  centralized  fund with a related  accrual of $8.0
    million  recorded for the associated  expenses of environmental  issues.  As
    CP&L's share of costs for  investigating  and remediating these sites become
    known,  the fund is assessed to determine  if  additional  accruals  will be
    required.  CP&L does not  believe  that it can  provide an  estimate  of the
    reasonably  possible  total  remediation  costs  beyond what  remains in the
    environmental  insurance  recovery  fund.  This is due to the fact  that the
    sites  are at  different  stages:  investigation  has not begun at 15 sites,
    investigation  has begun but remediation  cannot be estimated at seven sites
    and four sites have begun remediation. CP&L measures its liability for these
    sites based on available  evidence including its experience in investigating
    and remediating  environmentally  impaired sites. The process often involves
    assessing and developing  cost-sharing  arrangements  with other potentially
    responsible  parties.  Once the  environmental  insurance  recovery  fund is
    depleted,  CP&L will accrue costs for the sites to the extent its  liability
    is  probable  and the costs can be  reasonably  estimated.  Presently,  CP&L
    cannot determine the total costs that may be incurred in connection with the
    remediation  of all sites.  According to current  information,  these future
    costs at the CP&L sites are not expected to be material to CP&L's  financial
    condition or results of  operations.  A  rollforward  of the balance in this
    fund  is not  provided  due to the  immateriality  of this  activity  in the
    periods presented.

    CP&L has filed  claims  with its  general  liability  insurance  carriers to
    recover costs arising out of actual or potential environmental  liabilities.
    Some claims  have  settled and others are still  pending.  While  management
    cannot predict the outcome of these matters,  the outcome is not expected to
    have a material effect on the consolidated  financial position or results of
    operations.

    CP&L is also  currently  in the  process of  assessing  potential  costs and
    exposures at other  environmentally  impaired  sites. As the assessments are
    developed and  analyzed,  CP&L will accrue costs for the sites to the extent
    the costs are probable and can be reasonably estimated.

    Air Quality

    There has been and may be further  proposed  federal  legislation  requiring
    reductions in air  emissions for nitrogen  oxides,  sulfur  dioxide,  carbon
    dioxide and mercury.  Some of these proposals establish nation-wide caps and
    emission   rates   over  an   extended   period  of  time.   This   national
    multi-pollutant  approach to air pollution control could involve significant
    capital  costs  which could be  material  to CP&L's  consolidated  financial
    position or results of  operations.  Some companies may seek recovery of the
    related  cost  through  rate  adjustments  or  similar  mechanisms.  Control
    equipment  that  will be  installed  on  North  Carolina  fossil  generating
    facilities as part of the North  Carolina  legislation  discussed  below may
    address some of the issues outlined above.  However, CP&L cannot predict the
    outcome of this matter.

                                       151
<PAGE>

    The EPA is  conducting  an  enforcement  initiative  related  to a number of
    coal-fired   utility  power  plants  in  an  effort  to  determine   whether
    modifications  at  those  facilities  were  subject  to  New  Source  Review
    requirements  or New Source  Performance  Standards under the Clean Air Act.
    CP&L was asked to provide  information to the EPA as part of this initiative
    and  cooperated in providing the  requested  information.  The EPA initiated
    civil enforcement  actions against other  unaffiliated  utilities as part of
    this  initiative.  Some of these actions  resulted in settlement  agreements
    calling for  expenditures,  ranging  from $1.0  billion to $1.4  billion.  A
    utility that was not subject to a civil  enforcement  action settled its New
    Source  Review  issues  with  the EPA for  $300  million.  These  settlement
    agreements have generally  called for  expenditures to be made over extended
    time  periods,  and some of the  companies  may seek recovery of the related
    cost through rate adjustments or similar mechanisms. CP&L cannot predict the
    outcome of this matter.

    In 1998, the EPA published a final rule addressing the regional transport of
    ozone.  This  rule is  commonly  known as the NOx SIP Call.  The EPA's  rule
    requires 23  jurisdictions,  including  North  Carolina,  South Carolina and
    Georgia,  to further reduce  nitrogen  oxide  emissions in order to attain a
    pre-set  state  NOx  emission  levels  by May 31,  2004.  CP&L is  currently
    installing controls necessary to comply with the rule. Capital  expenditures
    needed  to meet  these  measures  in North and South  Carolina  could  reach
    approximately  $370  million,  which has not been  adjusted  for  inflation.
    Increased  operation and maintenance  costs relating to the NOx SIP Call are
    not  expected  to be  material  to CP&L's  results  of  operations.  Further
    controls  are  anticipated  as  electricity  demand  increases.  CP&L cannot
    predict the outcome of this matter.

    In July 1997, the EPA issued final regulations establishing a new eight-hour
    ozone standard.  In October 1999, the District of Columbia  Circuit Court of
    Appeals  ruled against the EPA with regard to the federal  eight-hour  ozone
    standard.  The U.S.  Supreme  Court has  upheld,  in part,  the  District of
    Columbia Circuit Court of Appeals decision. Designation of areas that do not
    attain the standard is proceeding,  and further litigation and rulemaking on
    this and other  aspects of the  standard  are  anticipated.  North  Carolina
    adopted the federal  eight-hour  ozone  standard and is proceeding  with the
    implementation  process.  North Carolina has promulgated final  regulations,
    which will require CP&L to install nitrogen oxide controls under the State's
    eight-hour  standard.  The costs of those  controls are included in the $370
    million cost estimate set forth above.  However,  further technical analysis
    and rulemaking may result in a requirement  for additional  controls at some
    units. CP&L cannot predict the outcome of this matter.

    The EPA published a final rule approving  petitions under Section 126 of the
    Clean Air Act. This rule as originally  promulgated required certain sources
    to make  reductions in nitrogen  oxide  emissions by May 1, 2003.  The final
    rule also includes a set of regulations that affect nitrogen oxide emissions
    from  sources  included  in the  petitions.  The North  Carolina  coal-fired
    electric generating plants are included in these petitions. Acceptable state
    plans  under the NOx SIP Call can be approved in lieu of the final rules the
    EPA approved as part of the 126  petitions.  CP&L,  other  utilities,  trade
    organizations  and other states  participated in litigation  challenging the
    EPA's  action.  On May 15, 2001,  the District of Columbia  Circuit Court of
    Appeals ruled in favor of the EPA, which will require North Carolina to make
    reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in
    its May 15th decision  rejected the EPA's  methodology  for  estimating  the
    future growth factors the EPA used in calculating  the emissions  limits for
    utilities.  In August  2001,  the Court  granted a request by CP&L and other
    utilities  to  delay  the  implementation  of  the  126  Rule  for  electric
    generating  units pending  resolution by the EPA of the growth factor issue.
    The Court's order tolls the three-year  compliance period (originally set to
    end on May 1, 2003) for electric  generating  units as of May 15,  2001.  On
    April 30, 2002, the EPA published a final rule harmonizing the dates for the
    Section 126 Rule and the NOx SIP Call.  In addition,  the EPA  determined in
    this  rule  that  the  future  growth  factor  estimation   methodology  was
    appropriate. The new compliance date for all affected sources is now May 31,
    2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP
    Call rule and has indicated it will rescind the Section 126 rule in a future
    rule making. CP&L expects a favorable outcome of this matter.

    On June 20, 2002,  legislation  was enacted in North Carolina  requiring the
    state's  electric  utilities to reduce the  emissions of nitrogen  oxide and
    sulfur dioxide from coal-fired power plants.  CP&L expects its capital costs
    to meet these emission targets will be  approximately  $813 million by 2013.
    CP&L currently has approximately 5,100 MW of coal-fired  generation in North
    Carolina that is affected by this legislation.  The legislation requires the
    emissions  reductions to be completed in phases by 2013, and applies to each
    utility's total system rather than setting requirements for individual power
    plants.  The  legislation  also freezes the  utilities'  base rates for five
    years  unless  there are  extraordinary  events  beyond  the  control of the
    utilities or unless the utilities  persistently earn a return  substantially
    in excess of the rate of return established and found reasonable by the NCUC
    in the utilities' last general rate case.  Further,  the legislation  allows
    the utilities to recover from their retail  customers the projected  capital
    costs  during  the  first  seven  years  of the  10-year  compliance  period
    beginning  on January 1, 2003.  The  utilities  must recover at least 70% of
    their  projected  capital  costs during the  five-year  rate freeze  period.
    Pursuant to the new law,  CP&L entered  into an agreement  with the state of
    North Carolina to transfer to the state all future  emissions  allowances it
    generates  from  over-complying  with the new federal  emission  limits when
    these units are completed.  The new law also requires the state to undertake
    a study of mercury and carbon  dioxide  emissions  in North  Carolina.  CP&L
    cannot  predict  the future  regulatory  interpretation,  implementation  or
    impact of this new law.

                                       152
<PAGE>

    The Kyoto  Protocol  was  adopted in 1997 by the  United  Nations to address
    global  climate  change by reducing  emissions  of carbon  dioxide and other
    greenhouse  gases.  The United  States has not adopted  the Kyoto  Protocol,
    however,  a number of carbon dioxide  emissions  control proposals have been
    advanced in Congress and by the Bush administration. The Bush administration
    favors  voluntary  programs.  Reductions in carbon dioxide  emissions to the
    levels specified by the Kyoto Protocol and some legislative  proposals could
    be  materially  adverse to CP&L's  financials  and  operations if associated
    costs cannot be recovered from customers.  CP&L favors the voluntary program
    approach  recommended by the  administration,  and is evaluating options for
    the reduction,  avoidance,  and sequestration of greenhouse gases.  However,
    CP&L cannot predict the outcome of this matter.

    In 1997,  the EPA's  Mercury  Study  Report and  Utility  Report to Congress
    conveyed  that mercury is not a risk to the average  American and  expressed
    uncertainty  about whether  reductions in mercury  emissions from coal-fired
    power plants would reduce human  exposure.  Nevertheless,  EPA determined in
    2000 that regulation of mercury  emissions from coal-fired  power plants was
    appropriate.  EPA  is  currently  developing  a  Maximum  Available  Control
    Technology  (MACT)  standard,  which is expected to become final in December
    2004, with compliance in 2008.  Achieving  compliance with the MACT standard
    could be materially  adverse to CP&L's  financials and operations.  However,
    CP&L cannot predict the outcome of this matter.

    2. CP&L,  like other  electric  power  companies in North  Carolina,  pays a
    franchise  tax  levied  by the  state  pursuant  to North  Carolina  General
    Statutes ss. 105-116,  a state-level  annual  franchise tax (State Franchise
    Tax).  Part of the revenue  generated by the State Franchise Tax is required
    by North Carolina  General  Statutes ss.  105-116.1(b)  to be distributed to
    North Carolina cities in which CP&L maintains facilities.  CP&L has paid and
    continues  to pay the State  Franchise  Tax to the state when such taxes are
    due. However,  pursuant to an Executive Order issued on February 5, 2002, by
    the  Governor  of  North  Carolina,   the  Secretary  of  Revenue   withheld
    distributions  of State Franchise Tax revenues to cities for two quarters of
    fiscal year 2001-2002 in an effort to balance the state's budget.

    In response to the state's  failure to  distribute  the State  Franchise Tax
    proceeds,   certain  cities  in  which  CP&L  maintains  facilities  adopted
    municipal  franchise  tax  ordinances  purporting  to impose on CP&L a local
    franchise  tax. The local taxes are intended to be collected  for as long as
    the state  withholds  distribution  of the State Franchise Tax proceeds from
    the cities. The first local tax payments were due August 15, 2002. On August
    2, 2002,  CP&L  filed a lawsuit  against  the  cities  seeking to enjoin the
    enforcement of the local taxes and to have the local ordinances  struck down
    because  the  ordinances  are beyond the  cities'  statutory  authority  and
    violate provisions of the North Carolina and United States Constitutions.

    On September  14, 2002,  the  Governor of North  Carolina  signed into law a
    provision  that prevents  cities and counties  from levying local  franchise
    taxes on electric  utilities.  This new  legislation  makes the lawsuit CP&L
    filed in August  against  certain  cities that were seeking to enforce local
    franchise  tax  ordinances  moot.  As a  result  of the  enactment  of  this
    legislation,  the parties  have agreed to an Order of  Dismissal by Consent,
    which has been  signed  by the  judge  and filed  with the Clerk of Court in
    Caswell County.

    3. As required under the Nuclear Waste Policy Act of 1982, CP&L entered into
    a contract  with the DOE under  which the DOE agreed to begin  taking  spent
    nuclear  fuel by no later than  January 31,  1998.  All  similarly  situated
    utilities were required to sign the same standard contract.

    In April 1995, the DOE issued a final interpretation that it did not have an
    unconditional  obligation to take spent nuclear fuel by January 31, 1998. In
    Indiana &  Michigan  Power v. DOE,  the Court of Appeals  vacated  the DOE's
    final interpretation and ruled that the DOE had an unconditional  obligation
    to begin  taking  spent  nuclear  fuel.  The Court did not  specify a remedy
    because the DOE was not yet in default.

                                       153
<PAGE>

    After the DOE failed to comply with the decision in Indiana & Michigan Power
    v. DOE, a group of  utilities  petitioned  the Court of Appeals in  Northern
    States  Power  (NSP) v. DOE,  seeking  an order  requiring  the DOE to begin
    taking spent  nuclear  fuel by January 31,  1998.  The DOE took the position
    that its delay was  unavoidable,  and the DOE was excused  from  performance
    under the terms and conditions of the contract. The Court of Appeals did not
    order the DOE to begin taking spent nuclear fuel, stating that the utilities
    had a  potentially  adequate  remedy by filing a claim for damages under the
    contract.

    After the DOE failed to begin taking spent nuclear fuel by January 31, 1998,
    a group of utilities filed a motion with the Court of Appeals to enforce the
    mandate in NSP v. DOE. Specifically, this group of utilities asked the Court
    to permit the utilities to escrow their waste fee payments, to order the DOE
    not to use the waste fund to pay damages to the utilities,  and to order the
    DOE to establish a schedule for disposal of spent  nuclear  fuel.  The Court
    denied  this motion  based  primarily  on the  grounds  that a review of the
    matter was premature,  and that some of the requested  remedies fell outside
    of the mandate in NSP v. DOE.

    Subsequently,  a number of utilities each filed an action for damages in the
    Federal Court of Claims.  In a recent  decision,  the U.S.  Circuit Court of
    Appeals  (Federal  Circuit) ruled that utilities may sue the DOE for damages
    in the Federal Court of Claims  instead of having to file an  administrative
    claim with DOE. CP&L is in the process of evaluating  whether it should file
    a similar action for damages.

    CP&L also  continues  to monitor  legislation  that has been  introduced  in
    Congress  which might provide some limited  relief.  CP&L cannot predict the
    outcome of this matter.

    With certain  modifications and additional approval by the NRC, CP&L's spent
    nuclear fuel storage  facilities will be sufficient to provide storage space
    for spent fuel generated on its system through the expiration of the current
    operating  licenses for all of its nuclear  generating units.  Subsequent to
    the  expiration  of these  licenses,  dry  storage  may be  necessary.  CP&L
    obtained NRC approval to use additional storage space at the Harris Plant in
    December 2000.

    4. CP&L is involved in various  litigation matters in the ordinary course of
    business,  some of which involve  substantial  amounts.  Where  appropriate,
    accruals  have been made in  accordance  with  SFAS No. 5,  "Accounting  for
    Contingencies,"  to provide for such matters.  In the opinion of management,
    the final  disposition  of  pending  litigation  would  not have a  material
    adverse  effect on CP&L's  consolidated  results of  operations or financial
    position.

                                       154
<PAGE>

INDEPDENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.

We have audited the consolidated balance sheets of Progress Energy, Inc. and its
subsidiaries  as of  December  31, 2002 and 2001,  and the related  consolidated
statements of income,  changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2002 and have issued our report
thereon  dated  February 12, 2003 (which  expresses an  unqualified  opinion and
includes an explanatory  paragraph  referring to the Company's change in 2002 in
its method of accounting for goodwill);  such consolidated  financial statements
and report are  included  herein.  Our audits  also  included  the  consolidated
financial statement schedule of the Company, listed in Item 8. This consolidated
financial statement schedule is the responsibility of the Company's  management.
Our responsibility is to express an opinion based on our audits. In our opinion,
such consolidated  financial statement schedule,  when considered in relation to
the basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.


