UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-Q

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

                  For the quarterly period ended June 30, 2003

                                       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>

Commission           Exact name of registrants as specified in their charters, state of           I.R.S. Employer
File Number      incorporation, address of principal 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


                                      NONE
(Former name, former address and former fiscal year, if changed since last report)
</TABLE>

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

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

This combined Form 10-Q is filed separately by two registrants: Progress Energy,
Inc.  (Progress Energy) and Carolina Power & Light Company d/b/a Progress Energy
Carolinas,   Inc.  (PEC).   Information  contained  herein  relating  to  either
individual registrant is filed by such registrant solely on its own behalf. Each
registrant makes no representation as to information relating exclusively to the
other registrant.

Indicate the number of shares  outstanding  of each of the  issuers'  classes of
common  stock,  as of the latest  practicable  date.  As of July 31, 2003,  each
registrant had the following shares of common stock outstanding:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

        Registrant                          Description                             Shares
        ----------                          -----------                             ------
Progress Energy, Inc.              Common Stock (Without Par Value)               243,437,696
Carolina Power & Light Company     Common Stock (Without Par Value)         159,608,055 (all of which
                                                                          were held by Progress Energy, Inc.)
</TABLE>

                                       1
<PAGE>

            PROGRESS ENERGY, INC. AND PROGRESS ENERGY CAROLINAS, INC.
                 FORM 10-Q - For the Quarter Ended June 30, 2003



Glossary of Terms

Safe Harbor For Forward-Looking Statements

PART I. FINANCIAL INFORMATION

Item 1.  Financial Statements

         Consolidated Interim Financial Statements:

         Progress Energy, Inc.
         --------------------------------------------------------------
         Consolidated Statements of Income
         Consolidated Balance Sheets
         Consolidated Statements of Cash Flows
         Notes to Consolidated Interim Financial Statements

         Carolina Power & Light Company
         d/b/a Progress Energy Carolinas, Inc.
         ---------------------------------------------------------------
         Consolidated Statements of Income
         Consolidated Balance Sheets
         Consolidated Statements of Cash Flows
         Notes to Consolidated Interim Financial Statements

Item 2.  Management's Discussion and Analysis of Financial Condition and
         Results of Operations

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

Item 4.  Controls and Procedures

PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

Item 4.  Submission of Matters to a Vote of Security Holders

Item 6.  Exhibits and Reports on Form 8-K

Signatures



                                       2
<PAGE>

                                GLOSSARY OF TERMS


The following abbreviations or acronyms used in the text of this combined Form
10-Q are defined below:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     TERM                                    DEFINITION

AFUDC                    Allowance for funds used during construction
the Agreement            Stipulation and Settlement Agreement
ARO                      Asset retirement obligations
Bcf                      Billion cubic feet
CCO                      Competitive Commercial Operations
the Code                 Internal Revenue Service Code
Colona                   Colona Synfuel Limited Partnership, L.L.L.P.
the Company              Progress Energy, Inc. and subsidiaries
CP&L Energy              CP&L Energy, Inc., now known as Progress Energy, Inc.
CPI                      Consumer Price Index
CR3                      Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3
CVO                      Contingent value obligation
DIG                      Derivatives Implementation Group
DOE                      United States Department of Energy
Dt                       Dekatherm
DWM                      North Carolina Department of Environment and Natural Resources, Division of Waste
                         Management
EITF                     Emerging Issues Task Force
ENCNG                    Eastern North Carolina Natural Gas Company, formerly referred to as Eastern NC
EPA                      United States Environmental Protection Agency
FASB                     Financial Accounting Standards Board
FDEP                     Florida Department of Environment and Protection
Federal Circuit          U.S. Circuit Court of Appeals
FERC                     Federal Energy Regulatory Commission
FIN No. 46               FASB Interpretation No. 46, "Consolidation of Variable Interest Entities - An
                         Interpretation of ARB No. 51"
FPC                      Florida Progress Corporation
FPSC                     Florida Public Service Commission
Funding Corp.            Florida Progress Funding Corporation
GAAP                     Accounting principles generally accepted in the United States of America
Genco                    Progress Genco Ventures, LLC
IRS                      Internal Revenue Service
Jackson                  Jackson Electric Membership Corp.
KWh                      Kilowatt-hour
MACT                     Maximum Available Control Technology
MGP                      Manufactured gas plant
MW                       Megawatt
NCNG                     North Carolina Natural Gas Corporation
NCUC                     North Carolina Utilities Commission
NOx SIP Call             EPA rule which requires 23 jurisdictions including North and South
                         Carolina and Georgia to further reduce nitrogen oxide emissions
NRC                      United States Nuclear Regulatory Commission
NSP                      Northern States Power
PCH                      Progress Capital Holdings, Inc.
PEC                      Progress Energy Carolinas, Inc., formerly referred to as Carolina Power & Light Company
PEF                      Progress Energy Florida, Inc., formerly referred to as Florida Power Corporation
PFA                      IRS Prefiling Agreement
the Plan                 Revenue Sharing Incentive Plan
PLRs                     Private Letter Rulings
Preferred Securities     FPC-obligated mandatorily redeemable preferred securities

                                        3
<PAGE>

Progress Energy          Progress Energy, Inc.
Progress Rail            Progress Rail Services Corporation
Progress Telecom         Progress Telecommunications Corporation
Progress Ventures        Business segment of Progress Energy primarily made up of nonregulated
                         energy generation, gas, coal and synthetic fuel operations and energy
                         marketing and trading
PUHCA                    Public Utility Holding Company Act of 1935, as amended
PVI                      Legal entity of Progress Ventures, Inc., formerly referred to as CPL Energy Ventures, Inc.
PWR                      Pressurized water reactor
RAFT                     Railcar Asset Financing Trust
Rail                     Rail Services
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
Section 42               Section 42 of the Internal Revenue Service Code
Service Company          Progress Energy Service Company, LLC
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. 131             Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an
                         Enterprise and Related Information"
SFAS No. 133             Statement of Financial Accounting Standards No. 133, "Accounting for Derivative and
                         Hedging Activities"
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"
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"
SFAS No. 149             Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on
                         Derivative Instruments and Hedging Activities"
SFAS No. 150             Statement of Financial Accounting Standards No. 150, "Accounting for Certain Financial
                         Instruments with Characteristics of Both Liabilities and Equity"
SMD NOPR                 Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination
                         through Open Access Transmission and Standard Market Design
SRS                      Strategic Resource Solutions Corp.
the Trust                FPC Capital I

</TABLE>


                                       4
<PAGE>

         SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

This combined report contains  forward-looking  statements within the meaning of
the safe harbor  provisions of the Private  Securities  Litigation Reform Act of
1995.  The matters  discussed  throughout  this  combined Form 10-Q 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,   forward-looking   statements  are  discussed  in   "Management's
Discussion  and  Analysis of  Financial  Condition  and  Results of  Operations"
including,  but not limited to, statements under the sub-heading "Other Matters"
about the  effects of new  environmental  regulations,  nuclear  decommissioning
costs and the effect of electric utility industry restructuring.

Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy, Inc. (Progress Energy) nor Progress Energy
Carolinas,  Inc. (PEC)  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
outcome of the IRS's audit and inquiry into the  availability and use of Section
29 tax credits by synthetic fuel producers and 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; the Company's
ability to obtain an extension of the Securities and Exchange Commission's order
requiring us to divest of Progress  Rail  Services  Corporation  by November 30,
2003; and unanticipated  changes in operating expenses and capital expenditures.
Most of these risks similarly impact the Company's subsidiaries including PEC.

These and other risk  factors  are  detailed  from time to time in the  Progress
Energy and PEC SEC  reports.  Many,  but not all of the factors  that may impact
actual results are discussed in the Risk Factors  sections of Progress  Energy's
and PEC's annual report on Form 10-K for the year ended December 31, 2002, which
were filed with the SEC on March 21,  2003.  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 PEC. 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 PEC.

                                       5
<PAGE>

                          PART I. FINANCIAL INFORMATION


Item 1.  Financial Statements

                              Progress Energy, Inc.
                    CONSOLIDATED INTERIM FINANCIAL STATEMENTS
                                  June 30, 2003
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CONSOLIDATED STATEMENTS OF INCOME
                                                               Three Months Ended              Six Months Ended
(Unaudited)                                                         June 30,                        June 30,
-----------------------------------------------------------------------------------------------------------------------
(In thousands except per share data)                           2003           2002            2003            2002
-----------------------------------------------------------------------------------------------------------------------
Operating Revenues
   Utility                                                  $ 1,582,787    $ 1,600,581     $ 3,236,674     $ 3,098,503
   Diversified business                                         429,897        358,274         792,015         647,653
-----------------------------------------------------------------------------------------------------------------------
      Total Operating Revenues                                2,012,684      1,958,855       4,028,689       3,746,156
-----------------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
   Fuel used in electric generation                             393,331        366,757         804,954         736,809
   Purchased power                                              209,825        224,685         412,567         405,958
   Operation and maintenance                                    364,766        346,358         699,079         675,332
   Depreciation and amortization                                223,595        210,485         443,683         422,373
   Taxes other than on income                                    94,446         93,306         197,278         189,227
Diversified business
   Cost of sales                                                379,710        347,438         686,651         647,963
   Depreciation and amortization                                 33,680         29,329          61,948          56,664
   Other                                                         38,996         35,209          89,254          64,562
-----------------------------------------------------------------------------------------------------------------------
        Total Operating Expenses                              1,738,349      1,653,567       3,395,414       3,198,888
-----------------------------------------------------------------------------------------------------------------------
Operating Income                                                274,335        305,288         633,275         547,268
-----------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                3,531          6,153           6,297           8,106
   Other, net                                                    (9,432)        (2,340)        (11,883)          3,718
-----------------------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                             (5,901)         3,813          (5,586)         11,824
-----------------------------------------------------------------------------------------------------------------------
Income before Interest Charges and Income Taxes                 268,434        309,101         627,689         559,092
-----------------------------------------------------------------------------------------------------------------------
Interest Charges
   Net interest charges                                         159,520        170,161         315,768         340,330
   Allowance for borrowed funds used during construction         (2,222)        (3,353)         (5,109)         (6,906)
-----------------------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                             157,298        166,808         310,659         333,424
-----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax             111,136        142,293         317,030         225,668
Income Tax Expense (Benefit)                                    (39,174)        20,360         (30,146)        (20,326)
-----------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations                               150,310        121,933         347,176         245,994
Discontinued Operations, Net of Tax                               2,513         (1,313)         13,803           7,153
-----------------------------------------------------------------------------------------------------------------------
Net Income                                                  $   152,823    $   120,620     $   360,979     $   253,147
-----------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding                               236,057        215,007         234,755         213,999
-----------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
    Income from Continuing Operations                       $      0.64    $      0.57     $      1.48     $      1.15
    Discontinued Operations, Net of Tax                     $      0.01    $     (0.01)    $      0.06     $      0.03
    Net Income                                              $      0.65    $      0.56     $      1.54     $      1.18
-----------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
    Income from Continuing Operations                       $      0.63    $      0.56     $      1.47     $      1.15
    Discontinued Operations, Net of Tax                     $      0.01    $      0.00     $      0.06     $      0.03
    Net Income                                              $      0.64    $      0.56     $      1.53     $      1.18
-----------------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share                         $     0.560    $     0.545     $     1.120     $     1.090
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

                                       6
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Progress Energy, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands except share data)                                                           June 30,           December 31,
Assets                                                                                       2003                 2002
-----------------------------------------------------------------------------------------------------------------------------
     Utility Plant
  Utility plant in service                                                             $  20,991,295           $  20,152,787
  Accumulated depreciation                                                                (9,990,819)            (10,480,880)
-----------------------------------------------------------------------------------------------------------------------------
        Utility plant in service, net                                                     11,000,476               9,671,907
  Held for future use                                                                         12,864                  15,109
  Construction work in progress                                                              842,520                 752,336
  Nuclear fuel, net of amortization                                                          234,515                 216,882
-----------------------------------------------------------------------------------------------------------------------------
             Total Utility Plant, Net                                                     12,090,375              10,656,234
-----------------------------------------------------------------------------------------------------------------------------
     Current Assets
  Cash and cash equivalents                                                                   45,654                  61,358
  Accounts receivable                                                                        824,233                 737,369
  Unbilled accounts receivable                                                               217,586                 225,011
  Inventory                                                                                  846,928                 875,485
  Deferred fuel cost                                                                         277,480                 183,518
  Assets of discontinued operations                                                          491,784                 490,429
  Prepayments and other current assets                                                       213,209                 260,804
-----------------------------------------------------------------------------------------------------------------------------
             Total Current Assets                                                          2,916,874               2,833,974
-----------------------------------------------------------------------------------------------------------------------------
     Deferred Debits and Other Assets
  Regulatory assets                                                                          640,891                 393,215
  Nuclear decommissioning trust funds                                                        861,752                 796,844
  Diversified business property, net                                                       2,213,623               1,884,271
  Miscellaneous other property and investments                                               443,428                 463,776
  Goodwill                                                                                 3,719,327               3,719,327
  Prepaid pension costs                                                                       57,919                  60,169
  Other assets and deferred debits                                                           684,764                 517,182
-----------------------------------------------------------------------------------------------------------------------------
             Total Deferred Debits and Other Assets                                        8,621,704               7,834,784
-----------------------------------------------------------------------------------------------------------------------------
           Total Assets                                                                $  23,628,953           $  21,324,992
-----------------------------------------------------------------------------------------------------------------------------

Capitalization and Liabilities
-----------------------------------------------------------------------------------------------------------------------------
Common Stock Equity
  Common stock without par value, 500,000,000 shares authorized, 242,187,774 and
      237,992,513 shares issued and outstanding,
      respectively                                                                     $   5,109,564           $   4,929,104
  Unearned ESOP common stock                                                                 (88,734)               (101,560)
  Accumulated other comprehensive loss                                                      (240,508)               (237,762)
  Retained earnings                                                                        2,182,440               2,087,227
-----------------------------------------------------------------------------------------------------------------------------
        Total Common Stock Equity                                                          6,962,762               6,677,009
-----------------------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption                           92,831                  92,831
Long-Term Debt                                                                             9,223,632               9,747,293
-----------------------------------------------------------------------------------------------------------------------------
        Total Capitalization                                                              16,279,225              16,517,133
-----------------------------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                                        1,130,308                 275,397
  Accounts payable                                                                           606,658                 756,287
  Interest accrued                                                                           222,896                 220,400
  Dividends declared                                                                         135,280                 132,232
  Short-term obligations                                                                     858,991                 694,850
  Customer deposits                                                                          161,539                 158,214
  Liabilities of discontinued operations                                                     119,058                 124,767
  Other current liabilities                                                                  478,419                 350,132
-----------------------------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                                          3,713,149               2,712,279
-----------------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                                                          824,961                 932,813
  Accumulated deferred investment tax credits                                                198,098                 206,221
  Regulatory liabilities                                                                     542,210                 119,766
  Asset retirement obligations                                                             1,225,605                       -
  Other liabilities and deferred credits                                                     845,705                 836,780
-----------------------------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                                       3,636,579               2,095,580
-----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 15)
-----------------------------------------------------------------------------------------------------------------------------
           Total Capitalization and Liabilities                                        $  23,628,953           $  21,324,992
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Progress Energy, Inc. Consolidated Interim Financial Statements.

                                       7
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Progress Energy, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS                                                           Six Months Ended
(Unaudited)                                                                                         June 30,
(In thousands)                                                                             2003                 2002
------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                             $   360,979         $   253,147
Adjustments to reconcile net income to net cash provided by operating activities:
      Income from discontinued operations                                                  (13,803)             (7,153)
      Depreciation and amortization                                                        568,328             567,106
      Deferred income taxes                                                               (118,442)            (44,234)
      Investment tax credit                                                                 (8,123)            (10,126)
      Deferred fuel cost (credit)                                                          (93,962)             22,718
      Net increase in accounts receivable                                                  (85,314)            (35,229)
      Net (increase) decrease in inventories                                                26,591             (38,637)
      Net (increase) decrease in prepayments and other current assets                       23,120             (14,993)
      Net decrease in accounts payable                                                     (15,332)            (62,655)
      Net increase in income taxes, net                                                    104,997              78,837
      Net increase in other current liabilities                                             52,538              30,661
      Other                                                                                 92,666              39,896
------------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                         894,243             779,338
------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions                                                          (541,205)           (520,872)
Diversified business property additions and acquisitions                                  (366,494)           (627,042)
Nuclear fuel additions                                                                     (84,050)            (49,346)
Net contributions to nuclear decommissioning trust                                         (17,959)            (19,917)
Investments in non-utility activities                                                       (5,792)            (10,301)
Acquisition of intangibles                                                                (190,168)                  -
Net decrease (increase) in restricted cash                                                  16,784           (105,721)
Other                                                                                       (1,136)              5,257
------------------------------------------------------------------------------------------------------------------------
          Net Cash Used in Investing Activities                                         (1,190,020)         (1,327,942)
------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net of issuance costs                                            171,771                   -
Purchase of restricted shares                                                               (6,560)             (5,393)
Issuance of long-term debt, net of issuance costs                                          654,824           1,013,633
Net increase in short-term indebtedness                                                    163,092              14,499
Net decrease in cash provided by checks drawn in excess of bank balances                   (43,707)            (33,605)
Retirement of long-term debt                                                              (392,054)           (108,381)
Dividends paid on common stock                                                            (267,608)           (238,404)
Other                                                                                          815              47,407
------------------------------------------------------------------------------------------------------------------------
           Net Cash Provided by Financing Activities                                       280,573             689,756
------------------------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations                                                          (500)               (584)
------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                       (15,704)            140,568
Cash and Cash Equivalents at Beginning of the Period                                        61,358              53,708
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period                                         $    45,654         $   194,276
------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year -  interest (net of amount capitalized)                      $   305,206         $   324,234
                             income taxes (net of refunds)                             $    22,241         $    15,977
</TABLE>

Noncash Activities
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 Progress Energy, Inc. Consolidated Interim Financial Statements.


                                       8
<PAGE>

Progress Energy, Inc.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. ORGANIZATION AND BASIS OF PRESENTATION

     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.  Both the Company and its subsidiaries are subject to
     the regulatory  provisions of PUHCA.  Effective  January 1, 2003,  Carolina
     Power & Light Company,  Florida Power  Corporation  and Progress  Ventures,
     Inc. (PVI) began doing business under the names Progress Energy  Carolinas,
     Inc.  (PEC),  Progress  Energy  Florida,  Inc.  (PEF) and  Progress  Energy
     Ventures,  Inc.,  respectively.  The legal names of these entities have not
     changed,  and there was no  restructuring  of any kind  related to the name
     change.   The  current   corporate  and  business  unit  structure  remains
     unchanged.

     Through its wholly owned subsidiaries,  Progress Energy Carolinas, Inc. and
     Progress  Energy  Florida,  Inc., the Company is engaged in the generation,
     purchase,  transmission,  distribution and sale of electricity primarily in
     portions of North  Carolina,  South  Carolina  and  Florida.  The  Progress
     Ventures  business  unit consists of the Fuels and  Competitive  Commercial
     Operations (CCO) operating  segments.  The Fuels operating segment includes
     natural  gas  drilling  and  production,  coal mining and  synthetic  fuels
     production.  The CCO operating segment includes nonregulated generation and
     energy  marketing and limited  trading  activities.  Through other business
     units, the Company engages in other nonregulated business areas,  including
     energy    management    and   related    services,    rail   services   and
     telecommunications.  Progress  Energy's  legal  structure is not  currently
     aligned  with the  functional  management  and  financial  reporting of the
     Progress  Ventures  business  unit.  Whether,   and  when,  the  legal  and
     functional structures will converge depends upon legislative and regulatory
     action, which cannot currently be anticipated.

     B. Basis of Presentation

     These financial statements have been prepared in accordance with accounting
     principles  generally  accepted in the United States of America  (GAAP) for
     interim  financial  information and with the  instructions to Form 10-Q and
     Regulation S-X. Accordingly, they do not include all of the information and
     footnotes required by GAAP for complete financial  statements.  Because the
     accompanying  consolidated  interim financial statements do not include all
     of the information  and footnotes  required by GAAP, they should be read in
     conjunction  with the audited  financial  statements  for the period  ended
     December 31, 2002 and notes thereto included in Progress Energy's Form 10-K
     for the year ended December 31, 2002.

     In accordance  with the  provisions  of APB 28, GAAP requires  companies to
     apply a levelized  effective tax rate to interim periods that is consistent
     with the  estimated  annual  effective  tax rate.  Income tax  expense  was
     increased by $4.8 million and $58.4 million for the second  quarter of 2003
     and  2002,  respectively,  in  order  to  maintain  an  effective  tax rate
     consistent with the estimated annual rate. Income tax expense was decreased
     by $5.4 million and increased  $79.6 million for the first half of 2003 and
     2002, respectively.

     The amounts included in the consolidated  interim financial  statements are
     unaudited but, in the opinion of management,  reflect all normal  recurring
     adjustments  necessary to fairly present the Company's  financial  position
     and results of operations for the interim periods.  Due to seasonal weather
     variations  and  the  timing  of  outages  of  electric  generating  units,
     especially  nuclear-fueled  units,  the results of  operations  for interim
     periods are not necessarily  indicative of amounts  expected for the entire
     year or future periods.

     In preparing 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  financial  statements  and  amounts of revenues  and  expenses
     reflected  during the reporting  period.  Actual  results could differ from
     those estimates. Certain amounts for 2002 have been reclassified to conform
     to the 2003 presentation.

2.   ACQUISITIONS

     During the first  quarter of 2003,  Progress  Fuels  Corporation,  a wholly
     owned  subsidiary  of  Progress  Energy,  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 primary  assets in the  acquisition  have been  contributed  to

                                       9
<PAGE>

     Progress Fuels North Texas Gas, L.P., a wholly owned subsidiary of Progress
     Fuels  Corporation.  The cash purchase price for the  transactions  totaled
     $148 million.

     On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
     subsidiary of the Williams Companies,  Inc., a long-term  full-requirements
     power supply  agreement at fixed  prices with Jackson  Electric  Membership
     Corp. (Jackson), for $188.2 million. See Note 7 for additional information.

3.   DIVESTITURES

     A. NCNG Divestiture

     On October 16, 2002, the Company announced the Board of Directors' approval
     to sell North  Carolina  Natural Gas  Corporation  (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.  By order  issued June 26,  2003,  the North  Carolina  Utilities
     Commission  (NCUC)  approved  the  Company's  application  to sell  NCNG to
     Piedmont  Natural  Gas  Company,  Inc.  The closing of the  acquisition  is
     subject to the approval of the  Securities and Exchange  Commission  (SEC).
     The sale is expected to close during the summer of 2003.  Net proceeds from
     the sale will be used to pay down debt obligations.

     The  accompanying  consolidated  interim  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  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.
     Interest  expense  allocated  for the three  months ended June 30, 2003 and
     2002 was $3.3 million and $4.0 million, respectively. Amounts allocated for
     the six months  ended  June 30,  2003 and 2002 were $6.9  million  and $8.0
     million,  respectively.  The Company  ceased  recording  depreciation  upon
     classification  of  the  assets  as  discontinued   operations.   After-tax
     depreciation expense recorded by NCNG during the second quarter of 2002 was
     $2.9 million and during the first half of 2002 was $5.8 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 was recorded in the fourth  quarter of 2002.  The estimated
     loss is reviewed  quarterly and will be finalized  once the  disposition is
     complete  and the actual loss can be  determined.  Results of  discontinued
     operations were as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                         Three Months Ended                   Six Months Ended
                                                              June 30,                            June 30,
     (in thousands)                                    2003              2002              2003               2002
                                                  --------------     -------------    ---------------    --------------
     Revenues                                           $ 70,815          $ 64,510          $ 225,041         $ 150,625
                                                  ==============     =============    ===============    ==============

     Earnings (loss) before income taxes                 $ 4,119          $(5,514)           $ 22,602          $  8,522
     Income tax expense (benefit)                          1,606           (4,201)              8,799             1,369
                                                  --------------     -------------    ---------------    --------------
     Net earnings (loss) from discontinued
     operations                                          $ 2,513          $(1,313)           $ 13,803          $  7,153
                                                  ==============     =============    ===============    ==============
</TABLE>

     The major  balance  sheet  classes  included in assets and  liabilities  of
     discontinued operations in the Consolidated Balance Sheets are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                         June 30,           December 31,
     (in thousands)                                        2003                2002
                                                      ---------------    ----------------
     Utility plant, net                                     $ 403,515            $398,931
     Current assets                                            69,743              72,821
     Deferred debits and other assets                          18,526              18,677
                                                      ---------------    ----------------
          Assets of discontinued operations                 $ 491,784            $490,429
                                                      ===============    ================

     Current liabilities                                     $ 68,884            $ 76,372
     Deferred credits and other liabilities                    50,174              48,395
                                                      ---------------    ----------------
          Liabilities of discontinued operations             $119,058            $124,767
                                                      ===============    ================
</TABLE>

     The  Company's  equity  investment  in ENCNG of $7.7 million as of June 30,
     2003 and December 31, 2002 is included in miscellaneous  other property and
     investments in the Consolidated Balance Sheets.


                                       10
<PAGE>

     B. 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.  A series of sales  transactions is
     expected to take place throughout  2003. An estimated  impairment on assets
     held for sale was  recognized in December 2002 to write-down  the assets to
     fair value less costs to sell.

     The assets of Railcar  Ltd.  have been  grouped as assets held for sale and
     are  included  in other  current  assets in the  accompanying  Consolidated
     Balance  Sheets as of June 30,  2003.  The  assets  are  recorded  at $24.0
     million  and $23.6  million  as of June 30,  2003 and  December  31,  2002,
     respectively.

     On March  12,  2003,  the  Company  signed a letter  of  intent to sell the
     majority of Railcar Ltd. assets to The Andersons,  Inc. The majority of the
     proceeds  from  the sale  will be used by the  Company  to pay off  certain
     Railcar Ltd. off balance sheet lease  obligations for railcars that will be
     transferred to The Andersons,  Inc. as part of the sales  transaction.  The
     transaction is subject to various closing conditions  including  financing,
     due diligence and the completion of a definitive purchase agreement.

4.   FINANCIAL INFORMATION BY BUSINESS SEGMENT

     The Company currently has the following business segments:  Progress Energy
     Carolinas  Electric (PEC Electric),  Progress Energy Florida (PEF),  Fuels,
     Competitive  Commercial  Operations  (CCO),  Rail Services (Rail) and Other
     Businesses (Other).  Prior to 2003, Fuels and CCO were reported together as
     the Progress Ventures business segment and corporate costs were included in
     the Other segment.  These  reportable  segment  changes reflect the current
     management  structure.  Additionally,  earnings from wholesale customers of
     the regulated  plants have  previously  been reported in both the regulated
     utilities'  results  and  the  results  of  Progress  Ventures.   With  the
     realignment  of the  reportable  business  segments,  these results are now
     included in each of the respective regulated utilities' results only.

     The  PEC  Electric  and  PEF  segments  are  engaged  in  the   generation,
     transmission,  distribution  and  sale  of  electric  energy  primarily  in
     portions of North  Carolina,  South  Carolina and Florida.  These  electric
     operations  are subject to the rules and  regulations of the Federal Energy
     Regulatory  Commission  (FERC),  the NCUC, the Public Service Commission of
     South Carolina  (SCPSC),  the Florida Public Service  Commission (FPSC) and
     the U.S. Nuclear Regulatory Commission (NRC).

     Fuels' operations,  which are located in the United States, include natural
     gas drilling and production,  coal mining and terminals, and the production
     of synthetic fuels.

     CCO   operations,   which  are  located  in  the  United  States,   include
     nonregulated electric generation operations and limited trading activities.
     The increase in revenue and income from  continuing  operations for the six
     months  ended  June  30,  2003  is  primarily  due to a  tolling  agreement
     termination payment from Dynegy.

     Rail  operations  include  railcar repair,  rail parts  reconditioning  and
     sales,  railcar leasing  (primarily  through  Railcar Ltd.) 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.  Rail's primary operations are located
     in the United States, with limited operation in Mexico and Canada.

     Other  primarily  includes  operations  in the  United  States of  Progress
     Telecommunications  Corporation and Caronet, Inc. (collectively referred to
     as Progress Telecom) and other  nonregulated  subsidiaries that do not meet
     the disclosure requirements of SFAS No. 131, "Disclosures about Segments of
     an Enterprise and Related Information."

     The Company's  corporate  operations  include the operations of the holding
     company,  Progress Energy Service Company, LLC and intercompany elimination
     transactions.  The operating  business segments combined with the corporate
     operations  represent the total  continuing  operations of the Company.  In
     prior periods, Corporate was reported as a component of the Other segment.

     The  discontinued  operations  related  to  NCNG  are  not  included  as an
     operating segment.

     The following  summarizes the revenues,  income from continuing  operations
     and assets (excluding  assets of discontinued  operations) for the business
     segments,  corporate and total Progress  Energy.  The 2002  information has
     been restated to align with the 2003 segment structure.

                                       11
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                                        Income
                                                                   Revenues                              from
                                              ---------------------------------------------------     Continuing
     (in thousands)                           Unaffiliated     Intersegment           Total           Operations
                                              ------------    ---------------    ----------------    ------------
     Three Months Ended June 30, 2003
        PEC Electric                           $   816,240          $       -         $   816,240       $  88,394
        PEF                                        766,547                  -             766,547          61,359
        Fuels                                      166,918             89,861             256,779          53,807
        CCO                                         33,283                  -              33,283           2,383
        Rail                                       213,740                  -             213,740           2,192
        Other                                       15,903              1,460              17,363           1,200
        Corporate                                       53            (91,321)            (91,268)        (59,025)
                                              ------------    ---------------    ----------------    ------------
     Consolidated totals                       $ 2,012,684          $       -         $ 2,012,684       $ 150,310
                                              ------------    ---------------    ----------------    ------------

     Three Months Ended June 30, 2002
        PEC Electric                           $   834,658          $       -         $   834,658       $ 131,690
        PEF                                        765,923                  -             765,923          76,753
        Fuels                                      112,558             74,896             187,454          46,729
        CCO                                         23,902                  -              23,902           6,738
        Rail                                       196,489                  -             196,489           2,947
        Other                                       25,325              1,454              26,779         (8,353)
        Corporate                                        -            (76,350)            (76,350)       (134,571)
                                              ------------    ---------------    ----------------    ------------
     Consolidated totals                       $ 1,958,855          $       -         $ 1,958,855       $ 121,933
                                              ------------    ---------------    ----------------    ------------


                                                                                                        Income
                                                                   Revenues                              from
                                              ---------------------------------------------------     Continuing
     (in thousands)                           Unaffiliated     Intersegment           Total           Operations        Assets
                                              ------------    ---------------    ----------------    ------------    -------------
     Six Months Ended June 30, 2003
        PEC Electric                           $ 1,741,710          $       -         $ 1,741,710       $ 223,264     $  9,568,769
        PEF                                      1,494,964                  -           1,494,964         132,116        5,912,152
        Fuels                                      297,769            174,068             471,837          80,385        1,215,374
        CCO                                         70,833                  -              70,833          10,909        1,712,985
        Rail                                       391,549                  -             391,549         (1,204)          503,897
        Other                                       31,758              2,957              34,715           1,869          305,535
        Corporate                                      106           (177,025)           (176,919)       (100,163)       3,918,457
                                              ------------    ---------------    ----------------    ------------    -------------
      Consolidated totals                      $ 4,028,689          $       -         $ 4,028,689       $ 347,176     $ 23,137,169
                                              ------------    ---------------    ----------------    ------------    -------------

     Six Months Ended June 30, 2002
        PEC Electric                           $ 1,646,139          $       -         $ 1,646,139       $ 217,222     $  8,669,993
        PEF                                      1,452,364                  -           1,452,364         134,496        4,967,998
        Fuels                                      215,824            150,003             365,827          88,324          963,109
        CCO                                         32,949                  -              32,949           4,627        1,277,824
        Rail                                       351,456                  -             351,456           2,246          607,617
        Other                                       47,424              2,908              50,332         (13,202)         803,837
        Corporate                                        -           (152,911)           (152,911)       (187,719)       4,008,041
                                              ------------    ---------------    ----------------    ------------    -------------
      Consolidated totals                      $ 3,746,156          $       -         $ 3,746,156       $ 245,994     $ 21,298,419
                                              ------------    ---------------    ----------------    ------------    -------------
</TABLE>

5.   IMPACT OF NEW ACCOUNTING STANDARDS

     SFAS  No.  148,  "Accounting  for  Stock-Based  Compensation"
     The  Company  measures  compensation  expense  for  stock  options  as  the
     difference  between the market  price of its common  stock and the exercise
     price of the option at the grant date. Accordingly, no compensation expense
     has been recognized for stock option grants.

     For  purposes  of the pro  forma  disclosures  required  by SFAS  No.  148,
     "Accounting for  Stock-Based  Compensation - Transition and Disclosure - an
     Amendment  of FASB  Statement  No.  123," the  estimated  fair value of the
     Company's  stock options is amortized to expense over the options'  vesting
     period.  The  Company's  information  related  to the pro  forma  impact on
     earnings and earnings per share  assuming  stock  options were expensed for
     the three and six months ended June 30 is as follows:

                                       12
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in thousands except per share data)                      Three Months Ended June 30,     Six Months Ended June 30,
                                                              ------------------------------  ----------------------------
                                                                   2003            2002           2003           2002
                                                              ---------------  -------------  ------------  --------------
     Net income, as reported                                        $ 152,823      $ 120,620     $ 360,979       $ 253,147
     Deduct:  Total stock option expense determined under fair
       value method for all awards, net of related tax effects          1,697          1,320         4,276           3,112
                                                              ---------------  -------------  ------------  --------------
     Pro forma net income                                           $ 151,126      $ 119,300     $ 356,703       $ 250,035
                                                              ===============  =============  ============  ==============

     Basic earnings per share
       As reported                                                  $    0.65      $    0.56     $    1.54       $    1.18
       Pro forma                                                    $    0.64      $    0.55     $    1.52       $    1.17

     Fully diluted earnings per share
       As reported                                                  $    0.64      $    0.56     $    1.53       $    1.18
       Pro forma                                                    $    0.64      $    0.55     $    1.51       $    1.16
</TABLE>

     In April 2003, the Financial  Accounting  Standards  Board (FASB)  approved
     certain decisions on its stock-based  compensation project. Some of the key
     decisions reached by the FASB were that stock-based  compensation should be
     recognized  in the  income  statement  as an expense  and that the  expense
     should be measured as of the grant date at fair value. A significant  issue
     yet to be resolved by the FASB is the determination of the appropriate fair
     value measure.  The FASB continues to deliberate  additional issues in this
     project;  however,  the FASB plans to issue an exposure  draft in 2003 that
     could become effective in 2004.

     Derivative Instruments and Hedging Activities
     In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
     Derivative  Instruments and Hedging  Activities."  The statement amends and
     clarifies SFAS No. 133 on accounting for derivative instruments,  including
     certain derivative instruments embedded in other contracts, and for hedging
     activities.  The new guidance  incorporates  decisions  made as part of the
     Derivatives  Implementation  Group  (DIG)  process,  as well  as  decisions
     regarding  implementation  issues raised in relation to the  application of
     the  definition  of a derivative.  SFAS No. 149 is generally  effective for
     contracts  entered  into or modified  after June 30,  2003.  The Company is
     currently  evaluating what effects, if any, this statement will have on its
     results of operations and financial position.

     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   Derivative
     Implementation  Group's C11  guidance,  relates to the pricing of contracts
     that include broad market indices (e.g., CPI). In particular, that guidance
     discusses  whether the pricing in a contract  that  contains  broad  market
     indices 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).
     In late June 2003,  the FASB issued final  superseding  guidance (DIG Issue
     C20) on this issue,  which is  significantly  different  from the tentative
     superseding  guidance  that was issued in April 2003.  The new  guidance is
     effective  October 1, 2003 for the  Company.  DIG Issue C20  specifies  new
     pricing-related  criteria for qualifying as a normal  purchase or sale, and
     it requires a special transition adjustment as of October 1, 2003.

     PEC has  determined  that it has one  existing  "normal"  contract  that is
     affected by this revised guidance.  PEC is in the process of evaluating the
     revised   guidance  and  related   contract  to  determine  the  transition
     adjustment  that will be necessary and to determine if the contract will be
     required to be recorded at fair value subsequent to October 1, 2003.

     SFAS  No.  150,   "Accounting  for  Certain   Financial   Instruments  with
     Characteristics  of Both  Liabilities  and  Equity"
     In May  2003,  the  FASB  issued  SFAS No.  150,  "Accounting  for  Certain
     Financial Instruments with Characteristics of Both Liabilities and Equity."
     SFAS 150  establishes  standards for how an issuer  classifies and measures
     certain financial  instruments with characteristics of both liabilities and
     equity. The financial  instruments within the scope of SFAS No. 150 include
     mandatorily redeemable stock, obligations to repurchase the issuer's equity
     shares by transferring  assets, and certain obligations to issue a variable
     number of shares. SFAS No. 150 is effective  immediately for such financial
     instruments  entered into or modified  after May 31, 2003, and is effective
     for previously  issued  financial  instruments  within its scope on July 1,
     2003.

                                       13
<PAGE>

     Upon the Company's  adoption of the FIN No. 46,  "Consolidation of Variable
     Interest Entities" (see below), the FPC Capital I Preferred Securities,  as
     discussed  in Note  12,  are  anticipated  to be  deconsolidated  from  the
     Company's  financial  statements  effective  July 1, 2003.  Therefore,  the
     Company  does not  expect the  adoption  of SFAS No. 150 to have a material
     impact on its financial position or results of operations.

     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 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.  During  the  first  six  months of 2003,  the  Company  did not
     participate  in the creation of, or obtain a new variable  interest in, any
     variable  interest entity.  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  is  currently   evaluating   what   effects,   if  any,  this
     interpretation  will  have  on its  results  of  operations  and  financial
     position.  During this evaluation process, several arrangements through its
     Railcar Ltd.  subsidiary have been identified to which this  interpretation
     may apply.  These  arrangements  include an agreement  with  Railcar  Asset
     Financing  Trust (RAFT),  a  receivables  securitization  trust,  and seven
     synthetic  leases.  Because  the  Company  expects to sell the  majority of
     Railcar Ltd. during 2003 (See Note 3B) and divest of its interests in these
     arrangements,  the  application  of FIN No.  46 is not  expected  to have a
     material impact with respect to these arrangements.  If these interests are
     not divested as currently  expected,  the maximum  cash  obligations  under
     these arrangements  total  approximately $54 million.  However,  management
     believes the maximum loss exposure would be significantly  reduced based on
     the  current  fair  values  of  the  underlying  assets  related  to  these
     arrangements.

     In addition,  the Company is also evaluating  certain other  investments to
     determine if they require  consolidation or disclosure upon adoption of FIN
     No. 46. These include  investments in approximately  50 Affordable  Housing
     properties  eligible  for  Section 42 tax credits of the  Internal  Revenue
     Service Code (Section 42). The Company  divested  approximately 30 of these
     Affordable Housing  investments in July 2003, and therefore the application
     of FIN No. 46 is not  expected to have a material  impact  with  respect to
     these 30  investments.  It is reasonably  possible that the Company will be
     required  to  consolidate  some  of the  remaining  20  Affordable  Housing
     entities that are  currently  accounted  for under the equity  method.  The
     maximum  exposure  to loss  as a  result  of the  Company's  total  funding
     commitments  for  the  remaining  20  Affordable  Housing   investments  is
     approximately $23.9 million. However, management believes the total loss of
     its  investments  is unlikely given the nature of the  investments  and the
     utilization of certain Section 42 tax credits to date.

     The  implementation  of FIN No. 46 may require  deconsolidation  of certain
     previously  consolidated  entities.  Upon adoption, the company anticipates
     deconsolidating   the  FPC  Capital  I  Trust,  which  holds  FPC-obligated
     mandatorily  redeemable preferred  securities.  The Company will reflect it
     subordinate note obligation to the Trust as detailed in Note 12. Therefore,
     the deconsolidation is not expected to have a material effect.

     The Company is in the final  stages of  completing  the adoption of FIN No.
     46, but having considered the facts described  herein,  does not expect the
     results to have a material impact on its consolidated  financial  position,
     results of operations or liquidity.