/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003

                                      155
<PAGE>

INDEPENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY:

We have audited the consolidated  balance sheets and schedules of capitalization
of Carolina Power & Light Company and its subsidiaries (CP&L) as of December 31,
2002  and  2001,  and  the  related   consolidated   statements  of  income  and
comprehensive  income,  retained earnings,  and cash flows for each of the three
years in the period ended  December 31, 2002 and have issued our report  thereon
dated February 12, 2003 such  consolidated  financial  statements and report are
included herein. Our audits also included the consolidated  financial  statement
schedule  of CP&L  listed  in  Item 8.  This  consolidated  financial  statement
schedule is the  responsibility of CP&L's  management.  Our responsibility is to
express  an opinion  based on our  audits.  In our  opinion,  such  consolidated
financial statement schedule, when considered in relation to the basic financial
statements  taken as a whole,  presents  fairly  in all  material  respects  the
information set forth therein.


/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003


                                      156
<PAGE>


                              PROGRESS ENERGY, INC.
                 Schedule II - Valuation and Qualifying Accounts
              For the Years Ended December 31, 2002, 2001 and 2000
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


                            Balance at        Additions                                               Balance at
                            Beginning         Charged to      Other                                   End of
        Description         of Period         Expenses        Additions          Deductions           Period
---------------------------------------------------------------------------------------------------------------

Year Ended
   December 31, 2002

 Uncollectible accounts     $ 38,661,474    $ 14,862,349     $          -       $ (13,925,249)  (a)  $ 39,598,574
 Fossil dismantlement
   reserve                   140,515,975       1,104,008                -                   -         141,619,983
 Nuclear refueling
   outage reserve                346,000       9,735,000                -            (480,000)  (b)     9,601,000


Year Ended
   December 31, 2001

 Uncollectible accounts     $ 26,292,093    $ 11,986,565     $ 19,443,822  (c)  $ (19,061,006)  (a)  $ 38,661,474
 Fossil dismantlement
   reserve                   134,622,258       5,899,357                -              (5,640)        140,515,975
 Nuclear refueling
   outage reserve             10,835,000      17,281,000                -         (27,770,000)  (b)       346,000


Year Ended
   December 31, 2000

 Uncollectible accounts     $ 13,926,483    $ 13,799,022      $ 8,254,368  (d)  $  (9,687,780)  (a)  $ 26,292,093
 Fossil dismantlement
   reserve                             -         189,497      134,432,761  (d)              -         134,622,258
 Nuclear refueling
   outage reserve                      -         884,000       10,591,000  (d)       (640,000)  (b)    10,835,000
</TABLE>

(a)  Represents write-off of uncollectible accounts, net of recoveries.
(b)  Represents payments of actual expenditures related to the outages.
(c)  Represents the  reclassification of Rail Services'  uncollectible  accounts
     from Net Assets Held for Sale.
(d)  Represents acquisition of FPC on November 30, 2000.


                                      157
<PAGE>

                         CAROLINA POWER & LIGHT COMPANY
                     Schedule II - Valuation and Qualifying
          Accounts For the Years Ended December 31, 2002, 2001 and 2000
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                              Balance at     Additions                                                Balance at
                              Beginning      Charged to       Other                                   End of
         Description          of Period      Expense          Additions            Deductions         Period
-----------------------------------------------------------------------------------------------------------------

Year Ended
   December 31, 2002

  Uncollectible accounts    $ 12,246,049    $  8,203,215     $       -          $  (9,156,225) (a)   $ 11,293,039


Year Ended
   December 31, 2001

  Uncollectible accounts    $ 16,976,093    $  3,921,255     $       -          $  (8,651,299) (a)   $ 12,246,049


Year Ended
   December 31, 2000

  Uncollectible accounts    $ 16,809,765    $ 12,450,000     $       -          $ (12,283,672) (b)   $ 16,976,093

</TABLE>

(a)  Represents write-off of uncollectible accounts, net of recoveries.
(b)  Represents transfer of uncollectible account balances for SRS, NCNG, Monroe
     Power and PVI to Progress  Energy on July 1, 2000 of  $2,846,873 as well as
     write-off of uncollectible accounts, net of recoveries of $9,436,799.


                                      158
<PAGE>

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

As a result of the acquisition of Florida Progress and Florida Power by Progress
Energy,  management  decided  to  retain  Deloitte  &  Touche  LLP  (D&T) as its
independent  public  accountants.  D&T  has  served  as the  independent  public
accountants  for Progress  Energy for over fifty years.  On March 21, 2001,  the
Audit  Committee  of the Board of Directors  approved  this  recommendation  and
formally  elected to (i) engage D&T as the  independent  accountants for FPC and
Florida Power and (ii) dismiss KPMG LLP (KPMG) as such independent accountants.

KPMG's reports on FPC's and Florida  Power's  financial  statements for 2000 and
1999 (the last two  fiscal  years of KPMG's  engagement)  contained  no  adverse
opinion or a  disclaimer  of opinion,  and were not  qualified or modified as to
uncertainty,  audit scope or accounting principles. D&T became FPC's and Florida
Power's  independent  accountants  upon the  completion  of the 2000  audit  and
issuance of the related financial statements.

During  FPC's and  Florida  Power's  last two  fiscal  years and the  subsequent
interim period to the date hereof,  there were no disagreements  between FPC and
Florida  Power and KPMG on any matter of  accounting  principles  or  practices,
financial  statement   disclosure,   or  auditing  scope  or  procedure,   which
disagreements,  if not resolved to the  satisfaction of KPMG,  would have caused
them to make reference to the subject matter of the  disagreements in connection
with their report on the financial statements for such years.

KPMG  furnished a letter  addressed to the  Securities  and Exchange  Commission
stating that it agreed with the above statements made by Progress Energy in this
Form 10-K.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     a)   Information on Progress  Energy,  Inc.'s directors is set forth in the
          Progress Energy 2002 definitive  proxy statement dated March 31, 2003,
          and incorporated by reference herein.  Information CP&L's directors is
          set forth in the CP&L 2002 definitive  proxy statement dated March 31,
          2003, and incorporated by reference herein.

     b)   Information on both Progress Energy's and CP&L's executive officers is
          set forth in PART I and incorporated by reference herein.

     c)   The Company  has  adopted a Code of Ethics that  applies to all of its
          employees,  including its Chief  Executive  Officer,  Chief  Financial
          Officer and Controller (or persons performing similar functions).  The
          Company's Code of Ethics is posted on its Internet  website and can be
          accessed at www.progress-energy.com. With respect to any amendment to,
          or a waiver from,  any provision of its Code of Ethics that applies to
          the officers  noted above and that relates to any  standards  that are
          reasonably designed to deter wrongdoing and to promote:

          -    honest and ethical  conduct,  including  the ethical  handling of
               actual or apparent  conflicts  of interest  between  personal and
               professional relationships;

          -    full, fair,  accurate,  timely and  understandable  disclosure in
               reports and  documents  that a registrant  files with, or submits
               to,  the  SEC  and in  other  public  communications  made by the
               Company;

          -    compliance  with   applicable   governmental   laws,   rules  and
               regulations;

          -    the prompt  internal  reporting of  violations  of the code to an
               appropriate  person or persons  identified in the Code of Ethics;
               and

          -    accountability for adherence to the Code of Ethics,

          the Company intends to post information about such amendment or waiver
          on its Internet website.

                                      159

<PAGE>

ITEM 11.   EXECUTIVE COMPENSATION

     Information on Progress Energy, Inc.'s executive  compensation is set forth
     in the Progress  Energy 2002  definitive  proxy  statement  dated March 31,
     2003, and incorporated by reference herein. Information on Carolina Power &
     Light  Company's  executive  compensation  is set  forth in the  CP&L  2002
     definitive  proxy  statement  dated March 31,  2003,  and  incorporated  by
     reference herein.

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

          a)   Information  regarding any person Progress Energy,  Inc. knows to
               be the  beneficial  owner of more than five (5%)  percent  of any
               class  of  its  voting  securities  is  set  forth  in  its  2002
               definitive   proxy   statement,   dated  March  31,   2003,   and
               incorporated herein by reference.

               Information  regarding any person  Carolina Power & Light Company
               knows to be the  beneficial  owner of more than five (5%) percent
               of any class of its  voting  securities  is set forth in its 2002
               definitive   proxy   statement,   dated  March  31,   2003,   and
               incorporated herein by reference.

          b)   Information  on security  ownership of the Progress  Energy's and
               Carolina Power & Light  Company's  management is set forth in the
               Progress Energy and CP&L 2002 definitive  proxy  statements dated
               March 31, 2003, and incorporated by reference herein.

          c)   Information on the equity  compensation  plans of Progress Energy
               is  set  forth  under  the  heading  "Equity   Compensation  Plan
               Information"  in  the  Progress  Energy  2002  definitive   proxy
               statement  dated March 31,  2002 and  incorporated  by  reference
               herein.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

          Information on certain  relationships and related  transactions is set
          forth in the Progress Energy and CP&L 2002 definitive proxy statements
          dated March 31, 2003, and incorporated by reference herein.

ITEM 14.   CONTROLS AND PROCEDURES

Progress Energy, Inc.

Within the 90 days  prior to the filing  date of this  report,  Progress  Energy
carried out an evaluation,  under the supervision and with the  participation of
its management,  including  Progress  Energy's chief executive officer and chief
financial officer,  of the effectiveness of the design and operation of Progress
Energy's  disclosure  controls and procedures  pursuant to Rule 13a-14 under the
Securities  Exchange Act of 1934. Based upon that evaluation,  Progress Energy's
chief  executive   officer  and  chief  financial  officer  concluded  that  its
disclosure  controls and  procedures  are  effective in timely  alerting them to
material  information  relating to Progress Energy  (including its  consolidated
subsidiaries) required to be included in its periodic SEC filings.

Since the date of the  evaluation,  there  have been no  significant  changes in
Progress Energy's internal controls or in other factors that could significantly
affect these controls.

Carolina Power & Light Company

Within the 90 days prior to the filing date of this report,  CP&L carried out an
evaluation,  under the supervision and with the participation of its management,
including  CP&L's chief executive  officer and chief financial  officer,  of the
effectiveness  of the design and  operation  of CP&L's  disclosure  controls and
procedures  pursuant to Rule 13a-14 under the  Securities  Exchange Act of 1934.
Based upon that evaluation,  CP&L's chief executive  officer and chief financial
officer  concluded that its disclosure  controls and procedures are effective in
timely  alerting them to material  information  relating to CP&L  (including its
consolidated subsidiaries) required to be included in its periodic SEC filings.

Since the date of the  evaluation,  there  have been no  significant  changes in
CP&L's  internal  controls or in other factors that could  significantly  affect
these controls.

                                      160
<PAGE>

                                     PART IV


ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

          a)   The following documents are filed as part of the report:

               1. Consolidated Financial Statements Filed:
                    See  ITEM  8  -   Consolidated   Financial   Statements  and
                    Supplementary Data

               2. Consolidated Financial Statement Schedules Filed:
                    See  ITEM  8  -   Consolidated   Financial   Statements  and
                    Supplementary Data

               3. Exhibits Filed:
                    See EXHIBIT INDEX

          b)   Reports on Form 8-K or Form 8-K/A filed during or with respect to
               the last quarter of 2002 and the portion of the first  quarter of
               2003 prior to the filing of this Form 10-K:

               Progress Energy, Inc.

                          Financial
                 Item     Statements
               Reported    Included      Date of Event          Date Filed
               --------    --------      -------------          ----------
                  5           No        October 16, 2002     November 6, 2002
                  5           No        November 7, 2002     November 7, 2002
                  5           No        November 6, 2002     November 13, 2002
                  9           No        December 2, 2002     December 2, 2002
                  5           No        February 7, 2003     February 12, 2003
                  7          Yes        February 18, 2003    February 18, 2003

               Carolina Power & Light Company

                          Financial
                 Item     Statements
               Reported    Included       Date of Event         Date Filed
               --------    --------       -------------         ----------
                  5           No        January 1, 2003      January 3, 2003
                  7          Yes        February 18, 2003    February 18, 2003


                                      161
<PAGE>

PROGRESS ENERGY, INC. RISK FACTORS

In this section,  unless the context indicates  otherwise,  references to "our,"
"we," "us" or similar terms refer to Progress Energy,  Inc. and its consolidated
subsidiaries.  Investing in our securities  involves risks,  including the risks
described below,  that could affect the energy  industry,  as well as us and our
business.  Although we have tried to discuss key  factors,  please be aware that
other risks may prove to be important in the future. New risks may emerge at any
time and we cannot  predict  such risks or estimate the extent to which they may
affect our financial performance.  Before purchasing our securities,  you should
carefully  consider the following risks and the other information in this Annual
Report, as well as the documents we file with the SEC from time to time. Each of
the  risks  described  below  could  result  in a  decrease  in the value of our
securities and your investment therein.

Risks Related to the Energy Industry
------------------------------------

We are  subject  to fluid and  complex  government  regulations  that may have a
negative impact on our business and our results of operations.

We are subject to comprehensive  regulation by several federal,  state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers.  We are required
to have  numerous  permits,  approvals and  certificates  from the agencies that
regulate  our  business.  We  believe  the  necessary  permits,   approvals  and
certificates  have  been  obtained  for our  existing  operations  and  that our
business is conducted in accordance with applicable laws; however, we are unable
to  predict  the impact on our  operating  results  from the  future  regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional   regulations  could  have  an  adverse  impact  on  our  results  of
operations.

The Federal Energy Regulatory  Commission ("FERC"),  the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental  Protection Agency ("EPA"), the North
Carolina Utilities  Commission  ("NCUC"),  the Florida Public Service Commission
("FPSC"), and the Public Service Commission of South Carolina ("SCPSC") regulate
many aspects of our utility  operations,  including  siting and  construction of
facilities,  customer  service and the rates that we can charge  customers.  Our
system is also subject to the  jurisdiction  of the SEC under the Public Utility
Holding  Company Act of 1935 ("PUHCA").  The rules and  regulations  promulgated
under PUHCA impose a number of  restrictions  on the  operations  of  registered
utility holding companies and their subsidiaries.  These restrictions  include a
requirement that, subject to a number of exceptions,  the SEC approve in advance
securities  issuances,  acquisitions  and  dispositions  of utility assets or of
securities of utility  companies,  and acquisitions of other  businesses.  PUHCA
also generally  limits the operations of a registered  holding company like ours
to a single  integrated  public utility system,  plus additional  energy-related
businesses.   Furthermore,   PUHCA  rules  require  that  transactions   between
affiliated  companies in a  registered  holding  company  system be performed at
cost, with limited exceptions.

We are unable to predict the impact on our business and  operating  results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.

We are subject to numerous  environmental laws and regulations that may increase
our cost of  operations,  impact or limit our  business  plans,  or expose us to
environmental liabilities.

We are subject to numerous  environmental  regulations affecting many aspects of
our present and future  operations,  including  air  emissions,  water  quality,
wastewater  discharges,   solid  waste  and  hazardous  waste.  These  laws  and
regulations  can  result in  increased  capital,  operating,  and  other  costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations.  These  laws and  regulations  generally  require  us to obtain and
comply with a wide variety of environmental licenses,  permits,  inspections and
other  approvals.  Both public  officials  and private  individuals  may seek to
enforce  applicable  environmental  laws and regulations.  We cannot predict the
outcome (financial or operational) of any related litigation that may arise.

In addition,  we may be a responsible party for environmental  clean up at sites
identified by a regulatory  body. We cannot predict with certainty the amount or
timing of all future  expenditures  related to environmental  matters because of
the  difficulty  of  estimating  clean up costs.  There is also  uncertainty  in
quantifying  liabilities under  environmental laws that impose joint and several
liability on all potentially responsible parties.

                                      162

<PAGE>

We cannot assure you that existing environmental regulations will not be revised
or that new regulations  seeking to protect the environment  will not be adopted
or become applicable to us. Revised or additional  regulations,  which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers,  could have a material
adverse effect on our results of operations.