     EITF Issue No. 03-04, "Accounting for 'Cash Balance' Pension Plans"
     In May  2003,  the  EITF  reached  consensus  in EITF  Issue  No.  03-04 to
     specifically address the accounting for certain cash balance pension plans.
     The consensus reached in EITF Issue No. 03-04 requires certain cash balance
     pension  plans to be  accounted  for as  defined  benefit  plans.  For cash
     balance plans  described in the consensus,  the consensus also requires the
     use of the  traditional  unit credit  method for purposes of measuring  the
     benefit  obligation  and annual cost of  benefits  earned as opposed to the
     projected unit credit method.  The Company has  historically  accounted for
     its cash balance plans as defined  benefit plans;  however,  the Company is
     required  to adopt the  measurement  provisions  of EITF  03-04 at its cash
     balance plans' next  measurement date of December 31, 2003. Any differences
     in the measurement of the obligations as a result of applying the consensus
     will be reported as a component of actuarial  gain or loss.  The Company is
     currently  evaluating  what  effects EITF 03-04 will have on its results of
     operations and financial position.

                                       14
<PAGE>

6.   ASSET RETIREMENT OBLIGATIONS

     SFAS No.  143,  "Accounting  for Asset  Retirement  Obligations,"  provides
     accounting  and   disclosure   requirements   for  retirement   obligations
     associated with long-lived  assets and was adopted by the Company 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 were 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.  For assets acquired  through  acquisition,  the cumulative
     effect was based on the acquisition date.

     Upon  adoption  of SFAS No.  143,  the Company  recorded  asset  retirement
     obligations (AROs) totaling $1,182.5 million for nuclear decommissioning of
     radiated  plant at PEC and PEF.  The  Company  used an  expected  cash flow
     approach  to measure  these  obligations.  This  amount  includes  accruals
     recorded prior to adoption  totaling $775.2 million,  which were previously
     recorded in accumulated  depreciation.  The related asset retirement costs,
     net of  accumulated  depreciation,  recorded upon adoption  totaled  $367.5
     million for  regulated  operations.  The adoption of this  statement had no
     impact on the income of the regulated entities,  as the effects were offset
     by the  establishment  of a  regulatory  asset and a  regulatory  liability
     pursuant to SFAS No. 71,  "Accounting  for the Effects of Certain  Types of
     Regulation." A regulatory  asset was recorded  related to PEC in the amount
     of $271.1 million,  representing  the cumulative  accretion and accumulated
     depreciation  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,  less amounts previously recorded. A regulatory liability
     was recorded  related to PEF in the amount of $231.3 million,  representing
     the amount by which previously  recorded  accruals  exceeded the cumulative
     accretion and  accumulated  depreciation  for the time period from the date
     the  liability  would  have  been  recognized  had the  provisions  of this
     statement  been in effect at the date of the  acquisition  of the assets by
     Progress Energy to the date of adoption.

     Funds set aside in the Company's nuclear decommissioning trust fund for the
     nuclear  decommissioning  liability totaled $861.8 million at June 30, 2003
     and $796.8 million at December 31, 2002.

     The Company also recorded AROs  totaling  $10.3 million for synthetic  fuel
     operations of PVI and coal mine  operations,  synthetic fuel operations and
     gas production of Progress Fuels Corporation.  The Company used an expected
     cash flow  approach to measure  these  obligations.  This  amount  includes
     accruals  recorded  prior to  adoption  totaling  $4.6  million,  which was
     previously recorded in other liabilities and deferred credits.  The related
     asset  retirement  costs,  net of accumulated  depreciation,  recorded upon
     adoption totaled $7.0 million for nonregulated  operations.  The cumulative
     effect of  initial  adoption  of this  statement  related  to  nonregulated
     operations  was $1.3  million  of pre-tax  income.  The  ongoing  impact on
     earnings  related to accretion and depreciation was not significant for the
     three or six months ended June 30, 2003.

     Pro forma net income has not been presented for prior years because the pro
     forma  application of SFAS No. 143 to prior years would result in pro forma
     net income not materially different from the actual amounts reported.

     The Company has  identified  but not  recognized  AROs  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.  As of June 30, 2003,
     the  portions of such costs not  representing  AROs under SFAS No. 143 were
     $882.6 million for PEC,  $940.1 million for PEF and $39.2 million for NCNG.
     The amounts for PEC and PEF are included in accumulated depreciation on the
     accompanying  Consolidated  Balance Sheets. The amount for NCNG is included
     as an  offset  to assets of  discontinued  operations  on the  accompanying
     Consolidated  Balance  Sheets.  PEC  and PEF  have  collected  amounts  for
     non-radiated  areas at nuclear  facilities,  which do not  represent  asset
     retirement obligations. The amounts at June 30, 2003 were $63.5 million for
     PEC  and  $61.5  million  for  PEF,   which  are  included  in  accumulated
     depreciation  on  the  accompanying   Consolidated   Balance  Sheets.   PEF
     previously  collected  amounts for  dismantlement of its fossil  generation
     plants.  As of June 30, 2003,  this  amounted to $142.2  million,  which is
     included  in  accumulated  depreciation  on the  accompanying  Consolidated
     Balance  Sheets.  This  collection was suspended  pursuant to the rate case
     settlement discussed in Note 13A.

                                       15
<PAGE>

     PEC filed a request  with the NCUC  requesting  deferral of the  difference
     between  expense  pursuant  to SFAS  No.  143  and  expense  as  previously
     determined  by the NCUC.  The NCUC  granted the  deferral of the January 1,
     2003 cumulative adjustment.  Because the clean air legislation discussed in
     Note 15 under "Air Quality" contained a prohibition  against cost deferrals
     unless  certain  criteria  are met,  the NCUC  denied the  deferral  of the
     ongoing  effects.  The Company has provided  additional  information to the
     NCUC that it believes will demonstrate that deferral of the ongoing effects
     should also be allowed. Since the NCUC order denied deferral of the ongoing
     effects,  PEC ceased  deferral  of the  ongoing  effects  during the second
     quarter  for the six  months  ended  June 30,  2003  related  to its  North
     Carolina retail  jurisdiction.  Pre-tax income for the three and six months
     ended  June 30,  2003  increased  by  approximately  $13.6  million,  which
     represents a decrease in non-ARO cost of removal expense,  partially offset
     by an increase in decommissioning expense.

     On April 8, 2003,  the SCPSC  approved a joint  request by PEC, Duke Energy
     and South  Carolina  Electric  and Gas Company for an  accounting  order to
     authorize the deferral of all cumulative and prospective effects related to
     the adoption of SFAS No. 143.

     On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
     development to adopt provisions relating to accounting for asset retirement
     obligations  under SFAS No. 143.  Accompanying  the notice was a draft rule
     presented  by the Staff which adopts the  provisions  of SFAS No. 143 along
     with the requirement to record the difference between amounts prescribed by
     the FPSC and those used in the  application  of SFAS No. 143 as  regulatory
     assets or regulatory  liabilities,  which was accepted by all parties.  The
     Commission  approved  the draft  rule in June  2003,  and a final  order is
     expected in the third quarter of 2003.

7.   GOODWILL AND OTHER INTANGIBLE ASSETS

     SFAS No.  142,  "Goodwill  and  Other  Intangible  Assets,"  requires  that
     goodwill be tested for  impairment  at least  annually and more  frequently
     when indicators of impairment  exist. SFAS No. 142 requires a two-step fair
     value-based  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.  This  assessment  could  result in  periodic  impairment
     charges.  The Company performed the annual goodwill impairment test for the
     CCO  segment  in the  first  quarter  of  2003,  and  the  annual  goodwill
     impairment test for the PEC Electric and PEF segments in the second quarter
     of 2003, both of which indicated no impairment.

     During 2002, the Company  acquired  Westchester Gas Company  (Westchester).
     The purchase  price was  finalized  during the first  quarter 2003 with the
     purchase price being primarily  allocated to fixed assets including oil and
     gas properties. No goodwill was recorded.

     The carrying  amounts of goodwill at June 30, 2003, by reportable  segment,
     are $1.9 billion, $1.7 billion and $64.1 million for PEC Electric,  PEF and
     CCO, respectively.

     The gross carrying  amount and  accumulated  amortization  of the Company's
     intangible assets as of June 30, 2003 and December 31, 2002 are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                            June 30, 2003                   December 31, 2002
                                    ------------------------------    -----------------------------
     (in thousands)                 Gross Carrying     Accumulated    Gross Carrying    Accumulated
                                        Amount        Amortization        Amount       Amortization
                                    -------------- ---------------    -------------- --------------
     Synthetic fuel intangibles          $ 140,469       $(54,717)         $ 140,469      $(45,189)
     Power agreements                      221,192        (10,073)            33,000        (5,593)
     Other                                  53,182         (9,453)            40,968        (7,792)
                                    -------------- ---------------    -------------- --------------
                 Total                   $ 414,843       $(74,243)         $ 214,437      $(58,574)
                                    -------------- ---------------    -------------- --------------
</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 Service
     Code (the Code) in December 2007.

     On May 31, 2003, PVI acquired from Williams Energy Marketing and Trading, a
     subsidiary of The Williams Companies,  Inc., a long-term  full-requirements
     power supply agreement at fixed prices with Jackson,  located in Jefferson,
     Georgia for $188.2 million.  Assignment of Williams' responsibilities under
     the  contract  began in June  2003  and  terminates  in 2015,  with a first
     refusal option to extend for five years. The agreement  includes the use of
     640 megawatts  (MW) of contracted  Georgia System  generation  comprised of
     nuclear,  coal,  gas and  pumped-storage  hydro  resources.  The intangible

                                       16
<PAGE>

     related to this power  agreement is being  amortized  based on the economic
     benefits of the contract.  As part of the acquisition of generating  assets
     from LG&E Energy  Corp.  on February  15,  2002,  power  agreements  of $33
     million were recorded and are amortized  based on the economic  benefits of
     the contracts through December 31, 2004, which approximates straight-line.

     Other  intangibles  are primarily  customer  contracts and permits that are
     amortized over their respective  lives. Of the increase in other intangible
     assets,  $9.2 million relates to customer contracts acquired as part of the
     Westchester acquisition, which was identified as an intangible in the final
     purchase price allocation.

     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 three  months  ended June 30, 2003 and 2002,
     respectively,  was $8.5  million  and $8.1  million.  Amortization  expense
     recorded on  intangible  assets for the six months  ended June 30, 2003 and
     2002,  respectively,  was $15.7  million and $16.2  million.  The estimated
     amortization  expense  for  intangible  assets for 2003  through  2007,  in
     millions,   is  approximately   $36.7,   $41.3,  $34.8,  $35.9  and  $36.1,
     respectively.

8.   COMPREHENSIVE INCOME

     Comprehensive  income for the three and six months  ended June 30, 2003 was
     $150.6 million and $358.2 million,  respectively.  Comprehensive income for
     the three and six months ended June 30, 2002 was $119.6  million and $256.4
     million,  respectively.  Items of other comprehensive  income for the three
     month  periods  consisted  primarily  of  changes  in  the  fair  value  of
     derivatives  used to hedge cash flows related to interest on long-term debt
     and gas sales.

9.   FINANCING ACTIVITIES

     On February 21,  2003,  PEF issued $425  million of First  Mortgage  Bonds,
     4.80% Series,  Due March 1, 2013 and $225 million of First Mortgage  Bonds,
     5.90% Series,  Due March 1, 2033.  Proceeds from this issuance were used to
     repay the balance of its  outstanding  commercial  paper,  to refinance its
     secured and unsecured  indebtedness,  including  PEF's First Mortgage Bonds
     6.125% Series Due March 1, 2003,  and to redeem the  aggregate  outstanding
     balance of its 8% First Mortgage Bonds Due 2022.

     On March 1, 2003, $70 million of PEF First Mortgage  Bonds,  6.125% Series,
     matured and were retired.

     On March 24, 2003,  PEF redeemed $150 million of First Mortgage  Bonds,  8%
     Series,  Due  December 1, 2022 at 103.75% of the  principal  amount of such
     bonds.

     In March  2003,  Progress  Genco  Ventures,  LLC  (Genco),  a wholly  owned
     subsidiary  of PVI,  terminated  its $50  million  working  capital  credit
     facility. A related  construction  facility initially provided for Genco to
     draw up to $260 million. The amount outstanding under this facility is $241
     million  as of June 30,  2003.  During  the  second  quarter  of 2003 Genco
     determined  it did  not  need to  make  any  additional  draws  under  this
     facility.  As a result of this  decision,  the drawn amount of $241 million
     will not increase.

     On April 1,  2003,  PEF  entered  into a new $200  million  364-day  credit
     agreement and a new $200 million three-year credit agreement, replacing its
     prior credit  facilities (which had been a $90 million 364-day facility and
     a $200 million five-year facility). The new PEF credit facilities contain a
     defined  maximum  total debt to total  capital ratio of 65%; as of June 30,
     2003 the calculated ratio was 52.6%. The new credit facilities also contain
     a requirement  that the ratio of EBITDA,  as defined in the facilities,  to
     interest  expense to be at least 3 to 1; as of June 30, 2003 the calculated
     ratio was 8.7 to 1.

     Also on April 1, 2003, PEC reduced the size of its existing  364-day credit
     facility  from  $285  million  to $165  million.  The  other  terms of this
     facility were not changed.  On July 30, 2003,  PEC renewed its $165 million
     364-day credit  agreement.  PEC's $285 million  three-year credit agreement
     entered into in July 2002 remains in place,  for total  facilities  of $450
     million.

     On May 27, 2003,  PEC redeemed $150 million of First Mortgage  Bonds,  7.5%
     Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds;
     PEC funded the redemption with commercial paper.

                                       17
<PAGE>

     On July 14, 2003,  PEC  announced  the  redemption of $100 million of First
     Mortgage Bonds,  6.875% Series Due August 15, 2023 at 102.84%.  The date of
     the redemption  will be August 15, 2003. PEC will fund the redemption  with
     commercial paper.

     For the three months ended June 30, 2003, the Company issued  approximately
     2.4 million shares representing  approximately $98 million in proceeds from
     its Investor Plus Stock Purchase Plan and its employee benefit plans during
     the second quarter. For the six months ended June 30, 2003, the Company has
     issued 4.2 million shares through these plans,  resulting in  approximately
     $172 million of cash proceeds.

10.  RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

     Progress Energy and its  subsidiaries  are exposed to various risks related
     to  changes  in  market  conditions.  The  Company  has a  risk  management
     committee  that is  chaired by the Chief  Financial  Officer  and  includes
     senior  executives  from  various  business  groups.  The  risk  management
     committee is responsible for  administering  risk  management  policies and
     monitoring compliance with those policies by all subsidiaries.

     The Company manages its market risk in accordance with its established risk
     management  policies,  which may include  entering into various  derivative
     transactions.

     Progress  Energy uses interest rate  derivative  instruments  to adjust the
     fixed and variable rate debt  components of its debt portfolio and to hedge
     interest  rates with regard to future fixed rate debt  issuances.  Treasury
     rate lock agreements were terminated in conjunction with the pricing of the
     PEF First  Mortgage  Bonds in February 2003. The loss on the agreements was
     deferred  and is  being  amortized  over  the  life of the  bonds  as these
     agreements had been designated as cash flow hedges for accounting purposes.

     Progress  Energy  currently  has $850 million of fixed rate debt swapped to
     floating rate debt by executing interest rate derivative agreements.  Under
     terms of these swap rate  agreements,  Progress Energy will receive a fixed
     rate and pay a  floating  rate  based on 3-month  LIBOR.  These  agreements
     expire in March of 2006, April 2007 and October 2008.

     In March,  April and June of 2003,  PEC entered into treasury rate locks to
     hedge its  exposure to interest  rates with regard to a future  issuance of
     debt.  These  agreements have a  computational  period of ten years and are
     designated as cash flow hedges for accounting purposes. The agreements have
     a total notional amount of $60 million.

     Progress Fuels Corporation  periodically enters into derivative instruments
     to hedge its  exposure to price  fluctuations  on natural gas sales.  As of
     June 30, 2003,  Progress Fuels  Corporation had  approximately  16.6 Bcf of
     cash flow hedges in place for its natural gas  production.  These positions
     span  the  remainder  of 2003  and  extend  through  December  2004.  These
     instruments  did not have a material  impact on the Company's  consolidated
     financial position or results of operations.

     Genco has a series of interest rate collars to hedge floating rate exposure
     associated with the construction  credit facility.  These collars hedge 75%
     of the drawn facility balance through March of 2007.

     The notional  amounts of the above  contracts  are not exchanged and do not
     represent   exposure  to  credit  loss.  In  the  event  of  default  by  a
     counterparty,  the risk in the  transaction  is the cost of  replacing  the
     agreements  at current  market  rates.  Progress  Energy  only  enters into
     interest  rate  derivative  agreements  with banks with  credit  ratings of
     single A or better.

11.  EARNINGS PER COMMON SHARE

     A  reconciliation   of  the   weighted-average   number  of  common  shares
     outstanding  for basic and  dilutive  earnings  per  share  purposes  is as
     follows (in thousands):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                Three Months Ended June 30,         Six Months Ended June 30,
                                               -----------------------------     -------------------------------
                                                   2003             2002             2003                 2002
                                               -------------    ------------     ------------    ---------------
                                               -------------
     Weighted-average common shares - basic          236,057         215,007          234,755            213,999
     Restricted stock awards                           1,004             734              967                690
     Stock options                                       140             333               23                224
                                               -------------    ------------     ------------    ---------------
                                               -------------    ------------
     Weighted-average shares - fully dilutive        237,201         216,074          235,745            214,913
                                               -------------    ------------     ------------    ---------------
</TABLE>

                                       18
<PAGE>

12.  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 (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.  Upon adoption of FIN No. 46, the
     Company  anticipates  deconsolidating  the FPC Capital I Trust which is not
     expected to have a material effect on the consolidated  financial position,
     results of operations or liquidity (See Note 5).

13.  REGULATORY MATTERS

     A. Retail Rate Matters

     In conjunction  with the acquisition of NCNG, PEC 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.  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. In September 2002, the NCUC issued its order approving
     the $4.1 million rate increase.  The rate increase was effective October 1,
     2002.  NCNG filed a general rate case with the NCUC on March 31, 2003. NCNG
     anticipates  that new rates,  if approved,  will go into effect in November
     2003, after the terms of the joint  stipulation  agreement expire (See Note
     3A).

     On  March  27,  2002,  the  parties  in  PEF'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  provides that PEF will operate under a Revenue Sharing Incentive
     Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.

     The Plan establishes annual revenue caps and sharing  thresholds.  The Plan
     provides that all retail base revenues between an established threshold and
     cap will be shared - a 2/3 share to be refunded to PEF's retail  customers,
     and a 1/3 share to be received by PEF's shareholders.  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  was limited to 67.1% of the retail base rate  revenues
     that exceeded the 2002 cap. The retail base rate revenue sharing  threshold
     amounts for 2003 are $1.333 billion and will increase $37 million each year
     thereafter. The retail base revenue cap for 2003 is $1.393 billion and will
     increase $37 million each year  thereafter.  As of December 31, 2002,  $4.7
     million was  accrued  and was  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

                                       19
<PAGE>

     disputed  PEF's  calculation  of  retail  revenue  subject  to  refund  and
     contended that the refund should be approximately  $23 million.  On July 9,
     2003,  the FPSC ruled that PEF must provide an additional  $18.4 million to
     its retail customers related to the 2002 revenue sharing  calculation.  PEF
     recorded  this  refund in the second  quarter  of 2003 as a charge  against
     electric  operating  revenue  and will  refund this amount by no later than
     October  31,  2003.  In the second  quarter of 2003,  PEF also  recorded an
     additional  accrual of $9.5  million  related  to  estimated  2003  revenue
     sharing.

     On March 4, 2003,  the FPSC  approved  PEF's  petition 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 recent Venezuelan oil
     workers' strike have put upward  pressure on commodity  prices that was not
     anticipated  by PEF when fuel factors for 2003 were approved by the FPSC in
     November 2002. New rates became effective on March 28, 2003.

     B. Regional Transmission Organizations

     In early 2000, the 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,  PEF,  along with Florida  Power & Light  Company and
     Tampa  Electric  Company,   filed  with  the  FERC,  in  October  2000,  an
     application  for  approval of a  GridFlorida  RTO. In March 2001,  the FERC
     issued an order provisionally  approving GridFlorida.  PEC, along with Duke
     Energy  Corporation and South Carolina  Electric & Gas Company,  filed with
     the FERC, for approval of a GridSouth RTO. In July 2001, the 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.  PEF  and PEC
     participated   in  the  mediation.   The  FERC  has  not  issued  an  order
     specifically on this mediation. In July 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). 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. PEF and
     PEC, as  subsidiaries  of Progress  Energy,  filed comments on November 15,
     2002 and supplemental  comments on January 10, 2003. On April 28, 2003, the
     FERC released a White Paper on the  Wholesale  Market  Platform.  The White
     Paper provides an overview of what the FERC currently intends to include in
     a  final  rule  in the  SMD  NOPR  docket.  The  White  Paper  retains  the
     fundamental  and most protested  aspects of SMD NOPR,  including  mandatory
     RTOs and the FERC's  assertion  of  jurisdiction  over  certain  aspects of
     retail service.  PEF and PEC, as subsidiaries of Progress  Energy,  plan to
     file  comments  on the White  Paper.  The FERC has also  indicated  that it
     expects  to  issue a final  rule  after  Congress  votes  this  fall on the
     proposed  House and Senate Energy  Bills.  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  $31.2  million  and an  immaterial  amount  invested  in
     GridSouth and  GridFlorida,  respectively,  at June 30, 2003. It is unknown
     what impact the future  proceedings  will have on the  Company's  earnings,
     revenues or prices.

     In October 2002,  the FPSC abated its  proceedings  regarding its review of
     the proposed GridFlorida RTO. The FPSC action to abate the proceedings came
     in response to the Florida  Office at 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.  On June 2, 2003 the Florida  Supreme
     Court  dismissed  the appeal  without  prejudice on the ground that certain
     portions  of the  Commission's  order  constituted  non-final  action.  The
     dismissal is without  prejudice to any party to challenge the  Commission's
     order after all portions are final. A technical conference for the state of
     Florida to be conducted by the FERC is scheduled for September 15, 2003. 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 prices.

14.  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 are as follows:

                                       20
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>


                                                            Three Months Ended June 30,         Six Months Ended June 30,
                                                           ------------------------------    -------------------------------
     (in thousands)                                             2003             2002            2003             2002
                                                           --------------     -----------    ------------    ---------------
     Other income
     Net financial trading gain (loss)                           $     67        $    792       $  (2,632)         $  (1,429)
     Net energy brokered for resale                                (1,369)            124             157               (141)
     Nonregulated energy and delivery services income               5,652           5,862          11,242             12,459
     Contingent value obligation mark-to-market                    (1,677)          1,479               -             12,821
     Investment gains                                                   -           2,960               -              2,960
     AFUDC equity                                                   4,035           1,833           5,914              4,077
     Other                                                          5,299           7,905          10,937             13,049
                                                           --------------     -----------    ------------    ---------------
         Total other income                                      $ 12,007        $ 20,955       $  25,618          $  43,796
                                                           --------------     -----------    ------------    ---------------

     Other expense
     Nonregulated energy and delivery services expenses             5,479           6,248           9,696              9,383
     Donations                                                      3,377           2,736           6,721              7,007
     Investment losses                                              8,644               -           8,644                  -
     Other                                                          3,939          14,311          12,440             23,688
                                                           --------------     -----------    ------------    ---------------
        Total other expense                                      $ 21,439        $ 23,295       $  37,501          $  40,078
                                                           --------------     -----------    ------------    ---------------

     Other, net                                                  $ (9,432)       $ (2,340)      $ (11,883)         $   3,718
                                                           ==============     ===========    ============    ===============
</TABLE>

     Net financial trading gains and losses represent non-asset-backed trades of
     electricity and gas. Net energy brokered for resale represents  electricity
     purchased  for sale to a third  party.  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.  Investment  losses
     represent losses on limited partnership investment funds.

15.  COMMITMENTS AND CONTINGENCIES

     Contingencies and significant changes to the commitments  discussed in Note
     24 of the financial statements included in the Company's 2002 Annual Report
     on Form 10-K are described below.

     A. 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.

     Guarantees  as of June 30,  2003,  are  summarized  in the table  below and
     discussed more fully in the subsequent paragraphs.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)
     Guarantees of performance issued by or on behalf of affiliates
          Guarantees supporting nonregulated portfolio expansion
               and energy marketing and trading activities issued by Progress Energy          $   290.5
          Guarantees supporting energy marketing and trading activities issued by
               subsidiaries of Progress Energy                                                     12.0
          Guarantees supporting nuclear decommissioning                                           276.0
          Guarantee supporting power supply agreements                                            285.0
          Standby letters of credit                                                                49.5
          Surety bonds                                                                            104.3
          Other guarantees                                                                         44.1
     Guarantees issued on behalf of third parties
          Other guarantees                                                                         16.4
                                                                                    -------------------
        Total                                                                                 $ 1,077.8
                                                                                    ===================

</TABLE>

                                       21
<PAGE>

     Guarantees Supporting Nonregulated Portfolio Expansion and Energy Marketing
     and Trading Activities

     Progress  Energy has issued  approximately  $290.5 million of guarantees on
     behalf  of  PVI  and  its  subsidiaries   for  obligations   under  tolling
     agreements,   transmission   agreements,   gas   agreements,   construction
     agreements  and trading  operations.  Approximately  $26.9 million of these
     guarantees  were  issued  during  the year to support  energy  and  trading
     activities.  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 June 30,  2003,  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 of  approximately  $40.0 million
     for the benefit of the Company's counterparties.

     Guarantees Supporting Nuclear Decommissioning

     In 2003, PEC determined that its external funding levels did not fully meet
     the nuclear decommissioning financial assurance levels required by the NRC.
     Therefore, PEC met the financial assurance requirements by obtaining parent
     company guarantees.

     Guarantee Supporting Power Supply Agreements

     On March 20, 2003,  PVI entered into a definitive  agreement  with Williams
     Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc.,
     to acquire a long-term  full-requirements  power supply  agreement at fixed
     prices with  Jackson.  The power supply  agreement  included a  performance
     guarantee by Progress  Energy.  The  transaction  closed  during the second
     quarter of 2003. The Company issued a payment and performance  guarantee to
     Jackson  related to the power supply  agreement of $285.0  million.  In the
     event that Progress  Energy's credit ratings fall below  investment  grade,
     Progress  Energy will be required to provide  additional  security for this
     guarantee  in form and amount (not to exceed $285  million)  acceptable  to
     Jackson.

     Standby Letters of Credit

     The Company has issued standby 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 June 30, 2003, the Company had $104.3 million in surety bonds  purchased
     primarily for purposes such as providing  workers'  compensation  coverage,
     obtaining licenses,  permits and rights-of-way and project performance.  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.

     Other Guarantees

     The Company has other guarantees  outstanding  related  primarily to prompt
     performance  payments,  lease  obligations  and other  payments  subject to
     contingencies.

     As of June 30, 2003,  management does not believe conditions are likely for
     performance under the agreements discussed in this Note 15.

     B. Insurance

     Both  PEC  and PEF are  insured  against  public  liability  for a  nuclear
     incident.  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  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  for each reactor owned per  occurrence.  Effective  August 20,
     2003, the retroactive  premium  assessments will increase to $100.6 million
     per  reactor  from the  current  amount of $88.1  million.  The total limit
     available to cover nuclear liability losses will increase as well from $9.6
     billion to $10.6  billion.  The  annual  retroactive  premium  limit of $10
     million per reactor owned will not change.

                                       22
<PAGE>

     C. Claims and uncertainties

     a)  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.

     PEC  There are 12  former  MGP sites and 14 other  sites or groups of sites
     associated  with PEC that  have  required  or are  anticipated  to  require
     investigation  and/or remediation costs. PEC received insurance proceeds to
     address costs  associated  with  environmental  liabilities  related to its
     involvement with some MGP sites. All eligible expenses related to these are
     charged against a specific fund containing  these proceeds.  As of June 30,
     2003,  approximately  $5.2 million remains in this  centralized fund with a
     related  accrual of $5.2 million  recorded for the  associated  expenses of
     environmental  issues.  As  PEC's  share  of costs  for  investigating  and
     remediating these sites becomes known, the fund is assessed to determine if
     additional  accruals  will be  required.  PEC 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.  PEC
     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,  PEC will accrue
     costs for the sites to the extent its  liability  is probable and the costs
     can be  reasonably  estimated.  Presently,  PEC cannot  determine the total
     costs that may be incurred in connection with the remediation of all sites.

     PEF There are two former  MGP sites and 11 other  active  sites  associated
     with PEF that have  required or are  anticipated  to require  investigation
     and/or   remediation   costs.   As  of  June  30,  2003,  PEF  has  accrued
     approximately $9.4 million,  for probable and reasonably estimable costs at
     these  sites.  PEF does not believe  that it can provide an estimate of the
     reasonably  possible  total  remediation  costs  beyond  what is  currently
     accrued. In 2002, PEF filed a petition for annual recovery of approximately
     $4.0 million in environmental costs through the Environmental Cost Recovery
     Clause with the FPSC. PEF 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,  PEF will  assess  the need to adjust the
     accruals.  These accruals have been recorded on an undiscounted  basis. PEF
     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.
     Presently,  PEF cannot  determine  the total  costs that may be incurred in
     connection with the remediation of all sites.

     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 June 30, 2003, NCNG has accrued  approximately $2.3 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

                                       23
<PAGE>

     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. In October 2002, the Company announced plans to sell
     NCNG to Piedmont  Natural Gas  Company,  Inc.  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.  FPC  established  an accrual to address  indemnities  and
     retained an environmental  liability  associated with the transaction.  FPC
     estimates that its maximum  contractual  liability to AEP Resources,  Inc.,
     associated with Inland Marine Transportation is $60 million. The balance in
     this  accrual  is $9.9  million at June 30,  2003.  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.

     Certain  historical waste sites exist that are being addressed  voluntarily
     by Fuels. The Company cannot determine the total costs that may be incurred
     in connection  with these sites.  The Company cannot predict the outcome of
     this matter.

     Rail Services is voluntarily addressing certain historical waste sites. The
     Company cannot determine the total costs that may be incurred in connection
     with these sites. The Company cannot predict the outcome of this matter.

     PEC,  PEF,  Fuels 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.  The Company  cannot predict the outcome of this
     matter.

     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 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 nationwide 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 PEC and PEF were  asked to provide  information  to the EPA as part of
     this  initiative  and  cooperated in providing  the requested  information.
     During  the  first  quarter  of  2003,  PEC  responded  to  a  supplemental
     information  request from the EPA. PEF has received a similar  supplemental
     information  request,  and responded to it in the second  quarter.  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 the EPA's  initiative or its impact,
     if any, on the Company.

     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
     order to attain  pre-set state NOx emission  levels by May 31, 2004. PEC 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.

                                       24
<PAGE>

     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  PEC 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 in the  preceding
     paragraph. 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. PEC,
     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 PEC 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 formally  proposed
     to rescind  the  Section 126 rule.  This  rulemaking  is expected to become
     final during the summer of 2003. 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.  PEC  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, PEC entered into an agreement
     with the state of North  Carolina  to  transfer  to the  state  any  future
     emissions  allowances  acquired as a result of compliance with the new law.
     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.  PEC  recorded  $33.5  million  in the  second  quarter  of  2003  and
     approximately  $54 million of clean air amortization to date in 2003. Clean
     air expenditures to date are $8.4 million.

     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.

                                       25
<PAGE>

     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. Pursuant to a Court Order, the EPA is 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  financial
     condition and results of  operations.  However,  the Company cannot predict
     the outcome of this matter.

     b) As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each
     entered  into a contract  with the U.S.  Department  of Energy  (DOE) under
     which the DOE agreed to begin  taking  spent  nuclear fuel by no later than
     January 31, 1998.  All similarly  situated  utilities were required to sign
     the same standard contract.

     In April 1995, the DOE issued a final  interpretation  that it did not have
     an unconditional obligation to take spent nuclear fuel by January 31, 1998.
     In Indiana & Michigan Power v. DOE, the Court of Appeals  vacated the DOE's
     final interpretation and ruled that the DOE had an unconditional obligation
     to begin  taking  spent  nuclear  fuel.  The Court did not specify a remedy
     because the DOE was not yet in default.

     After the DOE  failed to comply  with the  decision  in  Indiana & Michigan
     Power v. DOE,  a group of  utilities  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.  The U.S.  Circuit  Court  of  Appeals  (Federal
     Circuit)  has  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.  PEC and PEF are in the process of  evaluating  whether  they
     should each file a similar action for damages.

     On July 9, 2002, Congress passed an override resolution to Nevada's veto of
     DOE's  proposal to locate a permanent  underground  nuclear  waste  storage
     facility  at  Yucca  Mountain,  Nevada.  DOE  plans  to  submit  a  license
     application for the Yucca Mountain facility by the end of 2004. PEC and PEF
     cannot predict the outcome of this matter.

     With certain modifications, and additional approval by the NRC, PEC's spent
     nuclear fuel storage facilities will be sufficient to provide storage space
     for spent fuel  generated on PEC's  system  through the  expiration  of the
     current  operating  licenses  for all of PEC's  nuclear  generating  units.
     Subsequent or prior to the expiration of these licenses,  or any renewal of
     these  licenses,  dry storage or  acquisition  of new shipping casks may be
     necessary.  PEC obtained  approval from the NRC to use  additional  storage
     space at the Harris Plant in December  2000. PEF currently is storing spent
     nuclear  fuel onsite in spent fuel pools.  If PEF does not seek  renewal of
     the Crystal  River  Nuclear Plant (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 PEF extends the CR3  operating
     license, dry storage may be necessary.

     c) Progress Energy, through its subsidiaries,  produces synthetic fuel from
     coal  fines.  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. Any synthetic fuel tax credit amounts
     not utilized are carried  forward  indefinitely.  All of Progress  Energy's
     synthetic fuel facilities have received  private letter rulings (PLRs) from
     the Internal  Revenue  Service (IRS) with respect to their  synthetic  fuel
     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. Additionally, the ability to use tax credits currently being carried
     forward  could be  denied.  Total  Section  29  credits  generated  to date
     (including FPC prior to its  acquisition by the Company) are  approximately
     $1.028  billion,  of which $445.6 million have been used and $582.4 million
     are being carried  forward as of June 30, 2003. The current  Section 29 tax
     credit program expires in 2007.

                                       26
<PAGE>

     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 $273.1 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 the  Company's  majority-owned  synthetic  fuel
     entities,  including Colona, were accepted into the IRS Prefiling 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.

     In late June 2003,  the Company was informed  that IRS field  auditors have
     raised questions  regarding the chemical change  associated with coal-based
     synthetic fuel  manufactured at its Colona facility and the testing process
     by  which  the  chemical  change  is  verified.  (The  questions  arose  in
     connection  with  the  Company's  participation  in the PFA  program.)  The
     chemical  change and the associated  testing process were described as part
     of the PLR request for Colona. Based on that application,  the IRS ruled in
     Colona's  PLR that the  synthetic  fuel  produced  at  Colona  undergoes  a
     significant  chemical  change  and thus  qualifies  for tax  credits  under
     Section 29 of the Internal  Revenue Code.  While the IRS has announced that
     they may revoke PLRs if test procedures and results do not demonstrate that
     a  significant  chemical  change  has  occurred,  based on the  information
     received to date, the Company does not believe the issues warrant  reversal
     by the IRS National Office of its prior position in the Colona PLR.

     The information  provided by the IRS field auditors addresses only Progress
     Energy's Colona facility.  The Company,  however,  applies  essentially the
     same chemical process and uses the same independent laboratories to confirm
     chemical  change in the  synthetic  fuel  manufactured  at each of its four
     other  facilities.  The  independent  laboratories  used by the  Company to
     determine  significant  chemical  change are the  leading  experts in their
     field  and are  used by  many  other  industry  participants.  The  Company
     believes that the  laboratories'  work and the chemical  change process are
     consistent with the bases upon which the PLRs were issued.

     The Company is working to resolve  this matter as quickly as  possible.  At
     this time,  the Company  cannot predict how long the IRS process will take;
     however,  the Company intends to continue  working  cooperatively  with the
     IRS. The Company firmly  believes that it is operating the Colona  facility
     and its other  plants in  compliance  with its PLRs and  Section  29 of the
     Internal  Revenue  Code.  Accordingly,  the Company has no current plans to
     alter its synthetic fuel production schedules as a result of these matters.

     In  addition,  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.
     However,  the IRS has suspended issuance of PLRs relating to synthetic fuel
     production  (typically a closing  condition to the sale of an interest in a
     synthetic fuel entity).  Unless that  suspension on new PLRs is lifted,  it
     will be difficult to  consummate  the  successful  sale of interests in the
     Company's synthetic fuel facilities.  The Company cannot predict when or if
     the IRS will recommence  issuing such PLRs. The final outcome and timing of
     the Company's  efforts to sell  interests in synthetic  fuel  facilities is
     uncertain and while the Company  cannot predict the outcome of this matter,
     the outcome is not expected to have a material  effect on the  consolidated
     financial position, cash flows or results of operations.

     d) In November of 2001,  Strategic  Resource  Solutions Corp. (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  in  the  form  of  a
     cross-complaint   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."

                                       27
<PAGE>

     The Company has reviewed the District's  earlier  pleadings against SRS and
     believes that those claims are not meritorious. SRS filed its answer to the
     new pleadings on April 14, 2003. The Company has reviewed the new pleadings
     and the  Company  believes  that the new  claims are not  meritorious.  The
     Company has filed responsive  pleadings  denying the  allegations,  and the
     discovery  process is  underway.  SRS,  the  Company  and  Progress  Energy
     Solutions,  Inc. 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.

     e) The  Company and its  subsidiaries  are  involved in various  litigation
     matters in the ordinary  course of business,  some of which involve  claims
     for  substantial  amounts.  Where  appropriate,  accruals have been made in
     accordance with SFAS No. 5, "Accounting for  Contingencies," to provide for
     such  matters.  The  Company  believes  the final  disposition  of  pending
     litigation  would  not have a  material  adverse  effect  on the  Company's
     consolidated results of operations or financial position.