Recent events in the energy  markets that are beyond our control have  increased
the level of public and  regulatory  scrutiny in our industry and in the capital
markets and have resulted in increased regulation and new accounting  standards.
The  reaction  to  these  events  may have  negative  impacts  on our  business,
financial condition and access to capital.

As a result of the energy  crisis in California  during the summer of 2001,  the
recent volatility of natural gas prices in North America,  the bankruptcy filing
by the Enron  Corporation,  recently  discovered  accounting  irregularities  of
certain public companies,  and  investigations by governmental  authorities into
energy trading activities,  companies in the regulated and nonregulated  utility
businesses have been under a generally increased amount of public and regulatory
scrutiny.  Recently discovered accounting  irregularities have caused regulators
and legislators to review current accounting  practices,  financial  disclosures
and  companies'  relationships  with their  independent  auditors.  The  capital
markets and  ratings  agencies  also have  increased  their  level of  scrutiny.
Additionally,  allegations  against  various energy trading  companies of "round
trip" or "wash" transactions,  which involve the simultaneous buying and selling
of the same  amount of power at the same  price  and  provide  no true  economic
benefit,  may have a negative  effect on the  industry.  We believe  that we are
complying  with all  applicable  laws,  and we have taken  steps to avoid  these
events,  but it is  difficult  or  impossible  to predict or control what effect
these  types of  disruptions  in the energy  markets  may have on our  business,
financial condition or our access to the capital markets.

Additionally,  it is unclear what laws or regulations may develop, and we cannot
predict the ultimate  impact of any future changes in accounting  regulations or
practices in general with respect to public companies, the energy industry or in
our operations specifically.  Any such new accounting standards could impact the
way we are required to record revenues, expenses, assets and liabilities.  These
changes in  accounting  standards  could lead to  negative  impacts on  reported
earnings or increases in liabilities  that could,  in turn,  affect our reported
results of operations.

Deregulation or restructuring  in the electric  industry may result in increased
competition  and  unrecovered  costs that could  adversely  affect the financial
condition,  results  of  operations  or  cash  flows  of us and  our  utilities'
businesses.

Increased competition resulting from deregulation or restructuring efforts could
have a significant  adverse financial impact on us and our utility  subsidiaries
and  consequently  on our  results  of  operations  and  cash  flows.  Increased
competition  could also result in increased  pressure to lower costs,  including
the cost of  electricity.  Retail  competition  and the  unbundling of regulated
energy and gas service could have a significant  adverse  financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower  profit  margins  or  increased  costs  of  capital.  Because  we have not
previously operated in a competitive retail  environment,  we cannot predict the
extent and timing of entry by additional  competitors into the electric markets.
Movement toward  deregulation in North Carolina,  South Carolina and Florida has
slowed as a result of recent  developments,  including  developments  related to
electric  deregulation in California and other states. We cannot predict when we
will be subject to changes in legislation or regulation,  nor can we predict the
impact of these  changes on our  financial  condition,  results of operations or
cash flows.

One of the major issues to be resolved  from  deregulation  is who would pay for
stranded costs. Stranded costs are those costs and investments made by utilities
in order to meet their  statutory  obligation  to provide  electric  service but
which could not be recovered  through the market price of electricity  following
industry  restructuring.  The  amount  of such  stranded  costs  that  we  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 both
our electric  utilities and our gas utility are no longer  subject to cost-based
regulation  and it is not  possible to recover  stranded  costs,  our  financial
condition and results of operations could be adversely affected.

Additionally,  the electric  utility  industry  has  experienced  a  substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. As a result of the Public Utilities  Regulatory  Policies
Act of 1978 and the Energy  Policy  Act of 1992,  competition  in the  wholesale
electricity  market has  greatly  increased  due to a greater  participation  by
traditional  electricity suppliers,  non-utility  generators,  independent power
producers,  wholesale  power  marketers  and brokers,  as well as the trading of
energy  futures  contracts  on various  commodities  exchanges.  This  increased
competition  could  affect  our 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 us to expand our wholesale load, or
current  wholesale  customers  elect to  purchase  from  other  suppliers  after
existing  contracts  expire.  In 1996, the FERC issued new rules on transmission
service to facilitate competition in the wholesale market on a nationwide basis.
The  rules  give  greater  flexibility  and  more  choices  to  wholesale  power
customers. As a result of the changing regulatory environment and the relatively
low  barriers  to  entry,  we  expect  competition  to  steadily  increase.   As
competition  continues  to  increase,  our  financial  condition  and results of
operations could be adversely affected.

                                      163

<PAGE>

The uncertain outcome  regarding the timing,  creation and structure of regional
transmission  organizations,  or RTOs,  may  materially  impact  our  results of
operations, cash flows or financial condition.

On  December  20,  1999,  the FERC  issued  Order No.  2000 on RTOs.  This order
required public  utilities that own, operate or control  interstate  electricity
transmission facilities to file either a proposal to participate in an RTO or an
alternative  filing  describing  efforts and plans to  participate in an RTO. To
date, our electric utilities have responded to the order as follows:

     o    CP&L and other  investor-owned  utilities filed  applications with the
          FERC, the NCUC and the SCPSC for approval of an RTO,  currently  named
          GridSouth.

     o    Florida Power and other  investor-owned  utilities filed  applications
          with the FERC and the FPSC for  approval  of an RTO,  currently  named
          GridFlorida.

On November 7, 2001,  the FERC issued an order  providing  guidance on continued
processing of RTO filings.  In this order,  FERC recognized that it would not be
possible  for all RTOs to be  operational  by December  15, 2001 as set forth in
Order No. 2000; therefore,  the FERC stated that its future orders would address
the  establishment  of a timeline  for the RTO  progress  in each  region of the
country.

On July 31, 2002,  the FERC issued its Notice of Proposed  Rulemaking  in Docket
No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission
Service and Standard  Electricity Market Design ("SMD NOPR"). The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission owning utilities transfer control of their transmission  facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC-regulated  transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities  be required to meet  minimum  criteria  for  generating  reserves.  If
adopted as proposed,  the rules set forth in the SMD NOPR would materially alter
the manner in which  transmission and generation  services are provided and paid
for. We filed comments on November 15, 2002 and supplemental comments on January
10, 2003. On January 15, 2003,  the FERC announced the issuance of a White Paper
on SMD NOPR to be released in April 2003.  We plan to file comments to the White
Paper.  The FERC also has indicated  that it expects to issue final rules during
the third quarter of 2003.

Florida  Power is continuing to make  progress  towards the  development  of the
GridFlorida  RTO. CP&L and the other GridSouth  participants  withdrew their RTO
application  before the NCUC and the SCPSC  pending the review of the FERC's SMD
NOPR. A  determination  about  refiling will be made at a later date. The actual
structure of GridSouth,  GridFlorida or any  alternative  combined  transmission
structure,  as well as the  date it may  become  operational,  depends  upon the
resolution  of  all  regulatory   approvals  and  technical  issues.  Given  the
regulatory  uncertainty  of the ultimate  timing,  structure  and  operations of
GridSouth,  GridFlorida  or an alternate  combined  transmission  structure,  we
cannot predict  whether their creation will have any material  adverse effect on
our  future  consolidated  results  of  operations,   cash  flows  or  financial
condition.

Furthermore,  the  SMD  NOPR  presents  several  uncertainties,  including  what
percentage of our  investments in GridSouth and  GridFlorida  will be recovered,
how the elimination of transmission  charges,  as proposed in the SMD NOPR, will
impact us, and what amount of capital expenditures will be necessary to create a
new wholesale market.

Since  weather  conditions  directly  influence the demand for  electricity  and
natural  gas,  as well as the  price  of  energy  commodities,  our  results  of
operations,  financial condition, cash flows and ability to pay dividends on our
common stock can be  negatively  affected by changes in weather  conditions  and
severe weather.

Our results of operations,  financial  condition,  cash flows and ability to pay
dividends  on our common stock may be affected by changing  weather  conditions.
Weather conditions in our service territories,  primarily North Carolina,  South
Carolina, and Florida, directly influence the demand for electricity and natural
gas and affect the price of energy commodities.  Furthermore,  severe weather in
these states, such as hurricanes,  tornadoes,  severe thunderstorms and snow and
ice storms, can be destructive, causing outages, downed power lines and property
damage,  requiring us to incur additional and unexpected expenses and causing us
to lose generating revenues.

                                      164

<PAGE>

In 2002,  drought  conditions and related water  restrictions  affected numerous
electric  utilities in the southeast United States.  Drought  conditions and any
mandated water restrictions that could be implemented in response thereto, could
impact  a  small  percentage  of  our  generating   facilities,   including  our
hydroelectric  generating  facilities.  This may result in additional  expenses,
such as higher  fuel costs  and/or  purchased  power  expenses.  We  continue to
monitor weather patterns and will develop  contingency  plans, as necessary,  to
mitigate  the  impact  of  drought  conditions.  We do not have any  reliability
concerns  with our  generating  facilities  currently  and do not  expect  these
developments to have a material impact on our results of operations.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers,
and may also fluctuate on a seasonal or quarterly basis.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2002, commercial and industrial customers represented approximately
36.6% of our electric  revenues.  As a result,  changes in the  macroeconomy can
have  negative  impacts  on our  revenues.  As  our  commercial  and  industrial
customers  experience  economic  hardships,   our  revenues  can  be  negatively
impacted.

Electric  power  demand is generally a seasonal  business.  In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
As a  result,  our  overall  operating  results  in  the  future  may  fluctuate
substantially  on a seasonal basis.  The pattern of this  fluctuation may change
depending on the nature and location of  facilities  we acquire and the terms of
power sale contracts into which we enter. In addition, we have historically sold
less power, and  consequently  earned less income,  when weather  conditions are
milder.  While we believe that our North Carolina,  South Carolina,  and Florida
markets  complement  each other during normal seasonal  fluctuations,  unusually
mild weather  could  diminish our results of  operations  and harm our financial
condition.

Risks Related to Us and Our Business
------------------------------------

As a  holding  company,  we are  dependent  on  upstream  cash  flows  from  our
subsidiaries.  As a result, our ability to meet our ongoing and future financial
obligations  and to pay dividends on our common stock is primarily  dependent on
the earnings and cash flows of our operating  subsidiaries  and their ability to
pay upstream dividends or to repay funds to us.

We are a holding company. As such, we have no operations of our own. Our ability
to meet our  financial  obligations  and to pay dividends on our common stock at
the current  rate is  primarily  dependent on the earnings and cash flows of our
operating  subsidiaries and their ability to pay upstream  dividends or to repay
funds to us. Prior to funding us, our  subsidiaries  have financial  obligations
that must be satisfied,  including among others,  debt service,  preferred stock
dividends and obligations to trade creditors.

The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators.  Accordingly, our profit
margins  could be adversely  affected if we or our utility  subsidiaries  do not
control operating costs.

The NCUC, the SCPSC and the FPSC each exercises  regulatory authority for review
and approval of the retail  electric  power rates charged  within its respective
state.  State  regulators  may not allow our  utility  subsidiaries  to increase
retail  rates in the manner or to the extent  requested  by those  subsidiaries.
State  regulators  may also seek to reduce retail rates.  For example,  in March
2002,  Florida Power entered into a Stipulation  and  Settlement  Agreement that
required  Florida Power,  among other things,  to reduce its retail rates and to
operate  under a revenue  sharing plan through 2005 which  provides for possible
rate refunds to its retail customers.  The Agreement will also require increased
capital  expenditures  for Florida  Power's  Commitment to  Excellence  program.
However,  if  Florida  Power's  base rate  earnings  fall  below a 10% return on
equity,   Florida  Power  may  petition  the  FPSC  to  amend  its  base  rates.
Additionally, a North Carolina law passed in 2002 froze CP&L's base retail rates
for five years unless  there are  significant  cost changes due to  governmental
action,  significant  expenditures  due to force majeure or other  extraordinary
events beyond the control of CP&L. The same  legislation  required a significant
increase  in  capital  expenditures  over the next  several  years for clean air
improvements.  The cash costs incurred by our utility subsidiaries are generally
not  subject  to  being  fixed  or  reduced  by state  regulators.  Our  utility
subsidiaries will also require dedicated capital expenditures. Thus, our ability
to maintain our profit margins  depends upon stable demand for  electricity  and
our efforts to manage our costs.

There are  inherent  potential  risks in the  operation  of nuclear  facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could  result in fines or the shutdown of our nuclear  units,  which may present
potential exposures in excess of our insurance coverage.

                                      165

<PAGE>

We own and operate  five  nuclear  units  through our  subsidiaries,  CP&L (four
units)  and  Florida  Power  (one  unit),  that  represent  approximately  4,100
megawatts,  or 19%,  of our  generation  capacity.  Our nuclear  facilities  are
subject to  environmental,  health and  financial  risks such as the  ability to
dispose of spent nuclear fuel, the ability to maintain adequate capital reserves
for decommissioning, potential liabilities arising out of the operation of these
facilities,  and the costs of securing the facilities against possible terrorist
attacks. We maintain  decommissioning  trusts and external insurance coverage to
minimize the  financial  exposure to these risks;  however,  it is possible that
damages could exceed the amount of our insurance coverage.

The  NRC  has  broad  authority  under  federal  law  to  impose  licensing  and
safety-related  requirements for the operation of nuclear generation facilities.
In the event of non-compliance,  the NRC has the authority to impose fines or to
shut down a unit, or both,  depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could  require us to make  substantial  capital  expenditures  at our
nuclear plants. In addition,  although we have no reason to anticipate a serious
nuclear  incident at our plants,  if an incident did occur, it could  materially
and adversely affect our results of operations or financial  condition.  A major
incident  at a nuclear  facility  anywhere  in the world  could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.

Our facilities  require licenses that need to be renewed or extended in order to
continue  operating.  We do not anticipate any problems renewing these licenses.
However,  as a result  of  potential  terrorist  threats  and  increased  public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.

Our  financial  performance  depends on the  successful  operation  of  electric
generating facilities by our subsidiaries.

Operating electric generating facilities involves many risks, including:

     o    operator error and breakdown or failure of equipment or processes;

     o    operating  limitations  that may be imposed by  environmental or other
          regulatory requirements;

     o    labor disputes;

     o    fuel supply interruptions; and

     o    catastrophic events such as fires,  earthquakes,  explosions,  floods,
          terrorist attacks or other similar occurrences.

A decrease or elimination of revenues  generated by our  subsidiaries'  electric
generating  facilities  or an increase in the cost of operating  the  facilities
could have an adverse effect on our business and results of operations.

Our business is dependent on our ability to successfully access capital markets.
Our  inability  to access  capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.

We rely on access to both short-term money markets and long-term capital markets
as a significant  source of liquidity for capital  requirements not satisfied by
the cash  flow from our  operations.  If we are not able to  access  capital  at
competitive  rates,  our ability to  implement  our  strategy  will be adversely
affected.  We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings.  However,  certain market disruptions
or a  downgrade  of our credit  rating may  increase  our cost of  borrowing  or
adversely  affect  our  ability to access one or more  financial  markets.  Such
disruptions could include:

     o    an economic downturn;

     o    the bankruptcy of an unrelated energy company;

     o    capital market conditions generally;

     o    market prices for electricity and gas;

     o    terrorist attacks or threatened attacks on our facilities or unrelated
          energy companies; or

     o    the overall health of the utility industry.

                                      166
<PAGE>

Restrictions on our ability to access  financial  markets may affect our ability
to execute our business  plan as scheduled.  An inability to access  capital may
limit our ability to pursue  improvements or acquisitions  that we may otherwise
rely on for future growth.

Increases in our  leverage  could  adversely  affect our  competitive  position,
business planning and flexibility,  financial condition,  ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.