                                       28
<PAGE>




                         CAROLINA POWER & LIGHT COMPANY
                      d/b/a PROGRESS ENERGY CAROLINAS, INC.
                    CONSOLIDATED INTERIM FINANCIAL STATEMENTS
                                  June 30, 2003
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CONSOLIDATED STATEMENTS OF INCOME
                                                            Three Months Ended          Six Months Ended
(Unaudited)                                                      June 30,                   June 30,
----------------------------------------------------------------------------------------------------------------

(In thousands)                                             2003           2002           2003          2002
----------------------------------------------------------------------------------------------------------------
Operating Revenues
   Electric                                             $ 816,240      $ 834,658    $ 1,741,710     $ 1,646,139
   Diversified business                                     2,423          3,434          5,819           6,823
----------------------------------------------------------------------------------------------------------------
      Total Operating Revenues                            818,663        838,092      1,747,529       1,652,962
----------------------------------------------------------------------------------------------------------------
Operating Expenses
   Fuel used in electric generation                       177,020        170,977        402,562         342,703
   Purchased power                                         68,977         90,918        142,157         164,228
   Operation and maintenance                              210,295        193,887        400,170         387,324
   Depreciation and amortization                          141,848        133,459        280,644         274,844
   Taxes other than on income                              35,101         36,075         79,277          74,843
   Diversified business                                     1,595          2,754          2,535           5,815
----------------------------------------------------------------------------------------------------------------
        Total Operating Expenses                          634,836        628,070      1,307,345       1,249,757
----------------------------------------------------------------------------------------------------------------
Operating Income                                          183,827        210,022        440,184         403,205
----------------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                          2,075          3,202          3,441           4,868
   Other, net                                              (8,380)         4,652        (10,931)          1,680
----------------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                       (6,305)         7,854         (7,490)          6,548
----------------------------------------------------------------------------------------------------------------
Interest Charges
   Interest charges                                        48,412         56,255         97,715         117,899
   Allowance for borrowed funds used during                  (658)        (2,779)        (1,583)         (5,873)
   construction
----------------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                        47,754         53,476         96,132         112,026
----------------------------------------------------------------------------------------------------------------
Income before Income Taxes                                129,768        164,400        336,562         297,727
Income Tax Expense                                         40,956         33,248        112,688          81,456
----------------------------------------------------------------------------------------------------------------
Net Income                                                 88,812        131,152        223,874         216,271
Preferred Stock Dividend Requirement                          741            741          1,482           1,482
----------------------------------------------------------------------------------------------------------------
Earnings for Common Stock                               $  88,071      $ 130,411    $   222,392     $   214,789
----------------------------------------------------------------------------------------------------------------

See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
</TABLE>

                                       29
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)                                                     June 30,                  December 31,
Assets                                                               2003                        2002
----------------------------------------------------------------------------------------------------------
     Utility Plant
  Utility plant in service                                     $ 13,072,200                  $ 12,675,761
  Accumulated depreciation                                       (6,077,374)                   (6,356,933)
----------------------------------------------------------------------------------------------------------
        Utility plant in service, net                             6,994,826                     6,318,828
  Held for future use                                                 4,942                         7,188
  Construction work in progress                                     334,269                       325,695
  Nuclear fuel, net of amortization                                 168,148                       176,622
----------------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                  7,502,185                     6,828,333
----------------------------------------------------------------------------------------------------------
     Current Assets
  Cash and cash equivalents                                          12,998                        18,284
  Accounts receivable                                               260,691                       301,178
  Unbilled accounts receivable                                      143,870                       151,352
  Receivables from affiliated companies                              32,270                        36,870
  Notes receivable from affiliated companies                              -                        49,772
  Taxes receivable                                                        -                        55,006
  Inventory                                                         348,239                       342,886
  Deferred fuel cost                                                137,301                       146,015
  Prepayments and other current assets                               35,459                        45,542
----------------------------------------------------------------------------------------------------------
        Total Current Assets                                        970,828                     1,146,905
----------------------------------------------------------------------------------------------------------
     Deferred Debits and Other Assets
  Regulatory assets                                                 515,257                       252,083
  Nuclear decommissioning trust funds                               465,043                       423,293
  Diversified business property, net                                 51,771                         9,435
  Miscellaneous other property and investments                      184,029                       209,657
  Other assets and deferred debits                                   98,947                       104,978
----------------------------------------------------------------------------------------------------------
        Total Deferred Debits and Other Assets                    1,315,047                       999,446
----------------------------------------------------------------------------------------------------------
           Total Assets                                        $  9,788,060                  $  8,974,684
----------------------------------------------------------------------------------------------------------

Capitalization and Liabilities
----------------------------------------------------------------------------------------------------------
Capitalization
----------------------------------------------------------------------------------------------------------
  Common stock                                                 $  3,135,690                  $  3,089,115
  Preferred stock - not subject to mandatory redemption              59,334                        59,334
  Long-term debt, net                                             2,516,941                     3,048,466
----------------------------------------------------------------------------------------------------------
        Total Capitalization                                      5,711,965                     6,196,915
----------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                 400,000                             -
  Accounts payable                                                  176,387                       259,217
  Payables to affiliated companies                                  121,081                        98,572
  Notes payable to affiliated companies                              49,359                             -
  Taxes accrued                                                       4,031                             -
  Interest accrued                                                   56,678                        58,791
  Short-term obligations                                            363,900                       437,750
  Current portion of accumulated deferred income taxes               44,197                        66,088
  Other current liabilities                                          92,016                        93,171
----------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                 1,307,649                     1,013,589
----------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                               1,156,722                     1,179,689
  Accumulated deferred investment tax credits                       153,207                       158,308
  Regulatory liabilities                                            131,994                         7,774
  Asset retirement obligations                                      905,338                             -
  Other liabilities and deferred credits                            421,185                       418,409
----------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities              2,768,446                     1,764,180
----------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 9)
----------------------------------------------------------------------------------------------------------
            Total Capitalization and Liabilities               $  9,788,060                  $  8,974,684
----------------------------------------------------------------------------------------------------------

See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
</TABLE>

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

Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS                                                  Six Months Ended
(Unaudited)                                                                                 June 30,
(In thousands)                                                                         2003           2002
-----------------------------------------------------------------------------------------------------------------
     Operating Activities
Net income                                                                           $  223,874      $ 216,271
Adjustments to reconcile net income to net cash provided by operating
activities:
      Depreciation and amortization                                                     324,975        329,437
      Deferred income taxes                                                             (38,115)       (25,358)
      Investment tax credit                                                              (5,100)        (6,240)
      Deferred fuel cost                                                                  8,714         12,757
      Net (increase) decrease in accounts receivable                                     20,169        (13,408)
      Net decrease in affiliated accounts receivable                                     14,743        (38,213)
      Net increase in inventories                                                        (5,353)        (1,229)
      Net (increase) decrease in prepayments and other current assets                     8,315        (14,916)
      Net decrease in accounts payable                                                  (14,632)        (5,109)
      Net increase in affiliated accounts payable                                        17,487         33,340
      Net increase in other current liabilities                                          58,183         93,975
      Other                                                                              50,783         21,921
-----------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                      664,043        603,228
-----------------------------------------------------------------------------------------------------------------
     Investing Activities
Gross property additions                                                               (258,526)      (333,308)
Proceeds from assets transferred to affiliate                                                 -        243,719
Nuclear fuel additions                                                                  (45,642)       (49,380)
Contributions to nuclear decommissioning trust                                          (17,959)       (17,915)
Diversified business property additions                                                    (262)       (10,439)
Investments in non-utility activities                                                    (2,258)        (6,886)
-----------------------------------------------------------------------------------------------------------------
         Net Cash Used in Investing Activities                                         (324,647)      (174,209)
-----------------------------------------------------------------------------------------------------------------
     Financing Activities
Proceeds from issuance of long-term debt                                                      -         46,505
Net decrease in short-term obligations                                                  (73,850)      (207,535)
Net increase (decrease) in intercompany notes                                            99,131        (36,374)
Retirement of long-term debt                                                           (165,208)       (49,754)
Dividends paid to parent                                                               (203,273)      (190,599)
Dividends paid on preferred stock                                                        (1,482)        (1,482)
-----------------------------------------------------------------------------------------------------------------
         Net Cash Used in Financing Activities                                         (344,682)      (439,239)
-----------------------------------------------------------------------------------------------------------------
     Net Decrease in Cash and Cash Equivalents                                           (5,286)       (10,220)
-----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of the Period                                     18,284         21,250
-----------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of the Period                                       $   12,998      $  11,030
-----------------------------------------------------------------------------------------------------------------

Supplemental Disclosures of Cash Flow Information
Cash paid during the year -  interest (net of amount capitalized)                    $   95,287      $ 103,911
                             income taxes (net of refunds)                           $  119,638      $  61,163

Noncash Activities
-    In February 2002, CP&L  transferred  the Rowan plant to Progress  Ventures,
     Inc. and established an intercompany receivable. The property and inventory
     transferred  totaled  approximately  $244  million.  In  April  2002,  CP&L
     received  cash  proceeds  in  settlement  of  the  intercompany  receivable
     totaling  approximately  $244 million.  This amount is reported in proceeds
     from assets transferred to affiliates in the investing activities section.

See Notes to Progress Energy Carolinas, Inc. Consolidated Interim Financial Statements.
</TABLE>


                                       31
<PAGE>

Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS


1.   ORGANIZATION AND BASIS OF PRESENTATION

     A. Organization.

     Progress  Energy  Carolinas,  Inc.  (PEC) is a public  service  corporation
     primarily engaged in the generation, transmission, distribution and sale of
     electricity primarily in portions of North Carolina and South Carolina. PEC
     is a wholly  owned  subsidiary  of Progress  Energy,  Inc.  (the Company or
     Progress  Energy).  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.

     Effective  January 1, 2003,  Carolina  Power & Light  Company  (CP&L) began
     doing business under the assumed name Progress Energy  Carolinas,  Inc. The
     legal  name has not  changed  and  there was no  restructuring  of any kind
     related  to the name  change.  The  current  corporate  and  business  unit
     structure remains unchanged.

     B. Basis of Presentation.

     These financial statements have been prepared in accordance with accounting
     principles  generally  accepted in the United States of America  (GAAP) for
     interim  financial  information and with the  instructions to Form 10-Q and
     Regulation S-X. Accordingly, they do not include all of the information and
     footnotes required by GAAP for complete financial  statements.  Because the
     accompanying  consolidated  interim financial statements do not include all
     of the information  and footnotes  required by GAAP, they should be read in
     conjunction  with the audited  financial  statements  for the period  ended
     December 31, 2002 and notes thereto included in PEC's Form 10-K, as amended
     for the year ended December 31, 2002.

     The amounts included in the consolidated  interim financial  statements are
     unaudited  but,  in the  opinion of  management,  reflect  all  adjustments
     necessary  to fairly  present  PEC's  financial  position  and  results  of
     operations for the interim periods.  Due to seasonal weather variations and
     the  timing  of   outages  of   electric   generating   units,   especially
     nuclear-fueled units, the results of operations for interim periods are not
     necessarily  indicative  of amounts  expected for the entire year or future
     periods.

     In preparing 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  financial  statements  and  amounts of revenues  and  expenses
     reflected  during the reporting  period.  Actual  results could differ from
     those estimates. Certain amounts for 2002 have been reclassified to conform
     to the 2003 presentation,  with no effect on previously reported net income
     or common stock equity.

2.   FINANCIAL INFORMATION BY BUSINESS SEGMENT

     PEC's  operations  consist  primarily of the PEC  Electric  segment with no
     other material segments.

     The financial  information  for the PEC Electric  segment for the three and
     six months ended June 30, 2003 and 2002 is as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in thousands)
                              Three Months Ended June 30,        Six Months Ended June 30,
                              ---------------------------        -------------------------
                                   2003            2002             2003              2002
     --------------------------------------------------------------------------------------------
     Revenues                 $   816,240     $   834,658        $ 1,741,710         $ 1,646,139
     Segment income           $    88,394     $   131,690        $   223,264         $   217,222
     Total segment assets     $ 9,568,769     $ 8,669,993        $ 9,568,769         $ 8,669,993
     ============================================================================================
</TABLE>

     The  primary   differences   between  the  PEC  Electric  segment  and  PEC
     consolidated financial information relate to other non-electric  operations
     and elimination entries.

                                       32
<PAGE>



3.   IMPACT OF NEW ACCOUNTING STANDARDS

     SFAS No. 148, "Accounting for Stock-Based Compensation"
     For  purposes  of the pro  forma  disclosures  required  by SFAS  No.  148,
     "Accounting for  Stock-Based  Compensation - Transition and Disclosure - an
     Amendment  of FASB  Statement  No.  123," the  estimated  fair value of the
     Company's  stock options is amortized to expense over the options'  vesting
     period.  PEC's  information  related  to the pro forma  impact on  earnings
     assuming  stock  options  were  expensed for the three and six months ended
     June 30:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                            Three Months Ended June 30,    Six Months Ended June 30,
     (in thousands)                                            2003           2002            2003         2002
                                                            ------------  -------------    -----------  ------------
     Earnings for common stock, as reported                    $ 88,071      $ 130,411      $ 222,392     $ 214,789
     Deduct:  Total stock option expense determined under
       fair value method for all awards, net of related tax
       effects                                                      706            535          1,779         1,294
                                                            ------------  -------------    -----------  ------------
     Pro forma earnings for common stock                       $ 87,365      $ 129,876      $ 220,613     $ 213,495
                                                            ============  =============    ===========  ============
</TABLE>

     In April 2003, the Financial  Accounting  Standards  Board (FASB)  approved
     certain decisions on its stock-based  compensation project. Some of the key
     decisions reached by the FASB were that stock-based  compensation should be
     recognized  in the  income  statement  as an expense  and that the  expense
     should be measured as of the grant date at fair value. A significant  issue
     yet to be resolved by the FASB is the determination of the appropriate fair
     value measure.  The FASB continues to deliberate  additional issues in this
     project;  however,  the FASB plans to issue an exposure  draft in 2003 that
     could become effective in 2004.

     Derivative Instruments and Hedging Activities
     In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
     Derivative  Instruments and Hedging  Activities."  The statement amends and
     clarifies SFAS No. 133 on accounting for derivative instruments,  including
     certain derivative instruments embedded in other contracts, and for hedging
     activities.  The new guidance  incorporates  decisions  made as part of the
     Derivatives  Implementation  Group  (DIG)  process,  as well  as  decisions
     regarding  implementation  issues raised in relation to the  application of
     the  definition  of a derivative.  SFAS No. 149 is generally  effective for
     contracts  entered into or modified  after June 30, 2003.  PEC is currently
     evaluating what effects, if any, this statement will have on its results of
     operations and financial position.

     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 (e.g., CPI). In particular, that guidance
     discusses  whether the pricing in a contract  that  contains  broad  market
     indices 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).
     In late June 2003,  the FASB issued final  superseding  guidance (DIG Issue
     C20) on this issue,  which is  significantly  different  from the tentative
     superseding  guidance  that was issued in April 2003.  The new  guidance is
     effective   October  1,  2003  for  PEC.  DIG  Issue  C20   specifies   new
     pricing-related  criteria for qualifying as a normal  purchase or sale, and
     it requires a special transition adjustment as of October 1, 2003.

     PEC has  determined  that it has one  existing  "normal"  contract  that is
     affected by this revised guidance.  PEC is in the process of evaluating the
     revised   guidance  and  related   contract  to  determine  the  transition
     adjustment  that will be necessary and to determine if the contract will be
     required to be recorded at fair value subsequent to October 1, 2003.

     SFAS  No.  150,   "Accounting  for  Certain   Financial   Instruments  with
     Characteristics  of Both  Liabilities  and  Equity"
     In May  2003,  the  FASB  issued  SFAS No.  150,  "Accounting  for  Certain
     Financial Instruments with Characteristics of Both Liabilities and Equity."
     SFAS  No.  150  establishes  standards  for how an  issuer  classifies  and
     measures  certain  financial   instruments  with  characteristics  of  both
     liabilities  and equity.  It requires  that an issuer  classify a financial
     instrument  that is within  its scope as a  liability  (or an asset in some
     circumstances).  The financial instruments within the scope of SFAS No. 150
     include  mandatorily  redeemable  stock,   obligations  to  repurchase  the
     issuer's equity shares by transferring  assets, and certain  obligations to
     issue a variable  number of shares.  SFAS No. 150 is effective  immediately
     for such  instruments  entered into or modified  after May 31, 2003, and is
     effective for previously issued financial  instruments  within its scope on
     July 1, 2003.  PEC believes that the adoption of SFAS No. 150 will not have
     a material impact on its financial position or results of operations.

                                       33

<PAGE>

     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 know as special purpose entities or SPEs) and
     determining   whether  such  entities  should  be   consolidated.   Certain
     disclosures  are required 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.  During the first six months of 2003, PEC did not  participate in
     the  creation  of, or  obtain a new  variable  interest  in,  any  variable
     interest entity.  For those variable  interest entities created or obtained
     on or before  January 31, 2003, PEC must apply the provisions of FIN No. 46
     in the third quarter of 2003.

     PEC is currently  evaluating what effects, if any, this interpretation will
     have on its  results of  operations  and  financial  position.  During this
     evaluation process, several arrangements have been identified to which this
     interpretation  may  apply.  These  arrangements   include  investments  in
     approximately 50 Affordable Housing properties  eligible for Section 42 tax
     credits.  PEC  divested   approximately  30  of  these  Affordable  Housing
     investments  in July 2003,  and therefore the  application of FIN No. 46 is
     not  expected  to  have  a  material   impact  with  respect  to  those  30
     investments. It is reasonably possible that the Company will be required to
     consolidate  some of the remaining 20 Affordable  Housing entities that are
     currently  accounted for under the equity method.  The maximum  exposure to
     loss as a result of PEC's total  funding  commitments  for the remaining 20
     Affordable  Housing  investments is approximately  $23.9 million.  However,
     management believes the total loss of its investments is unlikely given the
     nature of the  investments  and the  utilization of certain  Section 42 tax
     credits to date.

     PEC is in the final  stages of  completing  the adoption of FIN No. 46, but
     having considered the facts described  herein,  does not expect the results
     to have a material impact on its consolidated  financial position,  results
     of operation or liquidity.

     EITF Issue No. 03-04, "Accounting for 'Cash Balance' Pension Plans"
     In May  2003,  the  EITF  reached  consensus  in EITF  Issue  No.  03-04 to
     specifically address the accounting for certain cash balance pension plans.
     The consensus reached in EITF Issue No. 03-04 requires certain cash balance
     pension  plans to be  accounted  for as  defined  benefit  plans.  For cash
     balance plans  described in the consensus,  the consensus also requires the
     use of the  traditional  unit credit  method for purposes of measuring  the
     benefit  obligation  and annual cost of  benefits  earned as opposed to the
     projected unit credit method.  PEC has historically  accounted for its cash
     balance plans as defined benefit plans;  however,  PEC is required to adopt
     the  measurement  provisions of EITF 03-04 at its cash balance  plans' next
     measurement  date of December 31, 2003. Any  differences in the measurement
     of the  obligations  as a result of applying the consensus will be reported
     as a component of actuarial gain or loss. PEC is currently  evaluating what
     effects  EITF 03-04 will have on its results of  operations  and  financial
     position.

4.   ASSET RETIREMENT OBLIGATIONS

     SFAS No.  143,  "Accounting  for Asset  Retirement  Obligations,"  provides
     accounting  and   disclosure   requirements   for  retirement   obligations
     associated with long-lived  assets and was adopted by the Company effective
     January  1,  2003.  This  statement  requires  that  the  present  value of
     retirement  costs for  which  PEC 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 were 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.

     Upon adoption of SFAS No. 143, PEC recorded  asset  retirement  obligations
     (AROs) for  nuclear  decommissioning  of  radiated  plant  totaling  $879.7
     million.  PEC  used  an  expected  cash  flow  approach  to  measure  these
     obligations.  This  amount  includes  accruals  recorded  prior to adoption
     totaling  $491.3  million,  which were  previously  recorded in accumulated
     depreciation.  The  related  asset  retirement  costs,  net of  accumulated
     depreciation, recorded upon adoption totaled $117.3 million. The cumulative
     effect of  adoption  of this  statement  had no impact on the net income of
     PEC, as the effects were offset by the  establishment of a regulatory asset
     in the amount of $271.1 million,  pursuant to SFAS No. 71,  "Accounting for
     the  Effects  of  Certain  Types  of  Regulation."   The  regulatory  asset
     represents the cumulative  accretion and accumulated  depreciation  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,  less
     the amount previously recorded.

     Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear
     decommissioning  liability  totaled  $465.0  million  at June 30,  2003 and
     $423.3 million at December 31, 2002.

                                       34
<PAGE>

     Pro forma net income has not been presented for prior years because the pro
     forma  application of SFAS No. 143 to prior years would result in pro forma
     net income not materially different from the actual amounts reported.

     PEC has identified but not recognized AROs related to electric transmission
     and distribution and  telecommunications  assets as the result of easements
     over property not owned by PEC. 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 PEC intends to utilize these properties indefinitely.  In
     the event PEC decides to abandon or cease the use of a particular easement,
     an ARO liability would be recorded at that time.

     PEC has previously  recognized removal costs as a component of depreciation
     in accordance with regulatory  treatment.  As of June 30, 2003, the portion
     of such costs not representing  AROs under SFAS No. 143 was $882.6 million.
     This amount is included in  accumulated  depreciation  on the  accompanying
     Consolidated  Balance Sheets.  PEC has collected  amounts for  non-radiated
     areas at  nuclear  facilities,  which  do not  represent  asset  retirement
     obligations. These amounts totaled $63.5 million as of June 30, 2003, which
     is included in accumulated  depreciation on the  accompanying  Consolidated
     Balance Sheets.

     PEC filed a request  with the NCUC  requesting  deferral of the  difference
     between  expense  pursuant  to SFAS  No.  143  and  expense  as  previously
     determined  by the NCUC.  The NCUC  granted the  deferral of the January 1,
     2003 cumulative adjustment.  Because the clean air legislation discussed in
     Note 9 under "Air Quality"  contained a prohibition  against cost deferrals
     unless  certain  criteria  are met,  the NCUC  denied the  deferral  of the
     ongoing  effects.  The Company has provided  additional  information to the
     NCUC that it believes will demonstrate that deferral of the ongoing effects
     should also be allowed. Since the NCUC order denied deferral of the ongoing
     effects,  PEC ceased  deferral  of the  ongoing  effects  during the second
     quarter  for the six  months  ended  June 30,  2003  related  to its  North
     Carolina retail  jurisdiction.  Pre-tax income for the three and six months
     ended  June 30,  2003  increased  by  approximately  $13.6  million,  which
     represents a decrease in non-ARO cost of removal expense,  partially offset
     by an increase in decommissioning expense.

     On April 8, 2003, the Public Service  Commission of South Carolina  (SCPSC)
     approved a joint  request by PEC, Duke Energy and South  Carolina  Electric
     and Gas Company for an  accounting  order to authorize  the deferral of all
     cumulative and prospective effects related to the adoption of SFAS No. 143.

5.   COMPREHENSIVE INCOME

     Comprehensive  income for the three and six months  ended June 30, 2003 was
     $88.0 million and $223.2 million,  respectively.  Comprehensive  income for
     the three and six months ended June 30, 2002 was $129.6  million and $218.2
     million, respectively.  Items of other comprehensive income for the periods
     consisted  primarily of changes in fair value of derivatives  used to hedge
     cash flows related to interest on long-term debt.

6.   FINANCING ACTIVITIES

     On April 1, 2003,  PEC  reduced  the size of its  existing  364-day  credit
     facility  from  $285  million  to $165  million.  The  other  terms of this
     facility were not changed.  On July 30, 2003,  PEC renewed its $165 million
     364-day credit  agreement.  PEC's $285 million  three-year credit agreement
     entered into in July 2002 remains in place,  for total  facilities  of $450
     million.

     On May 27, 2003,  PEC redeemed $150 million of First Mortgage  Bonds,  7.5%
     Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
     PEC funded the redemption with commercial paper.

     On July 14, 2003,  PEC  announced  the  redemption of $100 million of First
     Mortgage Bonds,  6.875% Series Due August 15, 2023 at 102.84%.  The date of
     the redemption  will be August 15, 2003. PEC will fund the redemption  with
     commercial paper.

7.   RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS

     PEC uses  interest  rate  derivative  instruments  to adjust  the fixed and
     variable rate debt  components of its debt  portfolio and to hedge interest
     rates with regard to future fixed rate debt issuances.  In March, April and
     June of 2003, PEC entered into treasury rate locks to hedge its exposure to

                                       35
<PAGE>

     interest rates with regard to a future issuance of debt.  These  agreements
     have a  computational  period of ten years and are  designated as cash flow
     hedges for  accounting  purposes.  These  agreements  have a total notional
     amount of $60 million.

     The notional  amounts of the above  contracts  are not exchanged and do not
     represent  exposure  to credit  loss.  In the event of default by a counter
     party,  the risk in the transaction is the cost of replacing the agreements
     at current market rates. PEC only enters into interest rate swap agreements
     with banks with credit ratings of single A or better.

8.   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 three and six months ended June
     30, 2003 and 2002 are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                            Three Months Ended June 30,         Six Months Ended June 30,
     (in thousands)                                           2003              2002              2003              2002
                                                          --------------    --------------    -------------     -------------
     Other income
     Net financial trading gain (loss)                        $   1,175         $     792        $  (1,524)         $ (1,429)
     Net energy brokered for resale                                 (68)              (89)             270              (446)
     Nonregulated energy and delivery services income             2,052             3,016            4,338             5,567
     AFUDC equity                                                   774             1,602            1,864             3,662
     Investment gains                                                 -             2,960                -             2,960
     Other                                                        2,767             4,711            5,523             5,981
                                                          --------------    --------------    -------------     -------------
         Total other income                                   $   6,700         $  12,992        $  10,471          $ 16,295
                                                          --------------    --------------    -------------     -------------

      Other expense
     Nonregulated energy and delivery services expenses       $   2,022         $   3,632        $   3,995          $  5,267
     Donations                                                    1,339             1,178            2,645             2,548
     Investment losses                                            8,643                 -            8,643                 -
     Other                                                        3,076             3,530            6,119             6,800
                                                          --------------    --------------    -------------     -------------
        Total other expense                                   $  15,080         $   8,340        $  21,402          $ 14,615
                                                          --------------    --------------    -------------     -------------

     Other, net                                               $ (8,380)         $   4,652        $ (10,931)         $  1,680
                                                          ==============    ==============    =============     =============
</TABLE>

     Net financial trading gains and losses represent non-asset-backed trades of
     electricity and gas. Net energy brokered for resale represents  electricity
     purchased  externally  for sale to a third party.  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. Investment
     losses represent losses on limited partnership investment funds.

9.   COMMITMENTS AND CONTINGENCIES

     Contingencies  existing as of the date of these  statements  are  described
     below.  No significant  changes have occurred since December 31, 2002, with
     respect to the commitments discussed in Note 18 of the financial statements
     included in PEC's 2002 Annual Report on Form 10-K, as amended.

     In 2003, PEC determined that its external funding levels did not fully meet
     the nuclear decommissioning financial assurance levels required by the NRC.
     Therefore,  PEC obtained parent company  guarantees of $276 million to meet
     the  required  levels.  As of June 30,  2003,  management  does not believe
     conditions are likely for  performance  under the  agreements  discussed in
     this Note 9.

     Insurance

     PEC is insured against public liability for a nuclear  incident.  Under the
     current  provisions of the Price Anderson Act,  which limits  liability for
     accidents  at nuclear  plants,  PEC, as an owner of nuclear  units,  can be
     assessed 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 for each reactor owned per
     occurrence.  Effective August 20, 2003, the retroactive premium assessments
     will  increase to $100.6  million per  reactor  from the current  amount of
     $88.1 million.  The total limit available to cover nuclear liability losses
     will  increase  as well from $9.6  billion  to $10.6  billion.  The  annual
     retroactive premium limit of $10 million per reactor owned will not change.

                                       36
<PAGE>

     Contingencies

     Claims and uncertainties

     a) PEC 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 MGP site depends  largely upon the state in which the site
     is located.  There are several MGP sites to which PEC has some  connection.
     In  this  regard,  PEC  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
     EPA and the North Carolina Department of Environment and Natural Resources,
     Division  of Waste  Management  (DWM).  In  addition,  PEC 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 or  groups  of sites
     associated  with PEC that  have  required  or are  anticipated  to  require
     investigation  and/or remediation costs. PEC received insurance proceeds to
     address costs associated with PEC environmental  liabilities related to its
     involvement with some MGP sites. All eligible expenses related to these are
     charged against a specific fund containing  these proceeds.  As of June 30,
     2003,  approximately  $5.2 million remains in this  centralized fund with a
     related  accrual of $5.2 million  recorded for the  associated  expenses of
     environmental  issues.  As  PEC's  share  of costs  for  investigating  and
     remediating  these sites become known, the fund is assessed to determine if
     additional  accruals  will be  required.  PEC 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.  PEC
     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,  PEC will accrue
     costs for the sites to the extent its  liability  is probable and the costs
     can be  reasonably  estimated.  Presently,  PEC cannot  determine the total
     costs that may be incurred in connection with the remediation of all sites.

     PEC 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.

     PEC is also  currently  in the  process of  assessing  potential  costs and
     exposures at other  environmentally  impaired sites. As the assessments are
     developed and  analyzed,  PEC 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 PEC'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, PEC 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.
     PEC was asked to provide  information to the EPA as part of this initiative
     and  cooperated in providing the  requested  information.  During the first
     quarter of 2003, PEC responded to a supplemental  information  request from
     the  EPA.  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

                                       37
<PAGE>

     $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.  PEC cannot predict the outcome of the EPA's initiative
     or its impact, if any, on the Company.

     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.  PEC 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 PEC's  results  of  operations.  Further
     controls  are  anticipated  as  electricity  demand  increases.  PEC 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  PEC 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 in the  preceding
     paragraph. However, further technical analysis and rulemaking may result in
     a requirement for additional controls at some units. PEC 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. PEC,
     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 PEC 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 formally  proposed to
     rescind the Section 126 rule.  This  rulemaking is expected to become final
     during the summer of 2003. PEC 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.  PEC expects its capital costs
     to meet these emission targets will be approximately  $813 million by 2013.
     PEC 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, PEC entered  into an  agreement  with the state of
     North  Carolina to transfer  to the state any future  emissions  allowances
     acquired  as a result  of  compliance  with  the new law.  The new law also
     requires  the state to  undertake  a study of mercury  and  carbon  dioxide
     emissions  in North  Carolina.  PEC cannot  predict  the future  regulatory
     interpretation,  implementation  or  impact of this new law.  PEC  recorded
     $33.5 million in the second quarter of 2003 and  approximately  $54 million
     of clean air  amortization to date in 2003.  Clean air expenditures to date
     are $8.4 million.

                                       38
<PAGE>

     Other Environmental Matters

     a) 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 PEC's financials and
     operations  if associated  costs cannot be recovered  from  customers.  PEC
     favors the voluntary  program approach  recommended by the  administration,
     and is evaluating options for the reduction,  avoidance,  and sequestration
     of  greenhouse  gases.  However,  PEC 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.  Pursuant to a Court  Order,  the EPA is  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 PEC's financial  condition
     and results of operations.  However, PEC cannot predict the outcome of this
     matter.

     b) As required under the Nuclear Waste Policy Act of 1982, PEC entered into
     a contract  with the DOE under which the DOE agreed to begin  taking  spent
     nuclear  fuel by no later than  January 31, 1998.  All  similarly  situated
     utilities were required to sign the same standard contract.

     In April 1995, the DOE issued a final  interpretation  that it did not have
     an unconditional obligation to take spent nuclear fuel by January 31, 1998.
     In Indiana & Michigan Power v. DOE, the Court of Appeals  vacated the DOE's
     final interpretation and ruled that the DOE had an unconditional obligation
     to begin  taking  spent  nuclear  fuel.  The Court did not specify a remedy
     because the DOE was not yet in default.

     After the DOE  failed to comply  with the  decision  in  Indiana & Michigan
     Power v. DOE,  a group of  utilities  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 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.  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.
     PEC is in the process of evaluating whether it should file a similar action
     for damages.

     On July 9, 2002, Congress passed an override resolution to Nevada's veto of
     DOE's  proposal to locate a permanent  underground  nuclear  waste  storage
     facility  at  Yucca  Mountain,  Nevada.  DOE  plans  to  submit  a  license
     application for the Yucca Mountain  facility by the end of 2004. PEC cannot
     predict the outcome of this matter.

     With certain  modifications and additional approval by the NRC, PEC'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 or prior to the expiration of these licenses,  or any renewal of
     these  licenses,  dry storage or  acquisition  of new shipping casks may be
     necessary. PEC obtained NRC approval to use additional storage space at the
     Harris Plant in December 2000.

                                       39
<PAGE>

     c) PEC is involved in various  litigation matters in the ordinary course of
     business,  some of which  involve  claims for  substantial  amounts.  Where
     appropriate,  accruals  have  been  made in  accordance  with  SFAS No.  5,
     "Accounting for  Contingencies," to provide for such matters.  PEC believes
     the final  disposition  of  pending  litigation  would not have a  material
     adverse  effect on PEC's  consolidated  results of  operations or financial
     position.

                                       40
<PAGE>

Item 2. 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
"SAFE HARBOR FOR  FORWARD-LOOKING  STATEMENTS"  for a discussion  of the factors
that may impact any such forward-looking statements made herein.

Amounts  reported  in the  interim  Consolidated  Statements  of Income  are not
necessarily  indicative of amounts expected for the respective  annual or future
periods  due to  the  effects  of  seasonal  temperature  variations  on  energy
consumption and the timing of maintenance on electric  generating  units,  among
other factors.

This discussion  should be read in conjunction with the  accompanying  financial
statements  found elsewhere in this report and in conjunction with the 2002 Form
10-K.

RESULTS OF OPERATIONS

In this section,  earnings and the factors affecting  earnings for the three and
six  months  ended June 30,  2003 as  compared  to the same  periods in 2002 are
discussed.  The  discussion  begins  with a general  overview,  then  separately
discusses earnings by business segment.

OVERVIEW

The net income and basic earnings per share of Progress Energy,  Inc.  (Progress
Energy or the Company) were $152.8 million or $0.65 per share and $120.6 million
or $0.56 per share for the second  quarter of 2003 and 2002,  respectively.  The
Company's net income and basic  earnings per share were $361.0  million or $1.54
per share and  $253.1  million or $1.18 per share for the first half of 2003 and
2002, respectively.

The  increase in net income for the second  quarter of 2003,  as compared to the
second  quarter of 2002,  is primarily  due to customer  growth and usage at the
utilities,  increased  sales of natural gas, a decrease in interest  expense and
the impact of levelizing the estimated  effective tax rate  throughout the year.
These items were partially  offset by the impact of unfavorable  weather,  PEF's
retail  revenue  sharing  and higher  costs  associated  with a planned  nuclear
outage.  The Company's  operating segments impacted earnings for the quarter and
first half of the year as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

---------------------------------------------------------------------------------------------------------
(in millions)                                Three Months Ended June 30,     Six Months Ended June 30,
---------------------------------------------------------------------------------------------------------
Business Segment                                    2003              2002          2003            2002
-------------------------------------------------------------------------------------------------------
PEC Electric                                     $  88.4          $ 131.7       $ 223.3        $ 217.2
PEF                                                 61.4             76.8         132.1          134.5
Fuels                                               53.8             46.7          80.4           88.3
CCO                                                  2.4              6.7          10.9            4.6
Rail                                                 2.2              2.9          (1.2)           2.2
Other                                                1.2             (8.4)          1.9          (13.2)
Corporate                                          (59.1)          (134.5)       (100.2)        (187.6)
                                           ------------------------------------------------------------
    Total income from continuing operations        150.3            121.9         347.2          246.0
NCNG discontinued operations                         2.5             (1.3)         13.8            7.1
                                           ------------------------------------------------------------
    Net income                                   $ 152.8          $ 120.6       $ 361.0        $ 253.1
-------------------------------------------------------------------------------------------------------
</TABLE>

A detailed  discussion of each of the Company's  significant  operating segments
follows.  The  Company's   significant  operating  segments  and  their  primary
operations are:

o    PEC Electric - engaged in the generation,  transmission,  distribution  and
     sale of  electricity  in  portions  of North  Carolina  and South  Carolina
     (differences  between the PEC  Electric  segment  and the PEC  consolidated
     financial   information  relate  to  other   non-electric   operations  and
     elimination entries);
o    PEF - engaged in the  generation,  transmission,  distribution  and sale of
     electricity in portions of Florida;
o    Fuels - engaged in natural gas drilling and production, coal mining and the
     production of synthetic fuels;
o    Competitive   Commercial   Operations   (CCO)  -  engaged  in  nonregulated
     generation operations and limited trading activities;
o    Progress Rail Services (Rail) - engaged in various rail and railcar related
     services; and
o    Other  Businesses  (Other) - engaged in other  nonregulated  business areas
     including telecommunications and energy services operations.

                                       41
<PAGE>

     In prior years'  reporting,  CCO and Fuels were  components of the Progress
     Ventures segment.  With the expansion of the nonregulated energy generation
     facilities  and the  current  management  structure,  CCO is now a distinct
     operating segment.  In addition to the operating segments listed above, the
     Company  has  other  corporate  activities  that  include  holding  company
     operations,  service company  operations and eliminations.  These corporate
     activities   have  been   included  in  the  Other  segment  in  the  past.
     Additionally,  earnings from  wholesale  customers on the regulated  plants
     have previously been reported in both the regulated  utilities' results and
     the results of Progress  Ventures.  With the  realignment of the reportable
     business  segments,   this  activity  is  now  included  in  the  regulated
     utilities'  results only. For comparative  purposes,  the 2002 results have
     been restated to align with the new business segments.

     In 2002, the operations of 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.  A discussion of the planned  divestiture  of NCNG is provided in
     the Discontinued Operations section that follows.

     In March of 2003,  the SEC  completed an audit of Progress  Energy  Service
     Company,  LLC (Service Company) and recommended that the Company change its
     cost allocation  methodology for allocating  Service Company costs. As part
     of the  audit  process,  the  Company  was  required  to  change  the  cost
     allocation  methodology  for  2003  and  record  retroactive  reallocations
     between  its  affiliates  in the  first  quarter  of 2003  for  allocations
     originally made in 2001 and 2002. This change in allocation methodology and
     the related retroactive  adjustments have no impact on consolidated expense
     or  earnings.  The impact on the  affiliates  is  included  in the  segment
     discussion that follows. The new allocation methodology, as compared to the
     previous  allocation  methodology,  generally  decreases  expenses  in  the
     regulated utilities and increases expenses in the nonregulated  businesses.
     The regulated utilities' reallocations are within operation and maintenance
     expense,  while the  diversified  businesses'  reallocations  are generally
     within diversified business expenses.

     In  accordance  with an SEC order  under  PUHCA,  effective  in the  second
     quarter of 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.  The allocation has no impact on
     the Company's  consolidated  tax expense or net income.  The impacts on the
     business  segments  are  included in the  discussions  below and  generally
     decrease  the  income  tax  expense  for  the  regulated  utilities,  while
     increasing  income tax expense for the holding company.  The second quarter
     2002 reallocation  included impacts from 2001 and the first two quarters of
     2002, while the second quarter 2003 reallocation was for one quarter only.

     REGULATED ELECTRIC SEGMENTS

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

     Effective   January  1,  2003,  the  Company   implemented  SFAS  No.  143,
     "Accounting  for Asset  Retirement  Obligations,"  which  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.  Both electric utilities  recorded asset retirement  obligations
     (AROs) in the first quarter of 2003. At June 30, 2003, PEC Electric's  AROs
     totaled $905.3 million and PEF's AROs totaled $310.9 million.

     PEC filed a request  with the NCUC  requesting  deferral of the  difference
     between  expense  pursuant  to SFAS  No.  143  and  expense  as  previously
     determined  by the NCUC.  The NCUC  granted the  deferral of the January 1,
     2003, cumulative  adjustment.  Because the clean air legislation enacted in
     North  Carolina  contained a  prohibition  against  cost  deferrals  unless
     certain  criteria  are met,  the NCUC  denied the  deferral  of the ongoing
     effects.  The Company has provided additional  information to the NCUC that
     it believes will  demonstrate  that deferral of the ongoing  effects should
     also be  allowed.  Since the NCUC  order  denied  deferral  of the  ongoing
     effects,  PEC ceased  deferral  of the  ongoing  effects  during the second
     quarter of 2003 for the six months ended June 30, 2003 related to its North
     Carolina retail jurisdiction. Pre-tax income for the second quarter of 2003
     increased by  approximately  $13.6 million,  which represents a decrease in
     non-ARO  cost of  removal  expense,  partially  offset  by an  increase  in
     decommissioning  expense. This earnings impact will be reversed if and when
     the NCUC issues an order granting deferral of the ongoing effects.

                                       42
<PAGE>

     On April 8, 2003, the SCPSC approved a joint request by PEC Electric,  Duke
     Energy and South Carolina  Electric and Gas Company for an accounting order
     to authorize the deferral of all cumulative and prospective effects related
     to the adoption of SFAS No. 143.

     On January 23, 2003, the Staff of the FPSC issued a notice of proposed rule
     development to adopt provisions relating to accounting for asset retirement
     obligations  under SFAS No. 143.  Accompanying  the notice was a draft rule
     presented  by the staff which adopts the  provisions  of SFAS No. 143 along
     with the requirement to record the difference between amounts prescribed by
     the FPSC and those used in the  application  of SFAS No. 143 as  regulatory
     assets or  regulatory  liabilities,  which  was  accepted  by all  parties.
     Therefore, the adoption of the statement had no impact on the income of PEF
     due to the establishment of a regulatory liability pursuant to SFAS No. 71,
     "Accounting for the Effects of Certain Types of Regulation." The Commission
     approved the draft rule in June 2003,  and a final order is expected in the
     third quarter of 2003.

     PROGRESS ENERGY CAROLINAS ELECTRIC

     PEC Electric  contributed net income of $88.4 million and $131.7 million in
     the second quarter of 2003 and 2002,  respectively,  and $223.3 million and
     $217.2  million  for the  first  half of 2003 and 2002,  respectively.  The
     decrease in the second  quarter of 2003  compared to the second  quarter of
     2002 is primarily due to unfavorable weather conditions  resulting in lower
     usage  across  all  customer  classes,   the  effect  of  the  tax  benefit
     reallocation  and higher planned nuclear outage costs,  partially offset by
     favorable  retail customer growth and usage. The increase in the first half
     of 2003  compared  to the first  half of 2002 was  primarily  due to strong
     wholesale sales, retail growth and usage and lower interest charges, offset
     partially by the effect of the tax benefit  reallocation,  higher operation
     and maintenance costs related to planned nuclear outages and costs incurred
     for the February 2003 ice storm.