Our cash requirements arise primarily from the  capital-intensive  nature of our
electric  utilities,  as well as the  expansion of our  diversified  businesses,
primarily  those of Progress  Ventures.  In addition to operating cash flows, we
rely heavily on our  commercial  paper and  long-term  debt.  As of December 31,
2002,  commercial  paper and bank  borrowings  and  long-term  debt balances for
Progress Energy and its subsidiaries were as follows (in millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                             Outstanding Commercial        Total Long-Term
     Company                                 Paper and Bank Borrowings         Debt, Net
     -----------------                       -------------------------   --------------------
     Progress Energy, unconsolidated (a)         $    0.0                 $   4,802.4
     CP&L                                           437.8                     3,048.5
     Florida Power                                  257.1                     1,244.4 (b)
     Other Subsidiaries                               0.0                       652.0 (c)
                                             -------------------------   --------------------
     Progress Energy, consolidated               $  694.9 (d)             $   9,747.3 (b)(e)
</TABLE>

(a)  Represents solely the outstanding indebtedness of the holding company.
(b)  On February  21,  2003,  Florida  Power  issued  $650.0  million  aggregate
     principal  amount of its first mortgage bonds, the proceeds from which were
     or will be used to reduce,  redeem, or retire our outstanding long-term and
     short-term, secured and unsecured, indebtedness.
(c)  Includes the following  subsidiaries:  Progress Genco Ventures, LLC ($225.0
     million),   Florida  Progress  Funding  Corporation  ($261.0  million)  and
     Progress Capital Holdings, Inc. ($166.0 million).
(d)  We no longer  reclassify  any of our  commercial  paper as long-term  debt.
     Prior to quarter  ended  September  30, 2002,  portions of our  outstanding
     commercial   paper  backed  by  our  multi-year   credit   facilities  were
     reclassified as long-term debt.
(e)  Net of current portion, which at December 31, 2002, was $275.4 million on a
     consolidated basis.

Progress Energy and its  subsidiaries  have an aggregate of six committed credit
lines that support our commercial paper programs  totaling $1.74 billion.  While
our financial policy precludes us from issuing commercial paper in excess of our
credit lines, as of December 31, 2002, we had an aggregate of approximately $1.0
billion  available for future borrowing under our credit lines.  Progress Energy
has an  uncommitted  credit line for up to $300 million and Florida Power has an
uncommitted  credit  line  for up to $100  million.  As of  December  31,  2002,
Progress  Energy had no  outstanding  borrowing  under its  uncommitted  line of
credit. In addition,  as of December 31, 2002, Progress Energy, CP&L and Florida
Power each had shelf  registration  statements  on file with the SEC that permit
the  issuance of various debt and equity  securities  up to an  additional  $1.1
billion,  $500  million,  and $700 million ($50 million  after giving  effect to
Florida  Power's first mortgage bond issuance in February  2003),  respectively.
These amounts may be increased  from time to time,  and each of CP&L and Florida
Power  expects to increase its shelf  capacity in the second or third quarter of
2003.

Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital ratios. As
of December 31, 2002, the maximum and actual ratios were as follows:

     Company                          Maximum Ratio      Actual Ratio
     ---------                        -----------------  ---------------
     Progress Energy                  70%                62.4%
     CP&L                             65%                52.7%
     Florida Power                    65%                48.6%

We expect that in  connection  with the  proposed  renewal of Progress  Energy's
364-day credit facility,  the facility will be reduced in size from $550 million
to approximately $480 million and the permitted debt to capital ratio under that
facility  will be 68% after June 30, 2003. In addition,  we anticipate  that the
facility will contain a requirement  that  Progress  Energy  maintain a ratio of
EBITDA to  interest  expense of at least 2.5x to 1. For the year ended  December
31, 2002, Progress Energy's ratio of EBITDA to interest expense was 3.43x to 1.

                                      167

<PAGE>

In the event our capital  structure  changes such that we approach the permitted
ratios,  our  access to capital  and  additional  liquidity  could  decrease.  A
limitation in our liquidity could have a material adverse impact on our business
strategy  and our ongoing  financing  needs.  Furthermore,  the credit  lines of
Progress  Energy,  CP&L and Florida Power each include  provisions that preclude
each company from borrowing under their respective  credit lines in the event of
a material adverse change in the respective company's financial condition.

Our  indebtedness  also includes  several  cross-default  provisions which could
significantly  impact our financial  condition.  Progress  Energy's,  CP&L's and
Florida  Power's credit lines include  cross-default  provisions for defaults of
indebtedness  in  excess  of  $10  million.   Progress  Energy's  cross  default
provisions  only apply to defaults of  indebtedness  by Progress  Energy and its
significant  subsidiaries  (i.e.,  CP&L,  Florida  Progress,  Florida  Power and
Progress  Capital  Holdings,  Inc.).  CP&L's and Florida  Power's  cross-default
provisions  only apply to defaults of indebtedness by CP&L and Florida Power and
their  subsidiaries,  respectively,  not other  affiliates  of CP&L and  Florida
Power.

Additionally,  certain of Progress  Energy's  long-term debt indentures  contain
cross-default  provisions for defaults of indebtedness in excess of $25 million;
these  provisions only apply to other  obligations of Progress  Energy,  not its
subsidiaries.  In the event that either of these  cross-default  provisions were
triggered,  the lenders could  accelerate  payment of any outstanding  debt. Any
such  acceleration  would  cause a  material  adverse  change in the  respective
company's financial  condition.  Certain agreements  underlying our indebtedness
also limit our ability to incur  additional  liens or engage in certain types of
sale and leaseback transactions.

Changes in economic  conditions  could result in higher  interest  rates,  which
would  increase our interest  expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:

     o    increasing the cost of future debt financing;

     o    impacting  our  ability to pay  dividends  on our common  stock at the
          current rate;

     o    making it more  difficult  for us to satisfy  our  existing  financial
          obligations;

     o    limiting our ability to obtain  additional  financing,  if we need it,
          for working capital, acquisitions,  debt service requirements or other
          purposes;

     o    increasing  our   vulnerability   to  adverse  economic  and  industry
          conditions;

     o    requiring us to dedicate a  substantial  portion of our cash flow from
          operations to payments on our debt, which would reduce funds available
          to us for operations, future business opportunities or other purposes;

     o    limiting our  flexibility  in planning for, or reacting to, changes in
          our business and the industry in which we compete;

     o    placing us at a competitive  disadvantage  compared to our competitors
          who have less debt; and

     o    causing a downgrade in our credit ratings.

Any reduction in our credit  ratings could increase our borrowing  costs,  limit
our access to additional capital and require posting of collateral, all of which
could  materially and adversely  affect our business,  results of operations and
financial condition.

Progress Energy's senior unsecured debt has been assigned a rating by Standard &
Poor's Ratings Group (S&P), a division of The  McGraw-Hill  Companies,  Inc., of
"BBB" (negative  outlook) and by Moody's Investors  Service,  Inc.  (Moody's) of
"Baa2"  (stable  outlook).  On February 7, 2003,  Moody's  announced that it was
lowering  Progress  Energy's senior unsecured debt rating from "Baa1" to "Baa2,"
and changing the outlook of the rating from  negative to stable.  Moody's  cited
the slower than planned pace of the Company's  efforts to pay down debt from its
acquisition of Florida  Progress as the primary  reason for the ratings  change.
Moody's also  changed the outlook of Florida  Power's  senior  secured debt from
stable to negative.  CP&L's senior  unsecured debt has been assigned a rating by
S&P of "BBB+"  (negative  outlook)  and by Moody's of "Baa1"  (stable  outlook).
Florida  Power's  senior  unsecured  debt has been  assigned  a rating by S&P of
"BBB+" (negative  outlook) and by Moody's of "A-2" (stable  outlook).  While our
nonregulated operations, including those conducted through our Progress Ventures
business  unit,  have  a  higher  level  of  risk  than  our  regulated  utility
operations,  we will seek to maintain a solid  investment  grade rating  through

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<PAGE>

prudent capital management and financing structures.  We cannot, however, assure
you that any of Progress Energy's current ratings,  or those of CP&L and Florida
Power,  will remain in effect for any given period of time or that a rating will
not be lowered or  withdrawn  entirely by a rating  agency if, in its  judgment,
circumstances  in the  future so  warrant.  Any  downgrade  could  increase  our
borrowing  costs and  adversely  affect  our  access  to  capital,  which  could
negatively impact our financial  results.  Further,  we may be required to pay a
higher interest rate in future  financings,  and our potential pool of investors
and funding sources could  decrease.  Although we would have access to liquidity
under our committed and uncommitted  credit lines, if our short-term rating were
to fall below A-2 or P-2,  the  current  ratings  assigned  by S&P and  Moody's,
respectively,  it could  significantly  limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy, sell or hold our securities or those of CP&L or Florida Power and that each
rating should be evaluated independently of any other rating.

Our energy trading and marketing business relies on Progress Energy's investment
grade ratings to stand behind transactions in that business.  As of December 31,
2002,   Progress  Energy  has  issued  guarantees  with  a  notional  amount  of
approximately  $172 million to support  Progress  Ventures'  energy  trading and
marketing businesses.  Based upon the amount of trading positions outstanding at
December 31, 2002, if Progress Energy's ratings were to decline below investment
grade,  we would have to deposit cash or provide letters of credit or other cash
collateral   for   approximately   $13.7   million   for  the   benefit  of  our
counterparties.  Additionally,  the power supply agreement with Jackson Electric
Membership  Corporation  that  PVI  expects  to  acquire  from  Williams  Energy
Marketing and Trading  Company  includes a performance  guarantee  that Progress
Energy will assume.  In the event that  Progress  Energy's  credit  ratings fall
below investment grade,  Progress Energy will be required to provide  additional
security for its guarantee in form and amount acceptable to Jackson,  but not to
exceed the coverage amount.  The coverage amount at the inception of PVI's power
sale  to  Jackson  is  $285  million  and  will  decline  over  the  life of the
transaction.   These   collateral   requirements   could  adversely  affect  our
profitability on energy trading and marketing transactions and limit our overall
liquidity.

The use of  derivative  contracts  in the normal  course of our  business  could
result in financial losses that negatively impact our results of operations.

We use  derivatives,  including  futures,  forwards  and  swaps,  to manage  our
commodity  and  financial  market  risks.  In the  future,  we  could  recognize
financial  losses on these  contracts  as a result of  volatility  in the market
values of the underlying commodities or if a counterparty fails to perform under
a  contract.  In the  absence of  actively  quoted  market  prices  and  pricing
information from external sources, the valuation of these financial  instruments
can involve management's judgment or use of estimates.  As a result,  changes in
the underlying  assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.

We could incur a significant  tax  liability,  and our results of operations and
cash flows may be  materially  and  adversely  affected if the Internal  Revenue
Service denies or otherwise makes unusable the Section 29 tax credits related to
our coal and synthetic fuels businesses.

Through Progress  Ventures,  we produce synthetic fuel from coal. The production
and sale of the synthetic fuel qualifies for tax credits under Section 29 of the
Internal  Revenue  Code  (Section  29) if certain  requirements  are  satisfied,
including  a  requirement  that the  synthetic  fuel  differs  significantly  in
chemical  composition  from the coal used to produce such synthetic fuel.  Total
Section 29 credits generated through December 31, 2002 are approximately  $897.2
million.  All of our synthetic fuel facilities have received  favorable  private
letter  rulings from the Internal  Revenue  Service  (IRS) with respect to their
operations. These tax credits are subject to review by the IRS, and if we failed
to  prevail  through  the  administrative  or legal  process,  there  could be a
significant  tax liability owed for previously  taken Section 29 credits,  which
would significantly  impact on earnings and cash flows. Tax credits for the year
ended December 31, 2002, were $291 million and were offset by operating  losses,
net of tax, of $101 million,  for the same period.  One  synthetic  fuel entity,
Colona  Synfuel  Limited  Partnership,  L.L.L.P.,  from  which  we (and  Florida
Progress  prior to our  acquisition)  have  been  allocated  approximately  $251
million in tax credits to date, is being audited by the IRS. In September  2002,
all of our  majority-owned  synthetic  fuel entities were accepted into the IRS'
Pre-Filing  Agreement  (PFA)  program.  The  PFA  program  allows  taxpayers  to
accelerate the IRS  examination  process in order to seek resolution of specific
issues.  Either we or the IRS can  withdraw  from the  program at any time,  and
issues not resolved through the program may proceed to the next level of the IRS
examination  process.  While the ultimate outcome is uncertain,  we believe that
participation  in the PFA  program  will  likely  shorten  the  tax  examination
process.  We believe that we are complying with all the requirements,  including
the private letter  rulings,  necessary to be allowed such credits under Section
29. We believe it is likely, although we cannot be certain, that we will prevail
if challenged by the IRS on any credits taken. The current Section 29 tax credit
program will expire in 2007.

Changes in the  telecommunications  industry  may  affect the future  returns we
expected from our Progress Telecom and Caronet,  Inc. venture.  Furthermore,  in
addition to an  impairment  charge we recorded in the third  quarter of 2002, if
the current  depressed  market  conditions  in the  telecommunications  industry
continue,   we  may  need  to  evaluate  further  the   recoverability   of  our
telecommunications assets.

                                      169

<PAGE>

Our  current  strategy  in the  telecommunications  business  is based  upon our
ability to deliver  broadband  telecommunication  services to our  customers  in
markets  from Miami,  Florida to New York City.  The market for these  services,
like the  telecommunications  industry in general,  is rapidly  changing,  and a
number of participants in this segment have had substantial  financial problems.
Due to the  recent  decline of the  telecommunications  industry  and  continued
operating losses, we initiated a valuation study to assess the recoverability of
Progress Telecom's and Caronet's long-lived assets. Based on this assessment, we
recorded an after-tax  write down and other  one-time  charges of  approximately
$208.6 million related to these assets in 2002. In the future,  we cannot assure
that growth in demand for these  services will occur as expected.  If the market
for these services  fails to recover as quickly as desired or becomes  saturated
with competitors,  our telecommunications  business and telecommunications asset
valuations may be further adversely affected.

There  is a  risk  that  we  will  not  successfully  integrate  newly  acquired
businesses  into our  operations as quickly or as  profitably as expected,  thus
resulting in unexpected and increased costs and losses on our investments.

Our ability to successfully  make strategic  acquisitions  and investments  will
depend on:

     o    the extent to which acquisitions and investment  opportunities  become
          available;

     o    our success in bidding for the opportunities that do become available;

     o    regulatory approval of the acquisitions on favorable terms; and

     o    our access to capital and the terms upon which we obtain capital.

If we are  unable to make  strategic  investments  and  acquisitions,  we may be
unable to realize the growth  that we  anticipate.  Our ability to  successfully
integrate acquired businesses into our operations will depend on the adequacy of
our   implementation   plans  and  our  ability  to  achieve  desired  operating
efficiencies. If we are unable to successfully integrate new businesses into our
operations, we could experience increased costs and losses on our investments.

There are risks  involved with the  construction  and operation of our wholesale
plants,  including construction delays,  dependence on third parties and related
counter-party  risks, and a lack of operating history, all of which may make our
wholesale generation and overall operations less profitable and more unstable.

As of December  31,  2002,  we had  approximately  1,500  megawatts of wholesale
generation in commercial operation. We intend to expand our wholesale generation
to approximately  3,100 megawatts by the end of 2003.

The construction and operation of wholesale generation  facilities is subject to
many risks, including those listed below. During the execution and completion of
our  wholesale  generation  strategy,  these risks will  intensify.  These risks
include:

     o    Construction delays may impact our ability to generate sufficient cash
          flow  and may  have an  adverse  o  effect  on our  operations.  If we
          encounter  significant  construction  delays, any liquidated  damages,
          contingency  funds,  or insurance  proceeds may not be  sufficient  to
          service our related project debt.

     o    We may enter into or otherwise acquire  long-term  contracts that take
          effect at a future  date based upon our  current  expectations  of our
          future wholesale generation capacity.  If our expected future capacity
          does not come to fruition as expected,  we may not be able to meet our
          obligations  under  any  such  long-term  contracts  and  may  have to
          purchase  power  in  the  spot  market  at  then  prevailing   prices.
          Accordingly,  we may lose  current  and future  customers,  impair our
          ability to implement our wholesale  strategy,  and suffer reputational
          harm.  Additionally,  if we are unable to secure favorable  pricing in
          the spot market, our results of operations may be diminished. Progress
          Energy may also become liable under any related performance guarantees
          then in existence.

     o    Our wholesale  facilities depend on third parties through construction
          agreements,  power purchase agreements, fuel supply and transportation
          agreements, and transmission grid connection agreements. If such third
          parties  breach  their  obligations  to us,  our  revenues,  financial
          condition,  cash flow and ability to make  payments  of  interest  and
          principal  on our  outstanding  debts may be  impaired.  Any  material
          breach by any of these parties of their  obligations under the project
          contracts could  adversely  affect our cash flows and could impair our
          ability  to  make  payments  of  principal  of  and  interest  on  our
          indebtedness.

                                      170

<PAGE>

     o    We  depend  on  transmission  and  distribution  facilities  owned and
          operated  by  utilities  and other  energy  companies  to deliver  the
          electricity and natural gas that we sell to the wholesale  market.  If
          transmission is disrupted,  or if capacity is inadequate,  our ability
          to sell and deliver  products and satisfy our contractual  obligations
          may be  hindered.  Although  FERC has issued  regulations  designed to
          encourage   competition   in   wholesale   market   transactions   for
          electricity,  there is the  potential  that fair and  equal  access to
          transmission   systems  will  not  be  available  or  that  sufficient
          transmission capacity will not be available to transmit electric power
          as we desire.  We cannot  predict the timing of industry  changes as a
          result of these initiatives or the adequacy of transmission facilities
          in specific markets.

     o    Agreements with our counter-parties  frequently will include the right
          to  terminate  and/or  withhold  payments  or  performance  under  the
          contracts if specific events occur.  If a project  contract were to be
          terminated  due to  nonperformance  by us or by the other party to the
          contract,  our  ability to enter into a  substitute  agreement  having
          substantially equivalent terms and conditions is uncertain.

     o    Because  many of our  facilities  are  new  construction  and  have no
          operating history, various unexpected events may increase our expenses
          or reduce our  revenues  and impair our ability to service the related
          project  debt.  As with  any new  business  venture  of this  size and
          nature,  operation of our facility  could be affected by many factors,
          including start-up problems,  the breakdown or failure of equipment or
          processes,  the  performance of our facility below expected  levels of
          output or  efficiency,  failure to  operate at design  specifications,
          labor disputes, changes in law, failure to obtain necessary permits or
          to meet permit conditions, government exercise of eminent domain power
          or similar events and catastrophic events including fires, explosions,
          earthquakes and droughts.

     o    Our facilities seek to enter into long-term power purchase  agreements
          to sell all or a portion of their generating capacity.  Currently, the
          percentage of our anticipated nonregulated capacity that will be under
          contract is as follows: 2003--63%,  2004--69% and 2005--25%. Following
          the expiration or early termination of our power purchase  agreements,
          or to the extent we cannot  otherwise secure contracts for our current
          and future generation  capacity,  our facilities will generally become
          merchant  facilities.  Our merchant facilities may not be able to find
          adequate  purchasers,  attain favorable pricing,  or otherwise compete
          effectively in the wholesale market. Additionally,  numerous legal and
          regulatory limitations restrict our ability to operate a facility on a
          wholesale basis.

Our energy marketing and trading operations are subject to risks that may reduce
our  revenues  and  adversely  impact our results of  operations  and  financial
condition, many of which are beyond our control.

Our fleet of wholesale  nonregulated plants may sell energy into the spot market
or other competitive power markets or on a contractual  basis. We may also enter
into contracts to purchase and sell electricity, natural gas and coal as part of
our power marketing and energy trading operations. Our business may also include
entering  into  long-term   contracts  that  supply   customers'  full  electric
requirements.  These  contracts  do not  guarantee  us any rate of return on our
capital  investments  through  mandated  rates,  and our revenues and results of
operations  from  these  contracts  are likely to depend,  in large  part,  upon
prevailing market prices for power in our regional markets and other competitive
markets.  These market prices can fluctuate  substantially over relatively short
periods  of time.  Trading  margins  may erode as  markets  mature,  and  should
volatility decline, we may have diminished opportunities for gain.

In addition,  the Enron Corporation  bankruptcy and enhanced regulatory scrutiny
have  contributed to more rigorous  credit rating review of  participants in the
energy marketing and trading business. Credit downgrades of certain other market
participants have significantly reduced such participants'  participation in the
wholesale  power  markets.  These events are causing a decrease in the number of
significant participants in the wholesale power markets, which could result in a
decrease in the volume and  liquidity in the  wholesale  power  markets.  We are
unable to predict the impact of such  developments  on our power  marketing  and
trading business.

Furthermore,  the FERC,  which has  jurisdiction  over wholesale power rates, as
well as independent  system  operators  that oversee some of these markets,  may
impose price limitations,  bidding rules and other mechanisms to address some of
the volatility in these markets. Fuel prices also may be volatile, and the price
we can  obtain  for power  sales may not  change at the same rate as fuel  costs
changes.  These  factors  could  reduce our margins and  therefore  diminish our
revenues and results of operations.

                                      171

<PAGE>

     Volatility in market prices for fuel and power may result from:

     o    weather conditions;

     o    seasonality;

     o    power usage;

     o    illiquid markets;

     o    transmission or transportation constraints or inefficiencies;

     o    availability of competitively priced alternative energy sources;

     o    demand for energy commodities;

     o    natural  gas,  crude oil and  refined  products,  and coal  production
          levels;

     o    natural disasters, wars, embargoes and other catastrophic events; and

     o    federal,  state and foreign  energy and  environmental  regulation and
          legislation.

We actively manage the market risk inherent in our energy  marketing and trading
operations. Nonetheless, adverse changes in energy and fuel prices may result in
losses in our earnings or cash flows and adversely affect our balance sheet. Our
marketing and risk management  procedures may not work as planned.  As a result,
we cannot predict with precision the impact that our marketing, trading and risk
management  decisions may have on our business,  operating  results or financial
position. In addition, to the extent that we do not cover the entire exposure of
our  assets  or our  positions  to  market  price  volatility,  or  our  hedging
procedures do not work as planned,  fluctuating commodity prices could cause our
sales and net income to be volatile.


                                      172
<PAGE>

CAROLINA POWER & LIGHT COMPANY RISK FACTORS

In this  section,  references  to "we,"  "our,"  "us" or  similar  terms  are to
Carolina Power & Light Company and its consolidated  subsidiaries.  Investing in
our securities  involves risks,  including the risks described below, that could
affect the energy  industry,  as well as us and our  business.  Although we have
tried to discuss key  factors,  please be aware that other risks may prove to be
important in the future.  New risks may emerge at any time and we cannot predict
such  risks or  estimate  the  extent to which  they may  affect  our  financial
performance. Before purchasing our securities, you should carefully consider the
following  risks and the other  information  in this Annual  Report,  as well as
documents  we file with the SEC from time to time.  Each of the risks  described
below  could  result  in a  decrease  in the  value of our  securities  and your
investment therein.

Risks Related to the Energy Industry
------------------------------------

We are  subject  to fluid and  complex  government  regulations  that may have a
negative impact on our business and our results of operations.

We are  subject  to  comprehensive  regulation  by  several  federal  and  state
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers.  We are required
to have  numerous  permits,  approvals and  certificates  from the agencies that
regulate  our  business.  We  believe  the  necessary  permits,   approvals  and
certificates  have  been  obtained  for our  existing  operations  and  that our
business is conducted in accordance with applicable laws; however, we are unable
to  predict  the impact on our  operating  results  from the  future  regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional   regulations  could  have  an  adverse  impact  on  our  results  of
operations.

The Federal Energy Regulatory  Commission ("FERC"),  the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental  Protection Agency ("EPA"), the North
Carolina  Utilities  Commission  ("NCUC") and the Public  Service  Commission of
South  Carolina  ("SCPSC")  regulate  many  aspects of our  utility  operations,
including siting and construction of facilities,  customer service and the rates
that we can charge customers.  Although we are not a registered  holding company
under the Public Utility Holding Company Act of 1935, as amended  ("PUHCA"),  we
are subject to many of the regulatory provisions of PUHCA.

We are a wholly-owned  subsidiary of Progress Energy,  Inc., a registered public
utility holding company under PUHCA.  Repeal of PUHCA has been proposed,  but it
is unclear whether or when such a repeal would occur. It is also unclear to what
extent repeal of PUHCA would result in additional or new regulatory oversight or
action at the federal or state levels, or what the impact of those  developments
might be on our business.

We are unable to predict the impact on our business and  operating  results from
future  regulatory  activities of these federal and state  agencies.  Changes in
regulations  or the imposition of additional  regulations  could have a negative
impact on our business and results of operations.

We are subject to numerous  environmental laws and regulations that may increase
our cost of  operations,  impact or limit our  business  plans,  or expose us to
environmental liabilities.

We are subject to numerous  environmental  regulations affecting many aspects of
our present and future  operations,  including  air  emissions,  water  quality,
wastewater  discharges,  solid  waste,  and  hazardous  waste.  These  laws  and
regulations  can  result  in  increased  capital,  operating  and  other  costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations.  These  laws and  regulations  generally  require  us to obtain and
comply with a wide variety of environmental licenses,  permits,  inspections and
other  approvals.  Both public  officials  and private  individuals  may seek to
enforce  applicable  environmental  laws and regulations.  We cannot predict the
financial or operational outcome of any related litigation that may arise.

In addition,  we may be a responsible party for environmental  clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount and
timing of all future  expenditures  related to environmental  matters because of
the  difficulty  of  estimating  clean up costs.  There is also  uncertainty  in
quantifying  liabilities under  environmental laws that impose joint and several
liability on all potentially responsible parties.

We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.

                                      173

<PAGE>

Recent events in the energy  markets that are beyond our control have  increased
the level of public and  regulatory  scrutiny in our industry and in the capital
markets and have resulted in increased regulation and new accounting  standards.
The  reaction  to  these  events  may have  negative  impacts  on our  business,
financial condition and access to capital.

As a result of the energy  crisis in California  during the summer of 2001,  the
recent volatility of natural gas prices in North America,  the bankruptcy filing
by the Enron  Corporation and Worldcom,  Inc.,  recently  discovered  accounting
irregularities of several public companies,  and  investigations by governmental
authorities  into energy  trading  activities,  companies in the  regulated  and
non-regulated utility businesses have been under a generally increased amount of
public and regulatory scrutiny.  Recently discovered  accounting  irregularities
have caused regulators and legislators to review current  accounting  practices,
financial  disclosures  and  companies'  relationships  with  their  independent
auditors.  The capital  markets and ratings  agencies also have increased  their
level of scrutiny.  We believe that we are complying with all  applicable  laws,
and we have  taken  steps to avoid  the  occurrence  of such  events,  but it is
difficult  or  impossible  to predict  or control  what  effect  these  types of
disruptions in the energy markets may have on our business,  financial condition
or our access to the capital markets.

Additionally,  it is unclear what laws or regulations may develop, and we cannot
predict the ultimate  impact of any future changes in accounting  regulations or
practices in general on public companies,  the energy industry or our operations
specifically.  Any such new  accounting  standards  could  impact the way we are
required to record revenues, expenses, assets and liabilities.  These changes in
accounting  standards  could lead to negative  impacts on  reported  earnings or
increases in liabilities  that could,  in turn,  affect our reported  results of
operations.

Deregulation or  restructuring  in the electric  utility  industry may result in
increased  competition  and unrecovered  costs that could  adversely  affect our
financial condition, results of operations and cash flows.

Increased competition resulting from deregulation or restructuring efforts could
have a significant  adverse  financial  impact on our results of operations  and
cash flows.  Increased  competition  could also result in increased  pressure to
lower rates.  Retail  competition and the unbundling of regulated energy and gas
service  could  have a  significant  adverse  financial  impact  on us due to an
impairment  of  assets,  a loss of retail  customers,  lower  profit  margins or
increased  costs of  capital.  Because  we have  not  previously  operated  in a
competitive retail environment, we cannot predict the extent and timing of entry
by  additional   competitors   into  the  electric   markets.   Movement  toward
deregulation  in North  Carolina  and South  Carolina  has slowed as a result of
recent developments,  including developments related to electric deregulation in
California  and other  states.  We cannot  predict  when we will be  subject  to
changes in  legislation  or  regulation,  nor can we predict the impact of these
changes on our financial condition, results of operations or cash flows.

One of the major issues to be resolved  from  deregulation  is who would pay for
stranded costs. Stranded costs are those costs and investments made by utilities
in order to meet their  statutory  obligation  to provide  electric  service but
which could not be recovered  through the market price of electricity  following
industry  restructuring.  The  amount  of such  stranded  costs  that  we  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 we
were no longer  subject to  cost-based  regulation  and it was not  possible  to
recover stranded costs, our financial  condition and results of operations could
be adversely affected.

Additionally,  the electric  utility  industry  has  experienced  a  substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. As a result of the Public Utilities  Regulatory  Policies
Act of 1978 and the Energy  Policy  Act of 1992,  competition  in the  wholesale
electricity  market has  greatly  increased  due to a greater  participation  by
traditional  electricity suppliers,  non-utility  generators,  independent power
producers,  wholesale  power  marketers  and brokers,  as well as the trading of
energy  futures  contracts  on various  commodities  exchanges.  This  increased
competition  could  affect  our 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 us to expand our wholesale load, or
current  wholesale  customers  elect to  purchase  from  other  suppliers  after
existing  contracts  expire.  In 1996, the FERC issued new rules on transmission
service to facilitate competition in the wholesale market on a nationwide basis.
The  rules  give  greater  flexibility  and  more  choices  to  wholesale  power
customers. As a result of the changing regulatory environment and the relatively
low  barriers  to  entry,  we  expect  competition  to  steadily  increase.   As
competition  continues  to  increase,   our  financial  condition,   results  of
operations and cash flows could be adversely affected.

The uncertain outcome  regarding the timing,  creation and structure of regional
transmission  organizations,  or RTOs,  may  materially  impact  our  results of
operations, cash flows or financial condition.

                                      174

<PAGE>

On  December  20,  1999,  the FERC  issued  Order No.  2000 on RTOs.  This order
required public  utilities that own, operate or control  interstate  electricity
transmission facilities to file either a proposal to participate in an RTO or an
alternative  filing  describing  efforts and plans to participate in an RTO. We,
along with other investor-owned utilities, filed applications with the FERC, the
NCUC, and the SCPSC for approval of an RTO, currently named GridSouth.

On November 7, 2001,  the FERC issued an order  providing  guidance on continued
processing of RTO filings.  In this order, the FERC recognized that it would not
be possible for all RTOs to be  operational by December 15, 2001 as set forth in
Order No. 2000; therefore,  the FERC stated that its future orders would address
the  establishment  of a timeline  for the RTO  progress  in each  region of the
country.

On July 31, 2002,  the FERC issued its Notice of Proposed  Rulemaking  in Docket
No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission
Service and Standard  Electricity Market Design ("SMD NOPR"). The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission owning utilities transfer control of their transmission  facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC- regulated transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities  be required to meet  minimum  criteria  for  generating  reserves.  If
adopted as proposed,  the rules set forth in the SMD NOPR would materially alter
the manner in which  transmission and generation  services are provided and paid
for.  Progress Energy,  Inc. filed comments on the SMD NOPR on November 15, 2002
and January 10, 2003. On January 15, 2003,  the FERC announced the issuance of a
White Paper on SMD to be released in April 2003.  Progress Energy, Inc. plans to
file comments on the White Paper,  as  appropriate.  The FERC has also indicated
that it expects to issue the final rules during the summer of 2003.

The SMD NOPR presents  several  uncertainties,  including what percentage of our
investments in GridSouth will be recovered,  how the elimination of transmission
charges, as proposed in the SMD NOPR, will impact us, and what amount of capital
expenditures  will be necessary to create a new wholesale  market.  We and other
GridSouth  participants  withdrew our RTO  applications  before the NCUC and the
SCPSC pending further review of FERC's SMD NOPR and the related White Paper.

Since weather conditions directly influence the demand for electricity,  as well
as the  price of  energy  commodities,  our  results  of  operations,  financial
condition  and cash  flows can be  negatively  affected  by  changes  in weather
conditions and severe weather.