     PEC's  electric  revenues for the second quarter and first half of 2003 are
     as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------------------------
     (in millions of $)              Three Months Ended June 30,                     Six Months Ended June 30,
     ------------------------------------------------------------------------------------------------------------------
     Customer Class                 2003      Change     % Change    2002       2003     Change    % Change    2002
     ------------------------------------------------------------------------------------------------------------------
     Residential                    $ 247.7   $ (10.8)    (4.2)      $ 258.5  $   604.7    $ 37.0       6.5  $   567.7
     Commercial                       198.8      (0.1)    (0.1)        198.9      399.7      13.6       3.5      386.1
     Industrial                       155.9      (4.3)    (2.7)        160.2      302.6     (3.3)      (1.1)     305.9
     Governmental                      17.8      (0.1)    (0.6)         17.9       36.4       0.9       2.5       35.5
                                 ----------------------            -------------------------------           ----------
         Total retail revenues        620.2     (15.3)    (2.4)        635.5    1,343.4      48.2       3.7    1,295.2
     Wholesale                        154.2      (2.5)    (1.6)        156.7      363.6      64.3      21.5      299.3
     Unbilled                          23.5      (0.6)      -           24.1      (7.5)    (21.9)         -       14.4
     Miscellaneous                     18.3      (0.1)    (0.5)         18.4       42.2       5.0      13.4       37.2
                                 ----------------------            -------------------------------           ----------
         Total electric revenues    $ 816.2   $ (18.5)    (2.2)      $ 834.7  $ 1,741.7    $ 95.6       5.8  $ 1,646.1
     ------------------------------------------------------------------------------------------------------------------
</TABLE>

     PEC's electric energy sales for 2003 and 2002 and the amount and percentage
     change by quarter and by customer class are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------------------------
     (in thousands of mWh)                Three Months Ended June 30,                     Six Months Ended June 30,
     ------------------------------------------------------------------------------------------------------------------
     Customer Class                 2003      Change     % Change    2002       2003     Change    % Change    2002
     ------------------------------------------------------------------------------------------------------------------
     Residential                      3,052      (210)    (6.4)        3,262      7,639       392        5.4     7,247
     Commercial                       2,946       (81)    (2.7)        3,027      5,930       112        1.9     5,818
     Industrial                       3,197      (164)    (4.9)        3,361      6,202      (145)      (2.3)    6,347
     Governmental                       317       (21)    (6.2)          338        660        (3)      (0.5)      663
                                 ----------------------            -------------------------------           ----------
         Total   retail   energy      9,512      (476)    (4.8)        9,988     20,431       356        1.8    20,075
     sales
     Wholesale                        3,301      (194)    (5.6)        3,495      7,920     1,094       16.0     6,826
     Unbilled                           396       (35)      -            431        (84)     (329)         -       245
                                 ----------------------            -------------------------------           ----------
         Total mWh sales             13,209      (705)    (5.1)       13,914     28,267     1,121        4.1    27,146
     ------------------------------------------------------------------------------------------------------------------
</TABLE>

     Second Quarter of 2003 Compared to Second Quarter of 2002

     Unfavorable weather accounted for a revenue decline of $34.1 million,  with
     the average  cooling  degree days  declining 37% when  comparing the second
     quarter of 2003 to the second quarter of 2002.  Retail  customer growth and
     usage,  excluding  the impact of weather,  accounted  for $18.1  million of
     additional  revenue in the second quarter of 2003 as compared to the second
     quarter of 2002, with 22,364  additional retail customers during the second
     quarter of 2003 as compared to 2002.

                                       43
<PAGE>

     Operation and maintenance  costs were $210.3 million for the second quarter
     of 2003, which  represents a $16.4 million increase  compared to the second
     quarter of 2002. A planned  nuclear  outage at the Harris plant during 2003
     accounted for $15.1 million of this increase.

     Depreciation  and  amortization  expense was $141.8  million for the second
     quarter of 2003, which represents an $8.3 million increase  compared to the
     second  quarter of 2002.  This increase in  depreciation  and  amortization
     expense  results  from  $33.5  million in clean air  amortization  expensed
     during the second  quarter of 2003 and a $7.0 million  increase  related to
     additional  plant in service.  These  increases are  partially  offset by a
     $16.7 million reduction in accelerated  nuclear  amortization and the $13.6
     million decrease in depreciation  expense related to the ongoing effects of
     SFAS No.  143 in the North  Carolina  retail  jurisdiction,  as  previously
     discussed under  "REGULATED  ELECTRIC  SEGMENTS." The clean air legislation
     allows flexibility in the recognition of the clean air amortization, with a
     maximum of $174 million per year. The Company  currently  plans to amortize
     approximately  $100  million  of clean  air  costs in 2003.  An NCUC  order
     allowed the reduction in the accelerated nuclear  amortization and extended
     the recovery time.

     Other income and expense was $6.9 million of expense for the second quarter
     of 2003  compared to $8.6  million of income  during the second  quarter of
     2002. The primary driver of the  unfavorability  was $9.4 million of losses
     on limited partnership  investment funds recorded during the second quarter
     of 2003.

     Interest  expense was $47.7 million for the second  quarter of 2003,  which
     represents  a $5.8  million  decrease  compared to the same period in 2002.
     This decrease was due to both a decrease in average  outstanding debt and a
     slightly lower interest rate.

     Income tax  expense  was $40.0  million  for the second  quarter of 2003 as
     compared to $32.7 million for the second quarter of 2002.  This variance is
     due to a $22.8 million lower tax benefit reallocation in the second quarter
     of 2003  compared to the same period in 2002,  partially  offset by the tax
     impact of changes in pre-tax income.

     First Half of 2003 Compared to First Half of 2002

     Favorable wholesale revenues are the primary driver of the revenue increase
     for  the  first  half  of 2003  compared  to  2002.  This  favorability  is
     attributable to weather-related  sales of energy to the Northeastern United
     States  markets  during the first half of 2003.  For its retail  customers,
     mild weather in North and South Carolina  during the second quarter of 2003
     more than offset the favorable  impact of cold weather  experienced  in the
     first quarter of 2003.  Retail  customer  growth has  increased  during the
     first half of 2003 when compared to 2002,  with  residential and commercial
     customer growth of two percent.

     Operation  and  maintenance  costs  increased  $12.9  million  compared  to
     operation  and  maintenance  costs of $387.3  million for the first half of
     2002, primarily due to $10.4 million of storm costs in the first quarter of
     2003 and $16.7 million of costs associated with a planned nuclear outage in
     the second quarter of 2003. These costs were partially offset by a decrease
     in  operation  and  maintenance  expense  of $15.9  million  related to the
     previously discussed reallocation of prior years' Service Company costs, as
     required by the SEC.

     Depreciation  and amortization  expense  increased $5.8 million compared to
     depreciation and amortization  expense of $278.4 million for the first half
     of 2002. This increase results from $53.5 million of clean air amortization
     in 2003 and $10.4 million of depreciation on additional  assets placed into
     service.  These increases are partially offset by a $41.6 million reduction
     in  accelerated  nuclear  amortization  and the $13.6  million  decrease in
     depreciation  related to the  ongoing  effects of SFAS No. 143 in the North
     Carolina retail jurisdiction, all of which are discussed previously.

     Other  income and expense was $7.5 million of expense for the first half of
     2003 compared to $6.9 million of income during the first half of 2002.  The
     primary driver of the  unfavorability was $9.4 million of losses on limited
     partnership investment funds recorded during the second quarter of 2003.

     Interest  expense  was  $96.1  million  for the first  half of 2003,  which
     represents  a decrease of $15.9  million.  This  decrease was due to both a
     decrease in average outstanding debt and a slightly lower interest rate.

     Income  tax  expense  was  $110.1  million  for the  first  half of 2003 as
     compared to $80.0 million for the first half of 2002.  This variance is due
     to the tax impact of changes in pre-tax  income and a $17.3  million  lower
     tax  benefit  reallocation  in the first half of 2003  compared to the same
     period in 2002.

                                       44
<PAGE>

     PROGRESS ENERGY FLORIDA

     PEF  contributed  earnings  for  common  stock of $61.4  million  and $76.8
     million in the second  quarter of 2003 and 2002,  respectively,  and $132.1
     million   and  $134.5   million  in  the  first  half  of  2003  and  2002,
     respectively.  These  decreases are primarily  attributed to impacts of the
     2002 rate case and are partially offset by favorable retail customer growth
     and  usage  and the  impact  of the tax  benefit  reallocation,  previously
     discussed.

     In March  2002,  PEF  settled a rate case  which  provided  for a  one-time
     retroactive rate refund,  decreased future retail rates by 9.25% (effective
     May 1, 2002),  provided for lower  depreciation and amortization,  provided
     for  increases in certain  service  revenue  rates and provided for revenue
     sharing with the retail  customers if certain revenue  thresholds were met.
     The impacts of the settlement agreement are included below.

     PEF's  electric  revenues for the second quarter and first half of 2003 and
     2002 and the amount and percentage  change by quarter and by customer class
     are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------------------------
     (in millions of $)                  Three Months Ended June 30,                     Six Months Ended June 30,
     ------------------------------------------------------------------------------------------------------------------
     Customer Class                 2003      Change     % Change    2002       2003     Change    % Change    2002
     ------------------------------------------------------------------------------------------------------------------
     Residential                    $ 413.5     $ 17.9     4.5       $ 395.6  $   798.5    $ 23.7       3.1  $   774.8
     Commercial                       192.1        8.7     4.7         183.4      342.5      (7.7)     (2.2)     350.2
     Industrial                        56.1        1.0     1.8          55.1      103.5      (1.6)     (1.5)     105.1
     Governmental                      45.8        2.3     5.3          43.5       83.8       0.3       0.4       83.5
     Retroactive rate refund              -          -      -              -          -      35.0     100.0      (35.0)
     Revenue sharing/rate
      refund                          (28.1)     (28.1)     -              -      (28.1)    (28.1)        -         -
                                 ----------------------            -------------------------------           ----------
         Total retail revenues        679.4        1.8     0.3         677.6    1,300.2      21.6       1.7    1,278.6
     Wholesale                         49.8       (6.0)  (10.8)         55.8      121.1      12.8      11.8      108.3
     Unbilled                           7.3        1.9      -            5.4        6.6      (5.2)        -       11.8
     Miscellaneous                     30.0        2.9    10.7          27.1       67.1      13.4      25.0       53.7
                                 ----------------------            -------------------------------           ----------
         Total electric revenues    $ 766.5     $  0.6     0.1       $ 765.9  $ 1,495.0    $ 42.6       2.9  $ 1,452.4
     ------------------------------------------------------------------------------------------------------------------
</TABLE>

     PEF's  electric  energy sales for the second quarter and first half of 2003
     and 2002 and the amount and  percentage  change by quarter  and by customer
     class are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ------------------------------------------------------------------------------------------------------------------
     (in thousands of mWh)                Three Months Ended June 30,                     Six Months Ended June 30,
     ------------------------------------------------------------------------------------------------------------------
     Customer Class                 2003      Change     % Change    2002       2003     Change    % Change    2002
     ------------------------------------------------------------------------------------------------------------------
     Residential                      4,703        188     4.2         4,515      9,256       681        7.9     8,575
     Commercial                       2,951         94     3.3         2,857      5,393        80        1.5     5,313
     Industrial                       1,008         14     1.4           994      1,924        48        2.6     1,876
     Governmental                       726         11     1.5           715      1,383        48        3.6     1,335
                                 ----------------------            -------------------------------           ----------
         Total retail energy sales    9,388        307     3.4         9,081     17,956       857        5.0    17,099
     sales
     Wholesale                          890        (86)   (8.8)          976      2,166       210       10.7     1,956
     Unbilled                           498         55      -            443        553        79          -       474
                                 ----------------------            -------------------------------           ----------
         Total mWh sales             10,776        276     2.6        10,500     20,675     1,146        5.9    19,529
     ------------------------------------------------------------------------------------------------------------------
</TABLE>

     Second Quarter of 2003 Compared to Second Quarter of 2002

     Retail  revenues,  excluding  fuel  revenues  of $286.3  million and $259.8
     million for the second quarter of 2003 and 2002, respectively, decreased as
     a result of the  impact  of the final  resolution  of the  revenue  sharing
     provisions in the 2002 rate settlement  agreement.  Fuel revenues increased
     compared to the prior year primarily due to increased  generation.  On July
     9, 2003, the FPSC issued an order that required PEF to refund an additional
     $18.4 million  related to 2002 revenue  sharing.  In the second  quarter of
     2003,  PEF also recorded an additional  accrual of $9.5 million  related to
     estimated 2003 revenue sharing. This accrual will be reviewed and adjusted,
     if necessary,  on a quarterly  basis.  Revenues were further reduced due to
     the impact of the 9.25% rate  reduction  that went into effect in May 2002,
     as part of the settlement agreement.

                                       45
<PAGE>

     These  decreases were  partially  offset by additional  retail  revenues of
     $11.4 million related to customer growth and usage.

     Operation and  maintenance  costs  increased $0.6 million,  compared to the
     $153.3  million  incurred  during the second quarter of 2002. A decrease in
     the  pension  credit  of  $5.4  million,   due  to  continued  weak  market
     performance, is offset by lower spending by PEF's business units.

     Income  tax  expense  was $28.0  million  for the  second  quarter of 2003,
     compared to $45.6 million during the second  quarter of 2002.  Fluctuations
     in income tax expense result from the tax benefit  reallocation,  discussed
     previously, and changes in pre-tax income.

     First Half of 2003 Compared to First Half of 2002

     Retail  revenues,  excluding  fuel  revenues  of $529.3  million and $498.1
     million for the first half of 2003 and 2002, respectively, decreased due to
     the impact of the 9.25% rate reduction,  2002 revenue  sharing  resolution,
     and  the  2003  revenue  sharing  accrual,   all  of  which  are  discussed
     previously.  Partially offsetting these items was the absence of the impact
     of the $35.0 million rate refund that was recognized in 2002 as part of the
     settlement agreement.

     Strong customer growth and usage and favorable weather positively  impacted
     revenues in 2003. The average number of customers  during the first half of
     the year increased by  approximately  34,000 or 2.3% in 2003 as compared to
     the same period in 2002.

     Operation and  maintenance  costs  increased $8.1 million,  compared to the
     $286.6 million incurred during the first half of 2002. The higher operation
     and maintenance costs were primarily due to a $10.7 million decrease in the
     pension credit.

     Income tax expense was $64.9  million for the first half of 2003,  compared
     to $79.0 million during the first half of 2002.  Fluctuations in income tax
     expense result from the tax benefit reallocation, discussed previously, and
     changes in pre-tax income.

     DIVERSIFIED BUSINESSES

     The  Company's  diversified  businesses  consist  primarily  of  the  Fuels
     segment, the CCO segment, the Rail segment, Progress Telecom and SRS. These
     businesses are explained in more detail below.

     Fuels

     The Fuels segment's  operations include synthetic fuel operations,  natural
     gas exploration and production,  coal extraction and terminals  operations.
     Fuels'  results for the second quarter and first half of 2003 were impacted
     most  significantly  by the timing of  synthetic  fuel  production  and the
     increase in gas production.

     The following summarizes the net income of the Fuels segment for the second
     quarter and first half of 2003 and 2002.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     -------------------------------------------------------------------------------------------------------
                                                   Three Months Ended June 30,      Six Months Ended June 30,
     -------------------------------------------------------------------------------------------------------
     (in millions)                                      2003           2002          2003            2002
     -------------------------------------------------------------------------------------------------------
       Synthetic fuel operations                       $ 41.7         $ 44.3        $ 67.2          $ 83.1
       Gas production and coal fuel operations           11.1            1.1          16.3             1.6
       Other earnings (losses)                            1.0            1.3          (3.1)            3.6
                                               -------------------------------------------------------------
          Income from continuing operations            $ 53.8         $ 46.7        $ 80.4          $ 88.3
     -------------------------------------------------------------------------------------------------------
</TABLE>

     Synthetic Fuel Operations

     The synthetic  fuels  operations  generated net income of $41.7 million and
     $44.3  million in the second  quarter of 2003 and 2002,  respectively,  and
     $67.2  million  and  $83.1  million  in the  first  half of 2003 and  2002,
     respectively.  The production and sale of synthetic fuel generate operating
     losses,  but qualify for tax credits  under  Section 29 of the Code,  which
     more than  offset the  effect of such  losses.  In late June 2003,  the IRS
     announced  that  field  auditors  have  raised  questions  associated  with
     synthetic fuel manufactured at the Colona facility regarding the scientific
     validity  of test  procedures  and  results  used to  verify a  significant
     chemical change,  which is a requirement of the synthetic fuel program. The
     impact  of  this  review  on  the  Company's  synthetic  fuel  tax  credits
     previously  taken or expected to be taken in the future cannot be predicted
     at this time. See the "OTHER MATTERS"  section for a further  discussion of
     the IRS review. The following  summarizes the synthetic fuel operations for
     the second quarter and first half of 2003 and 2002.

                                       46
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     -------------------------------------------------------------------------------------------------------
                                                      Three Months Ended June 30,  Six Months Ended June 30,
     -------------------------------------------------------------------------------------------------------
     (in millions)                                        2003           2002         2003         2002
     -------------------------------------------------------------------------------------------------------
     Tons produced                                               2.9          3.4          4.9          6.4
                                                     -------------------------------------------------------

     Operating losses, excluding tax credits                 $ (36.4)     $ (46.9)     $ (63.5)     $ (92.0)
     Tax credits generated                                      78.1         91.2        130.7        175.1
                                                     -------------------------------------------------------
         Income from continuing operations                   $  41.7      $  44.3      $  67.2      $  83.1
     -------------------------------------------------------------------------------------------------------
</TABLE>

     Total 2003  synthetic fuel sales as compared to 2002 decreased $2.6 million
     and $9.4  million  for the second  quarter  and first  half,  respectively,
     primarily  due to a change in the  synthetic  fuel  production  pattern for
     2003.  The  Company   anticipates   total   synthetic  fuel  production  of
     approximately  12  million  tons  for  2003,  which is  comparable  to 2002
     production levels.

     Gas Production and Coal Fuel Operations

     Gas operations generated net income of $9.8 million and $0.9 million in the
     second  quarter of 2003 and 2002,  respectively,  and of $14.7  million and
     $1.2 million in the first half of 2003 and 2002, respectively. The increase
     in production  resulting from the  acquisitions  of Westchester Gas in 2002
     and North Texas Gas in the first  quarter of 2003 drove  increased  revenue
     and  earnings.  Although  the Mesa  operations  continue to produce gas, no
     additional wells are being drilled at Mesa as various  divestiture  options
     are being  explored.  The  following  summarizes  the gas  revenues for the
     second quarter and first half of 2003 and 2002 by production facility.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     ---------------------------------------------------------------------------------------------------------
                                                Three Months Ended June 30,      Six Months Ended June 30,
     -------------------------------------------------------------------------------------------------------
     (in millions)                                      2003           2002          2003            2002
     -------------------------------------------------------------------------------------------------------
       Mesa                                            $  4.0          $ 3.5        $  8.7           $ 6.6
       Westchester Gas                                   13.4            1.6          28.6             1.6
       North Texas Gas                                   10.4              -          10.4               -
       Other                                              2.7            0.8           2.6             0.8
                                               -------------------------------------------------------------
          Total gas sales                              $ 30.5          $ 5.9        $ 50.3           $ 9.0
     -------------------------------------------------------------------------------------------------------
</TABLE>

     Coal fuel  operations  and other  operations  within the Fuels segment have
     immaterial impacts on comparative earnings.

     COMPETITIVE COMMERCIAL OPERATIONS

     CCO  generates  and  sells  electricity  to the  wholesale  market  through
     nonregulated  plants.  These  operations  also  include  limited  financial
     trading  activities.  The following  summarizes  the net income,  sales and
     generating  capacity of the nonregulated  plants for the second quarter and
     first half of 2003 and 2002.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     --------------------------------------------------------------------------------------------------
                                                 Three Months Ended June 30,  Six Months Ended June 30,
     --------------------------------------------------------------------------------------------------
     (in millions except megawatts)                 2003           2002          2003         2002
     --------------------------------------------------------------------------------------------------
     Operating revenue                              $ 33.3         $ 23.9       $ 70.8       $ 32.9
     Income from continuing operations              $  2.4         $  6.7       $ 10.9       $  4.6
     Generation capacity (MW) - June 30              2,620          1,239        2,620        1,239
     --------------------------------------------------------------------------------------------------
</TABLE>

     The  second  quarter  increase  in revenue is  primarily  due to  increased
     contracted  capacity and energy sales from  additional  plants with tolling
     agreements.  The  increase  during the first  half of 2003 in  revenue  and
     earnings is also related to a tolling  agreement  termination  payment from
     Dynegy.  The revenue  increases  related to higher  volumes were  partially
     offset by lower prices in the wholesale energy market,  higher depreciation
     cost of $2.4 million related to the additional  facilities and by increases
     in costs  allocated from the Service  Company of $2.1 million in accordance
     with the SEC audit.