Our results of operations, financial condition and cash flows may be affected by
changing  weather  conditions.  Weather  conditions  in our service  territories
directly  influence  the demand for  electricity  and affect the price of energy
commodities.  Furthermore, severe weather, such as hurricanes, tornadoes, severe
thunder  storms,  and snow and ice storms can be destructive,  causing  outages,
downed power lines and property  damage,  requiring us to incur  additional  and
unexpected expenses and causing us to lose generating revenues.

In 2002,  drought  conditions and related water  restrictions  affected numerous
electric  utilities in the southeast United States.  Drought  conditions and any
mandated water restrictions that could be implemented in response thereto, could
impact  a  small  percentage  of  our  generating   facilities,   including  our
hydroelectric  generating  facilities.  This may result in additional  expenses,
such as higher  fuel costs  and/or  purchased  power  expenses.  We  continue to
monitor weather patterns and will develop  contingency  plans, as necessary,  to
mitigate  the  impact  of  drought  conditions.  We do not have any  reliability
concerns  with our  generating  facilities  currently  and do not  expect  these
developments to have a material impact on our results of operations.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers,
and may also fluctuate on a seasonal or quarterly basis.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2002, commercial and industrial customers represented approximately
23.5% and 18.2% of our electric revenues,  respectively. As a result, changes in
the macroeconomy  can have negative  impacts on our revenues.  As our commercial
and industrial  customers  experience  economic  hardships,  our revenues can be
negatively impacted.

                                      175

<PAGE>

Electric  power  demand is generally a seasonal  business.  In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this  fluctuation may change depending on the nature and location
of  facilities  we acquire and the terms of power sale  contracts  into which we
enter.  In addition,  we have  historically  sold less power,  and  consequently
earned less income, when weather conditions are milder. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.

Risks Related to Us and Our Business
------------------------------------

Under a North  Carolina  law passed in 2002,  our base rates are frozen for five
years  and we are  required  to  increase  capital  expenditures  for  clean air
improvements.  Accordingly,  our profit margin could be adversely affected if we
do not control operating costs.

The NCUC and the SCPSC  each  exercises  regulatory  authority  for  review  and
approval of the retail electric power rates charged within its respective state.
State  regulators may not allow us to increase  retail rates in the manner or to
the extent we request.  State regulators may also seek to reduce retail rates. A
North  Carolina  law passed in 2002 froze our base  retail  rates for five years
unless  there  are  significant   cost  changes  due  to  governmental   action,
significant  expenditures  due to force  majeure or other  extraordinary  events
beyond our control.  That same  legislation  required a significant  increase in
capital expenditures over the next several years for clean air improvements. The
cash costs incurred by us are generally not subject to being fixed or reduced by
state regulators. We will also require dedicated capital expenditures. Thus, our
ability  to  maintain  our  profit  margins   depends  upon  stable  demand  for
electricity and our efforts to manage our costs.

There are  inherent  potential  risks in the  operation  of nuclear  facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could  result in fines or the shutdown of our nuclear  units,  which may present
potential exposures in excess of our insurance coverage.

We own and  operate  four  nuclear  units  that  represent  approximately  3,293
megawatts,  or  approximately  27%,  of our  generation  capacity.  Our  nuclear
facilities are subject to environmental,  health and financial risks such as the
ability to dispose of spent  nuclear  fuel,  the  ability to  maintain  adequate
capital reserves for decommissioning,  potential  liabilities arising out of the
operation of these facilities,  and the costs of securing the facilities against
possible  terrorist  attacks.  We maintain a decommissioning  trust and external
insurance coverage to minimize the financial  exposure to these risks;  however,
it is possible that damages could exceed the amount of our insurance coverage.

The  NRC  has  broad  authority  under  federal  law  to  impose  licensing  and
safety-related  requirements for the operation of nuclear generation facilities.
In the event of non-compliance,  the NRC has the authority to impose fines or to
shut  down any of our  units,  or both,  depending  upon its  assessment  of the
severity  of  the  situation,  until  compliance  is  achieved.  Revised  safety
requirements promulgated by the NRC could require us to make substantial capital
expenditures at our nuclear plants.  In addition,  although we have no reason to
anticipate a serious nuclear  incident at any of our plants,  if an incident did
occur,  it could  materially  and adversely  affect our results of operations or
financial  condition.  A major  incident at a nuclear  facility  anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.

Our facilities  require licenses that need to be renewed or extended in order to
continue  operating.  We do not anticipate any problems renewing these licenses.
However,  as a result  of  potential  terrorist  threats  and  increased  public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.

Our financial  performance  depends on the successful  operation of our electric
generating facilities.

Operating electric generating facilities involves many risks, including:

     o    operator error and breakdown or failure of equipment or processes;

     o    operating  limitations  that may be imposed by  environmental or other
          regulatory requirements;

     o    labor disputes;

     o    fuel supply interruptions; and

     o    catastrophic events such as fires,  earthquakes,  explosions,  floods,
          terrorist attacks or other similar occurrences.

A decrease or  elimination  of revenues  generated  by our  electric  generating
facilities or an increase in the cost of operating the facilities  could have an
adverse effect on our business and results of operations.

                                      176

<PAGE>

Our business is dependent on our ability to successfully access capital markets.
Our  inability  to access  capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.

We rely on access to both short-term money markets and long-term capital markets
as a significant  source of liquidity for capital  requirements not satisfied by
the cash flow from our  operations.  Our net cash  flow from  operations  funded
approximately  192% of our capital  requirements for the year ended December 31,
2002. If we are not able to access capital at competitive  rates, our ability to
implement our business operations will be adversely affected. We believe that we
will maintain  sufficient  access to these financial  markets based upon current
credit ratings. However, certain market disruptions or a downgrade of our credit
rating may increase  our cost of  borrowing  or adversely  affect our ability to
access one or more financial markets. Such disruptions could include:

     o    an economic downturn;

     o    a ratings downgrade of Progress Energy, Inc.;

     o    the bankruptcy of an unrelated energy company;

     o    capital market conditions generally;

     o    market prices for electricity;

     o    terrorist attacks or threatened  attacks on our facilities or those of
          unrelated energy companies; or

     o    the overall health of the utility industry.

Restrictions on our ability to access  financial  markets may affect our ability
to execute our business  plan as scheduled.  An inability to access  capital may
limit our ability to pursue  improvements or acquisitions  that we may otherwise
rely on for future growth.

Increases in our  leverage  could  adversely  affect our  competitive  position,
business planning and flexibility,  financial condition,  ability to service our
debt obligations and ability to access capital on favorable terms.

Our cash requirements arise primarily from the  capital-intensive  nature of our
business. In addition to operating cash flows, we rely heavily on our commercial
paper and long-term debt. As of December 31, 2002, our commercial  paper balance
was  approximately  $437.8  million,  we  had no  notes  payable  to  affiliated
companies and our long-term debt balances were  approximately $3.0 billion (with
no current portion of long-term debt at December 31, 2002).

We have two committed credit lines,  each totals $285 million,  that support our
commercial  paper programs and mature in July 2003 and July 2005,  respectively.
As of December 31, 2002, we had no outstanding  borrowings under these lines. If
we are unable to extend or renew these credit lines on  favorable  terms,  or at
all, we may experience a liquidity  shortfall that could have a material adverse
impact  on us and  our  financial  condition.  In  addition,  we  have  a  shelf
registration statement on file with the SEC that permits the issuance of various
secured and unsecured  debt  securities up to an additional  $500 million.  This
amount may be increased  from time to time,  and we expect to increase our shelf
capacity in the first or second quarter of 2003.

Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital ratios. As
of December 31, 2002,  the maximum and actual  ratios,  pursuant to the terms of
the  credit  facilities,  were 65% and  52.7%,  respectively.  Indebtedness,  as
defined under the credit facility agreements, includes certain letters of credit
and guarantees that are not recorded on our balance sheets.

In the event our capital  structure  changes such that we approach the permitted
ratios,  our  access to capital  and  additional  liquidity  could  decrease.  A
limitation in our liquidity could have a material adverse impact on our business
strategy and our ongoing financing needs. Furthermore,  our credit lines include
provisions  that preclude us from borrowing  additional  funds in the event of a
material adverse change in our financial condition.

                                      177

<PAGE>

Our   indebtedness   also   includes   cross-default   provisions   which  could
significantly  impact  our  financial   condition.   Our  credit  lines  include
cross-default  provisions for defaults of indebtedness in excess of $10 million.
Our cross-default provisions only apply to defaults on our indebtedness, but not
defaults by our  affiliates.  In the event that a  cross-default  provision  was
triggered,  our lenders could  accelerate  payment of any outstanding  debt. Any
such  acceleration  would  cause a  material  adverse  change  in our  financial
condition.

Changes in economic  conditions  could result in higher  interest  rates,  which
would  increase our interest  expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:

     o    increasing the cost of future debt financing;

     o    making it more  difficult  for us to satisfy  our  existing  financial
          obligations;

     o    limiting our ability to obtain  additional  financing,  if we need it,
          for working capital, acquisitions,  debt service requirements or other
          purposes;

     o    increasing  our   vulnerability   to  adverse  economic  and  industry
          conditions;

     o    requiring us to dedicate a  substantial  portion of our cash flow from
          operations to payments on our debt, which would reduce funds available
          to us for operations, future business opportunities or other purposes;

     o    limiting our  flexibility  in planning for, or reacting to, changes in
          our business and the industry in which we compete;

     o    placing us at a competitive  disadvantage  compared to our competitors
          who have less debt; and

     o    causing a downgrade in our credit ratings.

Any reduction in our credit ratings could increase our borrowing costs and limit
our access to additional  capital,  which could  materially and adversely affect
our business, results of operations and financial condition.

Our senior  secured debt has been assigned a rating by Standard & Poor's Ratings
Group,  a division  of The McGraw  Hill  Companies,  Inc.,  of "BBB+"  (negative
outlook) and by Moody's Investors  Service,  Inc. of "A3" (stable outlook).  Our
senior  unsecured  debt  rating  has been  assigned  a rating  by S&P of  "BBB+"
(negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's
rating philosophy links the ratings of a utility subsidiary to the credit rating
of its  parent  corporation.  Accordingly,  if S&P  were to  downgrade  Progress
Energy,   Inc.'s  credit  ratings,  our  credit  rating  would  also  likely  be
downgraded,  regardless of whether or not we had  experienced  any change in our
business operations or financial conditions.

We will seek to maintain a solid investment grade rating through prudent capital
management and financing  structures.  We cannot,  however,  assure you that our
current  ratings  will remain in effect for any given period of time or that our
ratings will not be lowered or withdrawn  entirely by a rating agency if, in its
judgment,  circumstances in the future so warrant.  Any downgrade could increase
our  borrowing  costs and  adversely  affect our access to capital,  which could
negatively impact our financial  results.  Further,  we may be required to pay a
higher interest rate in future  financings,  and our potential pool of investors
and funding sources could  decrease.  Although we would have access to liquidity
under our committed and uncommitted  credit lines, if our short-term rating were
to fall below "A-2" or "P-2," the current  ratings  assigned by S&P and Moody's,
respectively,  it could  significantly  limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy,  sell or hold our  securities  and that each  rating  should  be  evaluated
independently of any other rating.

The use of  derivative  contracts  in the normal  course of our  business  could
result in financial losses that negatively impact our results of operations.

We use  derivatives,  including  futures,  forwards  and  swaps,  to manage  our
commodity  and  financial  market  risks.  In the  future,  we  could  recognize
financial  losses on these  contracts  as a result of  volatility  in the market
values of the underlying commodities or if a counterparty fails to perform under
a  contract.  In the  absence of  actively  quoted  market  prices  and  pricing
information from external sources, the valuation of these financial  instruments
can involve management's judgment or use of estimates.  As a result,  changes in
the underlying  assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.

                                      178

<PAGE>

Changes in the  telecommunications  industry  may  affect the future  returns we
expected  from  our  Caronet,  Inc.  venture.  Furthermore,  in  addition  to an
impairment  charge  we  recorded  in  2002,  if  the  current  depressed  market
conditions in the telecommunications  industry continue, we may need to evaluate
further the recoverability of our telecommunications assets.

Our  current  strategy  in the  telecommunications  business  is based  upon our
ability to deliver broadband  telecommunication  services to our customers.  The
market for these services,  like the telecommunications  industry in general, is
rapidly  changing,  and a  number  of  participants  in this  segment  have  had
substantial   financial   problems.   Due  to   the   recent   decline   of  the
telecommunications  industry  and  continued  operating  losses,  we initiated a
valuation study to assess the  recoverability  of Caronet's  long-lived  assets.
Based on this assessment, we recorded an after-tax write down and other one-time
charges of  approximately  $71.1million  related to these assets in 2002. In the
future,  we cannot assure that growth in demand for these services will occur as
expected.  If the  market  for these  services  fails to  recover  as quickly as
desired or becomes saturated with competitors,  our telecommunications  business
and telecommunications asset valuations may be further adversely affected.



                                      179
<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.


                                   PROGRESS ENERGY, INC.
                                   CAROLINA POWER & LIGHT COMPANY
Date: March 21, 2003               (Registrants)

                                   By: /s/ Peter M. Scott III
                                   Peter M. Scott III
                                   Executive Vice President and
                                   Chief Financial Officer

                                   By: /s/ Robert H. Bazemore, Jr.
                                   Robert H. Bazemore, Jr.
                                   Vice President and Controller
                                   (Chief Accounting 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.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Signature                                         Title                                  Date

/s/ William Cavanaugh III                         Principal Executive                    March 19, 2003
(William Cavanaugh III,                           Officer and Director
Chairman and Chief Executive Officer)


/s/ Edwin B. Borden                               Director                               March 19, 2003
(Edwin B. Borden)


/s/ James E. Bostic, Jr.                          Director                               March 19, 2003
(James E. Bostic, Jr.)


/s/ David L. Burner                               Director                               March 19, 2003
(David L. Burner)


/s/ Charles W. Coker                              Director                               March 19, 2003
(Charles W. Coker)


/s/ Richard L. Daugherty                          Director                               March 19, 2003
(Richard L. Daugherty)


/s/ W.D. Frederick, Jr.                           Director                               March 19, 2003
(W.D. Frederick, Jr.)

                                      180

<PAGE>

/s/ William O. McCoy                              Director                               March 19, 2003
(William O. McCoy)


/s/ E. Marie McKee                                Director                               March 19, 2003
(E. Marie McKee)


/s/ John H. Mullin, III                           Director                               March 19, 2003
(John H. Mullin, III)


/s/ Richard A. Nunis                              Director                               March 19, 2003
(Richard A. Nunis)


/s/ Carlos A. Saladrigas                          Director                               March 19, 2003
(Carlos A. Saladrigas)


/s/ J. Tylee Wilson                               Director                               March 19, 2003
(J. Tylee Wilson)


/s/ Jean Giles Wittner                            Director                               March 19, 2003
(Jean Giles Wittner)

</TABLE>


                                      181
<PAGE>

                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, William Cavanaugh III, certify that:

1.   I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officer  and  I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;
     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and
     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's  other certifying  officer and I have disclosed,  based on
     our most recent  evaluation,  to the  registrant's  auditors  and the audit
     committee of registrant's board of directors:

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and
     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officer and I have  indicated in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.



Date: March 21, 2003                        /s/ William Cavanaugh III
                                            William Cavanaugh III
                                            Chairman and Chief Executive Officer


                                      182
<PAGE>

                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Peter M. Scott III, certify that:

1.   I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officer  and  I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;
     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and
     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's  other certifying  officer and I have disclosed,  based on
     our most recent  evaluation,  to the  registrant's  auditors  and the audit
     committee of registrant's board of directors:

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and
     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officer and I have  indicated in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.



Date: March 21, 2003                              /s/ Peter M. Scott III
                                                  Peter M. Scott III
                                                  Executive Vice President and
                                                  Chief Financial Officer

                                      183
<PAGE>

                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, William Cavanaugh III, certify that:

1.   I have reviewed  this annual report on Form 10-K of Carolina  Power & Light
     Company;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officer  and  I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;
     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and
     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's  other certifying  officer and I have disclosed,  based on
     our most recent  evaluation,  to the  registrant's  auditors  and the audit
     committee of registrant's board of directors:

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and
     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officer and I have  indicated in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.



Date: March 21, 2003                        /s/ William Cavanaugh III
                                            William Cavanaugh III
                                            Chairman and Chief Executive Officer

                                      184
<PAGE>

                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002


I, Peter M. Scott III, certify that:

1.   I have reviewed  this annual report on Form 10-K of Carolina  Power & Light
     Company;

2.   Based on my  knowledge,  this  annual  report  does not  contain any untrue
     statement of a material fact or omit to state a material fact  necessary to
     make the statements  made, in light of the  circumstances  under which such
     statements  were made, not misleading with respect to the period covered by
     this annual report;

3.   Based on my  knowledge,  the  financial  statements,  and  other  financial
     information included in this annual report,  fairly present in all material
     respects the financial  condition,  results of operations and cash flows of
     the registrant as of, and for, the periods presented in this annual report;

4.   The  registrant's  other  certifying  officer  and  I are  responsible  for
     establishing and maintaining disclosure controls and procedures (as defined
     in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to us by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;
     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and
     c)   presented   in  this   annual   report  our   conclusions   about  the
          effectiveness  of the disclosure  controls and procedures based on our
          evaluation as of the Evaluation Date;

5.   The registrant's  other certifying  officer and I have disclosed,  based on
     our most recent  evaluation,  to the  registrant's  auditors  and the audit
     committee of registrant's board of directors:

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and
     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6.   The  registrant's  other  certifying  officer and I have  indicated in this
     annual  report  whether or not there were  significant  changes in internal
     controls  or in other  factors  that could  significantly  affect  internal
     controls  subsequent to the date of our most recent  evaluation,  including
     any corrective actions with regard to significant deficiencies and material
     weaknesses.



Date: March 21, 2003                              /s/ Peter M. Scott III
                                                  Peter M. Scott III
                                                  Executive Vice President and
                                                  Chief Financial Officer



                                      185
<PAGE>

                                  EXHIBIT INDEX

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
                                                                                Progress
Number                     Exhibit                                              Energy, Inc.              CP&L
                                                                                ------------              ----
*2(a)             Agreement and Plan of Merger By and Among  Carolina  Power                                 X
                  & Light Company, North Carolina Natural Gas Corporation and
                  Carolina Acquisition Corporation, dated as of November 10,
                  1998 (filed as Exhibit No. 2(b) to Quarterly Report on Form
                  10-Q for the quarterly period ended September 30, 1998, File
                  No. 1-3382.)

*2(b)             Agreement and Plan of Merger by and among  Carolina  Power                                 X
                  & Light Company,  North Carolina  Natural Gas  Corporation
                  and  Carolina   Acquisition   Corporation,   Dated  as  of
                  November  10,  1998,  as Amended and  Restated as of April
                  22, 1999 (filed as Exhibit 2 to  Quarterly  Report on Form
                  10-Q for the quarterly  period ended March 31, 1999,  File
                  No. 1-3382).

*2(c)             Agreement and Plan of Exchange, dated as of August 22,               X                     X
                  1999, by and among Carolina Power & Light Company, Florida
                  Progress Corporation and CP&L Holdings, Inc.
                  (filed as Exhibit 2.1 to Current  Report on Form 8-K dated
                  August 22, 1999, File No. 1-3382).

*2(d)             Amended and Restated  Agreement  and Plan of Exchange,  by           X                     X
                  and  among  Carolina   Power  &  Light  Company,   Florida
                  Progress  Corporation and CP&L Energy,  Inc.,  dated as of
                  August 22, 1999,  amended and restated as of March 3, 2000
                  (filed as Annex A to Joint  Preliminary Proxy Statement of
                  Carolina  Power  &  Light  Company  and  Florida  Progress
                  Corporation dated March 6, 2000, File No. 1-3382).

*3a(1)            Restated Charter of Carolina Power & Light Company, as                                     X
                  amended May 10, 1995 (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                                      X
                  amended on May 10, 1996 (filed as Exhibit No. 3(i) to
                  Quarterly Report on Form 10-Q for the quarterly period ended
                  June 30, 1997, File No. 1-3382).

*3a(3)            Amended and  Restated  Articles of  Incorporation  of CP&L           X
                  Energy,  Inc.,  as amended  and  restated on June 15, 2000
                  (filed as Exhibit No.  3a(1) to  Quarterly  Report on Form
                  10-Q for the  quarterly  period ended June 30, 2000,  File
                  No. 1-15929 and No. 1-3382).


                                      186
<PAGE>

*3b(1)            Amended and Restated Articles of Incorporation of CP&L               X
                  Energy, Inc., as amended and restated on December 4, 2000
                  (filed as Exhibit 3b(1) to Annual Report on Form 10-K dated
                  March 28, 2002, File No. 1-3392 and 1-15929).

*3b(2)            By-Laws of Carolina Power & Light Company, as amended on                                   X
                  December 12, 2001 (filed as Exhibit 3b(2) to Annual Report on
                  Form 10-K dated March 28, 2002, File No. 1-3392 and 1-15929).

*3b(3)            By-Laws of Progress Energy, Inc., as amended and restated            X
                  December 12, 2001 (filed as Exhibit No. 3 to Current Report on
                  Form 8-K dated January 17, 2002, File No. 1-15929).

*4a(1)            Resolution of Board of Directors,  dated December 8, 1954,                                 X
                  authorizing the issuance of, and  establishing  the series
                  designation,  dividend  rate  and  redemption  prices  for
                  CP&L'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,                                 X
                  authorizing the issuance of, and  establishing  the series
                  designation,  dividend  rate  and  redemption  prices  for
                  CP&L'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,                                 X
                  1971,  relating to the  authorization of, and establishing
                  the  series  designation,  dividend  rate  and  redemption
                  prices for CP&L'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,                                 X
                  1972,  relating to the  authorization of, and establishing
                  the  series  designation,  dividend  rate  and  redemption
                  prices for CP&L's  Serial  Preferred  Stock,  $7.72 Series
                  (filed as Exhibit 3(g), File No. 33-25560).

*4b(1)            Mortgage and Deed of Trust dated as of May 1, 1940 between                                 X
                  CP&L and The Bank of New York (formerly, Irving Trust Company)
                  and Frederick G. Herbst (Douglas J.
                  MacInnes,  Successor),  Trustees  and  the  First  through
                  Fifth Supplemental  Indentures thereto (Exhibit 2(b), File
                  No. 2-64189);  the Sixth through Sixty-sixth  Supplemental
                  Indentures  (Exhibit 2(b)-5,  File  No.  2-16210;  Exhibit
                  2(b)-6,   File  No. 2-16210;   Exhibit  4(b)-8,  File  No.
                  2-19118;   Exhibit 4(b)-2,   File  No.  2-22439;   Exhibit
                  4(b)-2, File No. 2-24624;  Exhibit 2(c), File No. 2-27297;
                  Exhibit 2(c),  File No.  2-30172;  Exhibit 2(c),  File No.
                  2-35694;  Exhibit 2(c),  File No.  2-37505;  Exhibit 2(c),
                  File No. 2-39002;  Exhibit 2(c), File No. 2-41738; Exhibit
                  2(c),  File No.  2-43439;  Exhibit 2(c), File No. 2-47751;
                  Exhibit 2(c),   File  No.  2-49347;   Exhibit  2(c),  File
                  No. 2-53113;  Exhibit  2(d),  File  No.  2-53113;  Exhibit

                                      187

<PAGE>

                  2(c),  File No.  2-59511;  Exhibit 2(c), File No. 2-61611;
                  Exhibit 2(d),   File  No.  2-64189;   Exhibit  2(c),  File
                  No. 2-65514;  Exhibits  2(c) and 2(d),  File No.  2-66851;
                  Exhibits 4(b)-1,  4(b)-2,  and 4(b)-3,  File  No. 2-81299;
                  Exhibits   4(c)-1  through   4(c)-8,   File   No. 2-95505;
                  Exhibits 4(b) through 4(h),  File No.  33-25560;  Exhibits
                  4(b) and 4(c), File No. 33-33431;  Exhibits 4(b) and 4(c),
                  File  No.  33-38298;  Exhibits  4(h)  and  4(i),  File No.
                  33-42869;  Exhibits 4(e)-(g), File No. 33-48607;  Exhibits
                  4(e) and 4(f), File No. 33-55060;  Exhibits 4(e) and 4(f),
                  File   No.   33-60014;   Exhibits   4(a)   and   4(b)   to
                  Post-Effective   Amendment  No.  1,  File  No.   33-38349;
                  Exhibit 4(e),  File No.  33-50597;  Exhibit 4(e) and 4(f),
                  File No.  33-57835;  Exhibit to Current Report on Form 8-K
                  dated August 28, 1997,  File No. 1-3382;  Form of Carolina
                  Power & Light Company First  Mortgage  Bond,  6.80% Series
                  Due  August  15,  2007 filed as Exhibit 4 to Form 10-Q for
                  the period  ended  September  30, 1998,  File No.  1-3382;
                  Exhibit  4(b),  File No.  333-69237;  and Exhibit  4(c) to
                  Current Report on Form 8-K dated March 19, 1999,  File No.
                  1-3382.);  and  the  Sixty-eighth  Supplemental  Indenture
                  (Exhibit  No.  4(b) to  Current  Report  on Form 8-K dated
                  April  20,  2000,  File No.  1-3382;  and the  Sixty-ninth
                  Supplemental   Indenture  (Exhibit  No.  4b(2)  to  Annual
                  Report  on Form  10-K  dated  March  29,  2001,  File  No.
                  1-3382);  and  the  Seventieth   Supplemental   Indenture,
                  (Exhibit  4b(3) to Annual  Report on Form 10-K dated March
                  29,  2001,  File  No.  1-3382);   and  the   Seventy-first
                  Supplemental  Indenture  (Exhibit  4b(2) to  Annual Report
                  on Form 10-K dated March 28, 2002).

*4c(1)            Indenture,   dated  as  of  February  15,  2001,   between           X
                  Progress  Energy,  Inc. and Bank One Trust Company,  N.A.,
                  as  Trustee,  with  respect  to  Senior  Notes  (filed  as
                  Exhibit 4(a) to Form 8-K dated  February  27,  2001,  File
                  No. 1-15929).

*4c(2)            Indenture,  dated as of March 1,  1995,  between  CP&L and                                 X
                  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(3)            Resolutions  adopted  by the  Executive  Committee  of the                                 X
                  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).

                                      188

<PAGE>

*4d               Indenture (for Senior Notes), dated as of March 1, 1999                                    X
                  between Carolina Power & Light Company and The Bank of New
                  York, as Trustee, (filed as Exhibit No. 4(a) to Current Report
                  on Form 8-K dated March 19, 1999, File No.
                  1-3382),  and the First  and  Second  Supplemental  Senior
                  Note  Indentures  thereto  (Exhibit  No.  4(b) to  Current
                  Report  on  Form  8-K  dated  March  19,  1999,  File  No.
                  1-3382);  Exhibit No.  4(a) to Current  Report on Form 8-K
                  dated April 20, 2000, File No. 1-3382).

*4e               Indenture (For Debt  Securities),  dated as of October 28,                                 X
                  1999 between  Carolina Power & Light Company and The Chase
                  Manhattan  Bank,  as  Trustee  (filed as  Exhibit  4(a) to
                  Current  Report on Form 8-K dated  November 5, 1999,  File
                  No. 1-3382), and an Officer's  Certificate issued pursuant
                  thereto,  dated as of October 28,  1999,  authorizing  the
                  issuance  and sale of  Extendible  Notes due  October  28,
                  2009  (Exhibit  4(b) to  Current  Report on Form 8-K dated
                  November 5, 1999, File No. 1-3382).

*4f               Contingent  Value  Obligation   Agreement,   dated  as  of           X
                  November  30,  2000,  between  CP&L  Energy,  Inc. and The
                  Chase Manhattan  Bank, as Trustee  (Exhibit 4.1 to Current
                  Report  on Form 8-K  dated  December  12,  2000,  File No.
                  1-3382).

*10a(1)           Purchase,  Construction and Ownership Agreement dated July                                 X
                  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                                 X
                  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                                 X
                  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).


                                      189
<PAGE>

*10a(4)           Amendment   dated   December   16,   1982   to   Purchase,                                 X
                  Construction  and Ownership  Agreement dated July 30, 1981
                  between  Carolina Power & Light Company and North Carolina
                  Eastern  Municipal  Power Agency (filed as Exhibit  10(d),
                  File No. 33-25560).

*10a(5)           Agreement Regarding New Resources and Interim Capacity                                     X
                  between Carolina Power & Light Company and North Carolina
                  Eastern Municipal Power Agency dated October 13, 1987 (filed
                  as Exhibit 10(e), File No. 33-25560).

*10a(6)           Power   Coordination   Agreement  -  1987A  between  North                                 X
                  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)          Carolina Power & Light Company $272,500,000 364-Day                                        X
                  Revolving Credit Agreement dated as of July 31, 2002 (filed as
                  Exhibit 10(iii) to Quarterly Report on Form 10-Q for the
                  period ended September 30, 2002, File No.
                  1-3382).

 *10b(2)          Carolina Power & Light Company $272,500,000 3-Year Revolving                               X
                  Credit Agreement dated as of July 31, 2002 (filed as Exhibit
                  10(iv) to Quarterly Report on Form 10-Q for the period ended
                  September 30, 2002, File No. 1-3382).

 *10b(3)          Assumption  Agreement  from  The  Bank of New  York  dated                                 X
                  August  5,  2002 for a total  commitment  of $25  million,
                  increasing  the  amount  of the CP&L  364-Day  and  3-Year
                  Revolving Credit  Agreements dated as of July 31, 2002, to
                  $285,000,000  each  (filed as exhibit  10(v) to  Quarterly
                  Report  on  Form  10-Q  for  the  quarterly  period  ended
                  September 30, 2002, File No. 1-3382).

 *10b(4)          Amendment and Restatement  dated July 26, 2002 to Progress                                 X
                  Energy,   Inc.'s   $450,000,000  3-Year  Revolving  Credit
                  Agreement dated November 13, 2001 as amended  February 13,
                  2002 (filed as Exhibit  10(i) to Quarterly  Report on Form
                  10-Q for the  quarterly  period ended  September 30, 2002,
                  File No. 1-3382 and 1-15929).

 *10b(5)          Assumption   Agreement   from   Barclays  Bank  PLC  dated           X
                  December  17,  2001 for an  additional  commitment  of $50
                  million,  increasing  the amount of the  Progress  Energy,
                  Inc. 364-Day  Revolving Credit  Agreement,  dated November
                  13,  2001,  to $550  million  (filed as Exhibit  10(ii) to
                  Quarterly  Report  on Form 10-Q for the  quarterly  period
                  ended September 30, 2002, File No. 1-3382 and 1-15929).

                                      190

<PAGE>

 *10b(6)          Progress Energy, Inc. $500,000,000 364-Day Revolving Credit          X
                  Agreement dated as of November 13, 2001 (filed as Exhibit
                  10b(5) to Annual Report on Form 10-K dated March 28, 2002,
                  File No. 1-3392 and 1-15929).

 *10b(7)          Progress Energy, Inc. $450,000,000 3-Year Revolving Credit           X
                  Agreement dated as of November 13, 2001 (filed as Exhibit
                  10b(6) to Annual Report on Form 10-K dated March 28, 2002,
                  File No. 1-3392 and 1-15929).

 *10b(8)          Amendment,  dated  February 13, 2002, to Progress  Energy,           X
                  Inc.   $500,000,000  364-Day  Revolving  Credit  Agreement
                  dated as of November 13, 2001 (filed as Exhibit  10b(7) to
                  Annual Report on Form 10-K dated March 28, 2002,  File No.
                  1-3392 and 1-15929).

 *10b(9)          Amendment,  dated  February 13, 2002, to Progress  Energy,           X
                  Inc.  $450,000,000 3-Year Revolving Credit Agreement dated
                  November  13,  2001  (filed  as  Exhibit  10b(8) to Annual
                  Report on Form 10-K dated March 28, 2002,  File No. 1-3392
                  and 1-15929).

-+*10c(1)         Directors Deferred Compensation Plan effective January 1,                                  X
                  1982 as amended (filed as Exhibit 10(g), File No. 33-25560).

-+*10c(2)         Retirement Plan for Outside Directors (filed as Exhibit                                    X
                  10(i), File No. 33-25560).

-+*10c(3)         Key Management Deferred Compensation Plan (filed as Exhibit                                X
                  10(k), File No. 33-25560).

+*10c(4)          Resolutions of the Board of Directors, dated March 15,                                     X
                  1989, amending the Key Management Deferred Compensation Plan
                  (filed as Exhibit 10(a), File No. 33-48607).

-+*10c(5)         Resolutions of the Board of Directors dated May 8, 1991,             X                     X
                  amending the CP&L Directors Deferred Compensation Plan (filed
                  as Exhibit 10(b), File No. 33-48607).

+*10c(6)          Resolutions of Board of Directors dated July 9, 1997,                                      X
                  amending the Deferred Compensation Plan for Key Management
                  Employees of Carolina Power & Light Company.

+*10c(7)          Carolina Power & Light Company Non-Employee Director Stock           X                     X
                  Unit Plan, effective January 1, 1998.

-+*10c(8)         Carolina   Power  &   Light   Company   Restricted   Stock           X                     X
                  Agreement,  as approved  January 7, 1998,  pursuant to the
                  Company's  1997  Equity  Incentive  Plan (filed as Exhibit
                  No. 10 to Quarterly  Report on Form 10-Q for the quarterly
                  period ended March 31, 1998, File No. 1-3382.)

                                      191

<PAGE>

-+*10c(9)         Carolina  Power &  Light  Company  Restoration  Retirement           X                     X
                  Plan, as amended  January 1, 2000 (filed as Exhibit 10c(9)
                  to  Annual  Report  on  Form 10-K  dated  March 28,  2002,
                  File No. 1-3382 and 1-15929).

-+*10c(10)        Amended  and  Restated   Supplemental   Senior   Executive           X                     X
                  Retirement   Plan  of  Carolina  Power  &  Light  Company,
                  effective  January 1, 1984, as last amended March 15, 2000
                  (filed as Exhibit  10b(24)  to Annual  Report on Form 10-K
                  for the fiscal  year ended  December  31,  1999,  File No.
                  1-3382).

-+*10c(11)        Performance  Share  Sub-Plan of the 2002 Progress  Energy,           X                     X
                  Inc. Equity  Incentive Plan,  dated July 9, 2002 (filed as
                  Exhibit  10(vii) to Quarterly  Report on Form 10-Q for the
                  quarterly  period  ended  September  30,  2002,  File  No.
                  1-3382 and 1-15929).

-+*10c(12)        Performance  Share  Sub-Plan of the 1997 Equity  Incentive           X                     X
                  Plan,  as  amended  January  1,  2001  (filed  as  Exhibit
                  10c(11)  to Annual  Report on Form  10-K  dated  March 28,
                  2002, File No. 1-3382 and 1-15929).

+*10c(13)         2002 Progress Energy, Inc. Equity Incentive Plan, amended and        X                     X
                  restated July 10, 2002 (filed as Exhibit 10(vi) to Quarterly
                  Report on Form 10-Q for the quarterly period ended September
                  30, 2002, File No. 1-3382 and 1-15929).

+*10c(14)         1997 Equity Incentive Plan, Amended and Restated as of               X                     X
                  September 26, 2001 (filed as Exhibit 4.3 to Progress Energy
                  Form S-8 dated September 27, 2001, File No.
                  1-3382).

+*10c(15)         Progress Energy, Inc. Form of Stock Option Agreement (filed          X                     X
                  as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No.
                  333-70332).

+*10c(16)         Progress Energy, Inc. Form of Stock Option Award (filed as           X                     X
                  Exhibit 4.5 to Form S-8 dated September 27, 2001, File No.
                  333-70332).

-+*10c(17)        Amended   Management   Incentive   Compensation   Plan  of           X                     X
                  Progress Energy,  Inc., as amended and restated January 1,
                  2002  (filed as Exhibit  10c(15) to Annual  Report on Form
                  10-K dated March 28, 2002, File No. 1-3382 and 1-15929).

-+*10c(18)        Progress Energy, Inc. Management Deferred                            X                     X
                  Compensation  Plan,  amended and restated as of January 1,
                  2002  (filed as Exhibit  10c(16) to Annual  Report on Form
                  10-K dated March 28, 2002, File No. 1-3382 and 1-15929).

                                      192

<PAGE>

+*10c(19)         Agreement dated April 27, 1999 between Carolina Power &                                    X
                  Light Company and Sherwood H. Smith, Jr. (filed as Exhibit
                  10b, File No. 1-3382).

+*10c(20)         Employment  Agreement  dated  August 1, 2000  between CP&L           X
                  Service  Company LLC and William  Cavanaugh  III (filed as
                  Exhibit  10(i) to  Quarterly  Report  on Form 10-Q for the
                  quarterly  period  ended  September  30,  2000,  File  No.
                  1-15929 and No. 1-3382).

+*10c(21)         Employment   Agreement   dated   August  1,  2000  between                                 X
                  Carolina  Power & Light  Company  and  William  S.  "Skip"
                  Orser  (filed as  Exhibit  10(ii) to  Quarterly  Report on
                  Form 10-Q for the  quarterly  period ended  September  30,
                  2000, File No. 1-15929 and No. 1-3382).

+*10c(22)         Employment Agreement dated August 1, 2000 between Carolina                                 X
                  Power & Light Company and Tom Kilgore (filed as Exhibit
                  10(iii) to Quarterly Report on Form 10-Q for the quarterly
                  period ended September 30, 2000, File No.
                  1-15929 and No. 1-3382).

+*10c(23)         Employment  Agreement  dated  August 1, 2000  between CP&L           X
                  Service  Company LLC and Robert  McGehee (filed as Exhibit
                  10(iv) to Quarterly  Report on Form 10-Q for the quarterly
                  period ended  September 30, 2000, File No. 1-15929 and No.
                  1-3382).

+*10c(24)         Form of Employment Agreement dated August 1, 2000 (i)                X                     X
                  between Carolina Power & Light Company and Don K. Davis; and
                  (ii) between CP&L Service Company LLC and Peter M.
                  Scott III and William D. Johnson  (filed as Exhibit  10(v)
                  to Quarterly  Report on Form 10-Q for the quarterly period
                  ended  September  30,  2000,  File  No.  1-15929  and  No.
                  1-3382).

+*10c(25)         Form of  Employment  Agreement  dated  August  1, 2000 (i)           X                     X
                  between  Carolina  Power & Light  Company and Fred Day IV,
                  C.S.  "Scotty" Hinnant and E. Michael  Williams;  and (ii)
                  between  CP&L  Service  Company LLC and Bonnie V.  Hancock
                  and  Cecil  L.  Goodnight  (filed  as  Exhibit  10(vi)  to
                  Quarterly  Report  on Form 10-Q for the  quarterly  period
                  ended  September  30,  2000,  File  No.  1-15929  and  No.
                  1-3382).

+*10c(26)         Employment  Agreement  dated  November  30,  2000  between           X
                  Carolina Power & Light Company,  Florida Power Corporation
                  and  H.  William   Habermeyer,   Jr.   (filed  as  Exhibit
                  10.(b)(32)  to Florida  Progress  Corporation  and Florida
                  Power  Corporation  Annual  Reports  on Form  10-K for the
                  year ended December 31, 2000).

                                      193

<PAGE>

+10c(27)          Form of Employment Agreement between (i) Progress Energy             X
                  Service Company, LLC and Brenda F. Castonguay, effective
                  September 2002; and (ii) Progress Energy Service Company and
                  John R. McArthur, effective January 2003.

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

21                Subsidiaries of Progress Energy, Inc.                                X

23(a)             Consent of Deloitte & Touche LLP.                                    X                     X
</TABLE>


*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.
-Sponsorship of this management contract or compensation plan or arrangement was
       transferred from Carolina Power & Light Company to Progress Energy, Inc.,
       effective August 1, 2000.


                                      194
<PAGE>

                              PROGRESS ENERGY, INC.
                                 EXHIBIT NO. 12
              COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
       PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                        --------------------------------------------------------------------------
                                                                             Years Ended December 31,
                                                        --------------------------------------------------------------------------

                                                             2002           2001             2000          1999         1998
                                                             ----           ----             ----          ----         ----

                                                                              (Thousands of Dollars)
Earnings, as defined:
  Income from continuing operations                     $     552,169   $    540,396    $     477,922  $   383,299  $  396,271
  Fixed charges, as below                                     676,517        717,772          275,155      196,947     196,445
  Capitalized interest                                        (38,240)             -                -            -           -
  Income taxes, as below                                     (165,957)      (162,487)         188,353      249,867     249,180
                                                        --------------    -----------   -------------- ------------ -----------
    Total earnings, as defined                          $   1,024,489   $  1,095,681    $     941,430  $   830,113  $  841,896
                                                        ==============    ===========   ============== ============ ===========

Fixed Charges, as defined:
  Interest on long-term debt                            $     599,919   $    577,987    $     223,914  $   173,978  $  169,901
  Other interest                                               41,655        111,707           37,656        6,733      11,156
  Imputed interest factor in rentals-charged
    principally to operating expenses                          28,278         20,897            8,756       11,517      10,775
  Preferred dividend requirements of subsidiaries (a)           6,665          7,181            4,710        4,719       4,613
                                                        --------------    -----------   -------------- ------------ -----------
    Total fixed charges, as defined                     $     676,517   $    717,772    $     275,036  $   196,947  $  196,445
                                                        ==============    ===========   ============== ============ ===========

Income Taxes:
    Income tax expense (benefit)                        $    (157,808)  $   (154,338)   $     196,502  $   258,018   $ 257,494
    Included in AFUDC - deferred taxes in
       book depreciation                                       (8,149)        (8,149)          (8,149)      (8,149)     (8,314)
                                                        --------------    -----------   -------------- ------------ -----------
    Total income taxes                                  $    (165,957)  $   (162,487)   $     188,353  $   249,869  $  249,180
                                                        ==============    ===========   ============== ============ ===========

Ratio of Earnings to Fixed Charges                               1.51           1.53             3.42         4.21        4.29

</TABLE>

(a)  Presented on a pretax basis based on effective income tax rate



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<PAGE>

                         CAROLINA POWER & LIGHT COMPANY
                                 EXHIBIT NO. 12
              COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
       PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                        ----------------------------------------------------------------------
                                                                             Years Ended December 31,
                                                        ----------------------------------------------------------------------

                                                             2002          2001          2000          1999          1998
                                                             ----          ----          ----          ----          ----

                                                                              (Thousands of Dollars)
Earnings, as defined:
  Net income                                            $     430,932     $ 364,231  $    461,028   $   382,255  $    399,238
  Fixed charges, as below                                     235,026       270,305       248,759       202,491       191,832
  Income taxes, as below                                      199,211       215,084       282,122       250,272       249,180
                                                        --------------   ----------- ------------- ------------- -------------
    Total earnings, as defined                          $     865,169     $ 849,620  $    991,909   $   835,018  $    840,250
                                                        ==============   =========== ============= ============= =============

Fixed Charges, as defined:
  Interest on long-term debt                            $     204,672     $ 245,808  $    223,562   $   180,676  $    169,901
  Other interest                                               12,338        11,333        16,441        10,298        11,156
  Imputed interest factor in rentals-charged
    principally to operating expenses                          18,016        13,163         8,756        11,517        10,775
                                                        --------------   ----------- ------------- ------------- -------------
    Total fixed charges, as defined                     $     235,026     $ 270,304  $    248,759   $   202,491  $    191,832
                                                        ==============   =========== ============= ============= =============

Earnings Before Income Taxes                            $     630,143     $ 579,315  $    743,150   $   632,527  $    648,418
                                                        ==============   =========== ============= ============= =============

Ratio of Earnings Before Income Taxes to Net Income              1.46          1.59          1.61          1.65          1.62

Income Taxes:
    Income tax expense                                  $     207,360     $ 223,233  $    290,271   $   258,421  $    257,494
    Included in AFUDC - deferred taxes in
       book depreciation                                       (8,149)       (8,149)       (8,149)       (8,149)       (8,314)
                                                        --------------   ----------- ------------- ------------- -------------
    Total income taxes                                  $     199,211     $ 215,084  $    282,122   $   250,272  $    249,180
                                                        ==============   =========== ============= ============= =============

Fixed Charges and Preferred Dividends Combined:
  Preferred dividend requirements                       $       2,964     $   2,964  $      2,966   $     2,967  $      2,967
  Portion deductible for income tax purposes                     (312)         (312)         (312)         (312)         (312)
                                                        --------------   ----------- ------------- ------------- -------------
  Preferred dividend requirements not deductible        $       2,652     $   2,652  $      2,654   $     2,655  $      2,655
                                                        ==============   =========== ============= ============= =============

Preferred dividend factor:
    Preferred dividends not deductible times ratio of
      Earnings before income taxes to net income        $       3,872     $   4,217  $      4,273   $     4,407  $      4,301
    Preferred dividends deductible for income taxes               312           312           312           312           312
    Fixed charges, as above                                   235,026       270,305       248,759       202,491       191,832
                                                        --------------   ----------- ------------- ------------- -------------
      Total fixed charges and preferred dividends       $     239,210     $ 274,834  $    253,344   $   207,210  $    196,445
         combined                                       ==============   =========== ============= ============= =============

Ratio of Earnings to Fixed Charges                               3.68          3.14          3.99          4.12          4.38

Ratio of Earnings to Fixed Charges and Preferred
  Dividends Combined                                             3.62          3.09          3.92          4.03          4.28
</TABLE>


                                      196
<PAGE>

                                                                     Exhibit 21


                      SUBSIDIARIES OF PROGRESS ENERGY, INC.
                              AT DECEMBER 31, 2002


The following is a list of certain direct and indirect  subsidiaries of Progress
Energy, Inc. and their respective states of incorporation:

Carolina Power & Light Company                                   North Carolina
    Caronet, Inc.                                                North Carolina

Florida Progress Corporation                                     Florida
    Florida Power Corporation                                    Florida
    Progress Telecommunications Corporation                      Florida
    Progress Capital Holdings, Inc.                              Florida
             Progress Fuels Corporation                          Florida
                      Progress Rail Services Corporation         Alabama

North Carolina Natural Gas Corporation                           Delaware

Progress Ventures, Inc.                                          North Carolina

Strategic Resource Solutions Corp.                               North Carolina

Progress Energy Service Company, LLC                             North Carolina


                                      197
<PAGE>
                                                                  Exhibit 23(a)


                          INDEPENDENT AUDITORS' CONSENT


We consent to the  incorporation  by reference  in  Registration  Statement  No.
33-33520 on Form S-8,  Post-Effective  Amendment 1 to Registration Statement No.
33-38349  on Form  S-3,  Registration  Statement  No.  333-81278  on  Form  S-3,
Registration  Statement No. 333-81278-01 on Form S-3, Registration Statement No.
333-81278-02 on Form S-3,  Registration  Statement No. 333-81278-03 on Form S-3,
Post-Effective  Amendment 1 to Registration Statement No. 333-69738 on Form S-3,
Registration  Statement No.  333-70332 on Form S-8,  Registration  Statement No.
333-87274 on Form S-3, Post-Effective  Amendment 1 to Registration Statement No.
333-47910  on Form  S-3,  Registration  Statement  No.  333-52328  on Form  S-8,
Post-Effective  Amendment 1 to Registration Statement No. 333-89685 on Form S-8,
and Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of
our reports dated February 12, 2003 (which  express an  unqualified  opinion and
include an explanatory  paragraph  referring to the Company's  change in 2002 in
its method of accounting for goodwill);  appearing in this Annual Report on Form
10-K of Progress Energy, Inc. for the year ended December 31, 2002.

We also consent to the incorporation by reference in Registration  Statement No.
333-58800  on Form S-3 of Carolina  Power & Light  Company of our reports  dated
February  12,  2003,  appearing  in this Annual  Report on Form 10-K of Carolina
Power & Light Company for the year ended December 31, 2002.


/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 19, 2003


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