     In the second quarter of 2003, PVI acquired from Williams Energy  Marketing
     and  Trading  a  full-requirements  power  supply  agreement  with  Jackson
     Electric Membership Corp. (Jackson) in Georgia for $188 million.

     During  2002,  the  Company  completed  the  acquisition  of  two  electric
     generation projects,  Walton County Power, LLC and Washington County Power,
     LLC. The  acquisition  resulted in goodwill of $64.1  million.  The Company
     performed the annual goodwill  impairment test in the first quarter of 2003
     which   indicated  no  impairment.   However,   modest  changes  in  either
     assumptions or market conditions could cause some or all of the $64 million
     of goodwill related to the CCO operating segment to become impaired.

                                       47
<PAGE>

     The 466-megawatt Rowan combined cycle unit and the 600-megawatt  Washington
     combustion  turbine  facilities  were  completed and placed into service in
     June 2003.  The  Washington  plant has a tolling  agreement with LG&E Power
     Trading & Marketing  through December 31, 2004. The 480-megawatt  Effingham
     combined  cycle  facility is  expected to be placed into  service in August
     2003 and will complete CCO's  nonregulated  build-out with a total capacity
     of 3,100 megawatts.

     Including  the  Jackson  contract  and the  impact of the  Dynegy  contract
     termination,  mentioned previously,  the Company has contracts for 68%, 74%
     and 50% of planned production capacity for 2003 through 2005, respectively.
     The 2005 decline results from the expiration of four contracts. The Company
     continues to pursue  opportunities  with both current  customers  and other
     potential customers.

     Rail

     Rail's operations  include railcar and locomotive repair,  trackwork,  rail
     parts reconditioning and sales, scrap metal recycling,  railcar leasing and
     other rail  related  services.  The  Company  intends to sell the assets of
     Railcar Ltd., a leasing subsidiary, in 2003 and has classified these assets
     as assets held for sale at June 30, 2003.

     Progress Rail  contributed  net income of $2.2 million and $2.9 million for
     the second quarter of 2003 and 2002,  respectively,  and a net loss of $1.2
     million and net income of $2.2 million for the first half of 2003 and 2002,
     respectively.  As a  result  of the SEC  order,  Rail  incurred  additional
     Service  Company  allocations of $1.2 and $6.9 million in the first quarter
     and first half of 2003, respectively.  These increased costs were partially
     offset by  improvements  in the  recycling  business and reduced  operating
     costs.

     An SEC order  approving  the merger of FPC  requires  the Company to divest
     Rail by November 30, 2003. The Company is pursuing  alternatives,  but does
     not  expect  to find  the  right  divestiture  opportunity  by  that  date.
     Therefore, the Company has sought a three year extension from the SEC.

     Other Businesses Segment

     Progress Energy's Other segment  primarily  includes the operations of SRS,
     Progress  Telecom  and  small  nonregulated  subsidiaries  of PEC.  Holding
     company operations and other corporate  functions that have previously been
     included in the Other  segment  have been  removed  and are being  reported
     separately.  The segment  contributed income from continuing  operations of
     $1.2 million and a loss from  continuing  operations of $8.4 million in the
     second quarter of 2003 and 2002,  respectively,  and income from continuing
     operations of $1.9 million and a loss of $13.2 million in the first half of
     2003 and 2002, respectively.

     The  improvement  in both the  quarter  and the half is related to Progress
     Telecom's  lower  depreciation  charges  resulting from the impairment of a
     significant   portion  of  its  assets  in  the  third   quarter  of  2002.
     Additionally,  SRS  recognized a loss in the second quarter of 2002 related
     to the sale of certain portions of its operations.

     CORPORATE SERVICES

     Corporate  Services  includes the  operations of the Holding  Company,  the
     Service Company, and consolidation  entities, as summarized below (expenses
     are indicated by positive numbers).
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     -------------------------------------------------------------------------------------------------------
                                              Three Months Ended June 30,      Six Months Ended June 30,
     -------------------------------------------------------------------------------------------------------
     (in millions)                                 2003         2002          2003              2002
     -------------------------------------------------------------------------------------------------------
       Interest expense                           $ 73.3     $  75.7         $ 144.3           $ 146.7
       Contingent value obligations                  1.7        (1.5)              -             (12.8)
       Tax reallocation                              9.3        30.0            18.6              30.0
       Tax levelization                              4.8        58.4            (5.4)             79.6
       Other income taxes                          (31.3)      (31.5)          (62.4)            (63.4)
       Other expenses                                1.2         3.5             5.1               7.6
                                             -----------------------------------------------------------
         Loss from continuing operations          $ 59.0     $ 134.6         $ 100.2           $ 187.7
     -------------------------------------------------------------------------------------------------------
</TABLE>

     Progress Energy issued 98.6 million  contingent value obligations (CVOs) in
     connection with the 2000 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 June 30, 2003 and
     2002,  the CVOs had fair market values of  approximately  $13.8 million and
     $29.1 million, respectively. Progress Energy recorded an unrealized loss of
     $1.7 million and unrealized  gain of $1.5 million for the second quarter of

                                       48
<PAGE>

     2003 and 2002,  respectively,  to record  the  changes in fair value of the
     CVOs, which had average unit prices of $0.14 and $0.30 at June 30, 2003 and
     2002, respectively. The CVO values at June 30, 2003 were unchanged from the
     January 1, 2003 values, thus requiring no recognition of an unrealized gain
     or loss in the first half. A $12.8 million unrealized gain was recorded for
     the first half of 2002.

     GAAP requires companies to apply a levelized  effective tax rate to interim
     periods that is consistent  with the estimated  annual  effective tax rate.
     Income tax expense was  increased by $4.8 million and $58.4 million for the
     second  quarter of 2003 and 2002,  respectively,  in order to  maintain  an
     effective tax rate  consistent with the estimated  annual rate.  Income tax
     expense was decreased by $5.4 million and  increased  $79.6 million for the
     first half of 2003 and 2002, respectively.  The tax credits associated with
     the  Company's  synthetic  fuel  operations  primarily  drive the  required
     levelization  amount.  Fluctuations  in estimated  annual  earnings and tax
     credits can also cause large swings in the  effective  tax rate for interim
     periods.  Therefore,  this adjustment will vary each quarter, but will have
     no effect on net income for the year.

     DISCONTINUED OPERATIONS

     In the fourth  quarter of 2002, the Company's  Board of Directors  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 the sale to
     close during the third  quarter of 2003 for net  proceeds of  approximately
     $400  million.  An estimated  loss on the sale of NCNG of $29.4 million was
     recognized in the fourth quarter of 2002.

     LIQUIDITY AND CAPITAL RESOURCES

     Progress Energy, Inc.

     Statement of Cash Flows and Financing Activities

     Cash provided by operating  activities increased $114.9 million for the six
     months ended June 30, 2003,  when compared to the  corresponding  period in
     the prior year. The increase in cash from operating activities for the 2003
     period is due to improved  operating  cash flow at PVI and Progress  Fuels,
     which offset lower cash from operations at the utility operations.

     Net cash used in investing  activities decreased $137.9 million for the six
     months ended June 30, 2003,  when compared to the  corresponding  period in
     the prior  year.  The  decrease  in cash used in  investing  activities  is
     primarily due to lower capital  spending at PVI, which acquired  generating
     assets from LG&E in February 2002 for approximately $350 million.

     During  the  first  six  months  of  2003,  $366.5  million  was  spent  in
     diversified   business  property   additions.   This  amount  includes  the
     acquisition  of the natural gas reserves in February 2003 for $148 million.
     In addition to the $366.5  million spent on diversified  business  property
     additions,  PVI also  purchased  a wholesale  energy  supply  contract  for
     approximately $190 million.

     The increase in operating cash flow and lower capital expenditures resulted
     in an increase  of $253  million of net cash flow  before  common  dividend
     payments and other financing  activity for the six month period ending June
     30, 2003 compared with the corresponding period for the prior year.

     On February 21,  2003,  PEF issued $425  million of First  Mortgage  Bonds,
     4.80% Series,  Due March 1, 2013 and $225 million of First Mortgage  Bonds,
     5.90% Series,  Due March 1, 2033.  Proceeds from this issuance were used to
     repay the balance of its  outstanding  commercial  paper,  to refinance its
     secured and unsecured  indebtedness,  including  PEF's First Mortgage Bonds
     6.125% Series Due March 1, 2003,  which were retired on March 1, 2003,  and
     to redeem on March 24, 2003, the $150 million aggregate outstanding balance
     of its 8% First Mortgage Bonds due 2022 at 103.75% of the principal  amount
     of such bonds.

     On April 1,  2003,  PEF  entered  into a new $200  million  364-day  credit
     agreement and a new $200 million three-year credit agreement, replacing its
     prior credit  facilities (which had been a $90 million 364-day facility and
     a $200 million five-year facility). The new PEF credit facilities contain a
     defined  maximum  total debt to total  capital ratio of 65%; as of June 30,
     2003 the calculated ratio was 52.6%. The new credit facilities also contain
     a requirement  that the ratio of EDITDA,  as defined in the facilities,  to
     interest  expense to be at least 3 to 1; as of June 30, 2003 the calculated
     ratio was 8.7 to 1.

     Also on April 1, 2003, PEC reduced the size of its existing  364-day credit
     facility  from  $285  million  to $165  million.  The  other  terms of this
     facility were not changed.  On July 30, 2003,  PEC renewed its $165 million

                                       49
<PAGE>

     364-day credit  agreement PEC's $285 million  three-year  credit  agreement
     entered into in July 2002 remains in place,  for total  facilities  of $450
     million.

     On May 27, 2003,  PEC redeemed $150 million of First Mortgage  Bonds,  7.5%
     Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
     PEC funded the redemption with commercial paper.

     In March  2003,  Progress  Genco  Ventures,  LLC  (Genco),  a wholly  owned
     subsidiary  of PVI,  terminated  its $50  million  working  capital  credit
     facility. A related  construction  facility initially provided for Genco to
     draw up to $260 million. The amount outstanding under this facility is $241
     million  as of June 30,  2003.  During  the  second  quarter  of 2003 Genco
     determined  it did  not  need to  make  any  additional  draws  under  this
     facility.  As a result of this  decision,  the drawn amount of $241 million
     will not increase.

     On July 14, 2003,  PEC  announced  the  redemption of $100 million of First
     Mortgage Bonds,  6.875% Series Due August 15, 2023 at 102.84%.  The date of
     the redemption  will be August 15, 2003. PEC will fund the redemption  with
     commercial paper.

     For the three months ended June 30, 2003, the Company issued  approximately
     2.4 million shares representing  approximately $98 million in proceeds from
     its Investor Plus Stock Purchase Plan and its employee benefit plans during
     the second  quarter ended June 30, 2003.  For the six months ended June 30,
     2003,  the Company  has issued 4.2  million  shares  through  these  plans,
     resulting in $172 million of cash proceeds.

     Future Commitments

     The current portion of long-term debt of $1.1 billion includes $500 million
     of Progress  Energy's 6.55% senior  unsecured  notes due March 1, 2004. The
     Company expects to have sufficient commercial paper capacity to retire this
     issue  due to the  proceeds  from the sale of North  Carolina  Natural  Gas
     (NCNG)  in the  summer  of  2003.  The  proceeds  from the sale of NCNG are
     expected  to be  approximately  $400  million  and  will be used to  reduce
     commercial  paper. The current portion of long-term debt also includes $400
     million of secured  debt issued by PEC.  These  amounts are  expected to be
     refinanced or retired through commercial paper, capital market transactions
     and with internal generation of funds.

     As of June 30, 2003,  Progress  Energy's  guarantees were  approximately $1
     billion,  up from  approximately  $785  million as of March 31,  2003.  The
     increase  is  due  primarily  to  a  $285  million  performance   guarantee
     associated  with the  purchase of a wholesale  power  supply  contract,  as
     discussed previously.

     OTHER MATTERS

     PEF Rate Case Settlement

     On  March  27,  2002,  the  parties  in  PEF'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  provides that PEF will operate under a Revenue Sharing Incentive
     Plan (the Plan) through 2005 and thereafter until terminated by the FPSC.

     The Plan  provides that all retail base  revenues  between the  established
     threshold  and cap  will  be  shared  on a 2/3 - 1/3,  customer/shareholder
     basis.  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 was limited to 67.1% of
     the retail base rate  revenues  that exceeded the 2002 cap. The retail base
     revenue cap for 2003 is $1.393  billion and will  increase $37 million each
     year thereafter.  As of December 31, 2002, $4.7 million was accrued and was
     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 disputed PEF's calculation of retail
     revenue  subject to refund and  contended  that the refund should have been
     approximately  $23 million.  On July 9, 2003,  the FPSC ruled that PEF must
     provide an additional $18.4 million to its retail customers  related to the
     2002 revenue  sharing  calculation.  PEF recorded this refund in the second
     quarter 2003 as a charge against electric operating revenue and will refund
     this amount by no later than  October 31,  2003.  In the second  quarter of
     2003,  PEF also recorded an additional  accrual of $9.5 million  related to
     estimated 2003 revenue sharing.

                                       50
<PAGE>

     Synthetic Fuels Tax Credits

     Progress Energy,  through its  subsidiaries,  produces  synthetic fuel from
     coal  fines.  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. Any synthetic fuel tax credit amounts
     not utilized are carried  forward  indefinitely.  All of Progress  Energy's
     synthetic fuel facilities have received  private letter rulings (PLRs) from
     the Internal  Revenue  Service (IRS) with respect to their  synthetic  fuel
     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. Additionally, the ability to use tax credits currently being carried
     forward  could be  denied.  Total  Section  29  credits  generated  to date
     (including FPC prior to its  acquisition by the Company) are  approximately
     $1.028  billion,  of which $445.6 million have been used and $582.4 million
     are being carried forward as of June 30, 2003.

     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 $273.1 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 the  Company's  majority-owned  synthetic  fuel
     entities,  including Colona, were accepted into the IRS Prefiling 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,  and  issues not
     resolved  through the program may proceed to the next level of the IRS exam
     process.

     In late June 2003,  the Company was informed  that IRS field  auditors have
     raised questions  regarding the chemical change  associated with coal-based
     synthetic fuel  manufactured at its Colona facility and the testing process
     by  which  the  chemical  change  is  verified.  (The  questions  arose  in
     connection  with  the  Company's  participation  in the PFA  program.)  The
     chemical  change and the associated  testing process were described as part
     of the PLR request for Colona.  Based upon that application,  the IRS ruled
     in Colona's  PLR that the  synthetic  fuel  produced at Colona  undergoes a
     significant  chemical  change  and thus  qualifies  for tax  credits  under
     Section 29 of the Internal  Revenue Code.  While the IRS has announced that
     they may revoke PLRs if test procedures and results do not demonstrate that
     a  significant  chemical  change  has  occurred,  based on the  information
     received to date, the Company does not believe the issues warrant  reversal
     by the IRS National Office of its prior position in the Colona PLR.

     The information  provided by the IRS field auditors addresses only Progress
     Energy's Colona facility.  The Company,  however,  applies  essentially the
     same chemical process and uses the same independent laboratories to confirm
     chemical  change in the  synthetic  fuel  manufactured  at each of its four
     other  facilities.  The  independent  laboratories  used by the  Company to
     determine  significant  chemical  change are the  leading  experts in their
     field  and are  used by  many  other  industry  participants.  The  Company
     believes that the  laboratories'  work and the chemical  change process are
     consistent with the bases upon which its PLRs were issued.

     The Company is working to resolve  this matter as quickly as  possible.  At
     this time,  the Company  cannot predict how long the IRS process will take;
     however,  the Company intends to continue  working  cooperatively  with the
     IRS. The Company firmly  believes that it is operating the Colona  facility
     and its other  plants in  compliance  with its PLRs and  Section  29 of the
     Internal  Revenue  Code.  Accordingly,  the Company has no current plans to
     alter its synthetic fuel production schedules as a result of these matters.

     In  addition,  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.
     However,  the IRS has suspended issuance of PLRs relating to synthetic fuel
     production  (typically a closing  condition to the sale of an interest in a
     synthetic fuel entity).  Unless that  suspension on new PLRs is lifted,  it
     will be difficult to  consummate  the  successful  sale of interests in the
     Company's synthetic fuel facilities.  The Company cannot predict when or if
     the IRS will recommence  issuing such PLRs. The final outcome and timing of
     the Company's  efforts to sell  interests in synthetic  fuel  facilities is
     uncertain and while the Company  cannot predict the outcome of this matter,
     the outcome is not expected to have a material  effect on the  consolidated
     financial position, cash flows or results of operations.

                                       51
<PAGE>

     Nuclear Matters

     The Shearon  Harris Nuclear Plant in New Hill,  North Carolina  completed a
     successful  refueling outage on May 18, 2003, when the unit was returned to
     service.

     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 penetration leakage
     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 Company  currently  plans to re-inspect the Robinson Plant reactor head
     during its next refueling outage in the spring of 2004 and replace the head
     in  the  fall  of  2005.   The  Harris   Plant  is  ranked  in  the  lowest
     susceptibility  classification.  During  the  Harris  Plant's  Spring  2003
     outage,  the  Company  completed  a series of  examinations  of the  entire
     reactor  pressure  vessel head and found no  degradation  or  indication of
     leakage.

     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 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 pressurized water reactors (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.

     In April 2003, the STP Nuclear Operating Company,  an unaffiliated  entity,
     notified the NRC of a potential  leak  indication on the bottom head of the
     reactor  vessel of one of its units.  The Company is  continuing to monitor
     this development for  applicability to our plants and will take appropriate
     action if and when necessary.

     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.

     The NRC continues to issue additional  orders designed to increase security
     at nuclear  facilities.  In April 2003, one of the orders issued by the NRC
     imposes  revisions to the Design Basis Threat and requires  power plants to
     implement  additional  protective  actions to protect  against  sabotage by
     terrorists and other  adversaries.  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.

     Franchise Litigation

     Six cities, with a total of approximately  49,000 customers,  have sued PEF
     in various circuit courts in Florida.  As discussed  below,  two of the six
     cities, with a total of approximately  21,000 customers,  have subsequently
     settled  their  lawsuits  with  PEF  and  signed  new,  30-year   franchise
     agreements.  The lawsuits  principally seek 1) a declaratory  judgment that
     the cities have the right to purchase  PEF'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 PEF to continue to
     collect from PEF's customers and remit to the cities, franchise fees during
     the pending litigation,  and as long as PEF continues to occupy the cities'
     rights-of-way to provide electric service,  notwithstanding  the expiration
     of the  franchise  ordinances  under  which PEF had agreed to collect  such
     fees.  Five circuit  courts have entered  orders  requiring  arbitration to
     establish the purchase price of PEF's electric  distribution  system within
     five cities. Two appellate courts have upheld these circuit court decisions
     and authorized cities to determine the value of PEF's electric distribution
     system  within  the  cities  through  arbitration.  To  date,  no city  has
     attempted to actually  exercise the option to purchase any portion of PEF's
     electric distribution system.  Arbitration in one of the cases (the City of
     Casselberry)  was held in August  2002 and an award was  issued in  October
     2002  setting the value of PEF's  distribution  system  within that city at
     approximately  $22 million.  On April 2, 2003, PEF filed a rate filing with
     the FERC to  recover  $10.6  million  in  stranded  costs  from the City of
     Casselberry in the event the City ultimately chooses and is allowed to form
     a municipal  electric  utility.  PEF's rate filing has been abated  pending
     settlement discussions between the parties. On July 28, the City approved a
     settlement  agreement and a new, 30-year franchise  agreement with PEF. The
     settlement  resolves  all  pending  litigation  with  that  city.  A second
     arbitration  (with the City of Winter Park) was completed in February 2003.
     That arbitration panel issued an award on May 29, 2003 setting the value of
     PEF's  distribution  system within the City of Winter Park at approximately
     $31.5 million,  not including separation and reintegration and construction

                                       52
<PAGE>

     work in progress, which could add several million dollars to the award. The
     panel also awarded PEF  approximately  $10.7 million in stranded costs. The
     City of Winter  Park has  scheduled a September  9, 2003  referendum  where
     citizens  will  decide  whether to issue bonds of up to  approximately  $50
     million  to  acquire  PEF's  electric  distribution  system.  At this time,
     whether and when there will be further  proceedings  regarding  the City of
     Winter Park cannot be  determined.  A third  arbitration  (with the Town of
     Belleair) was  completed on June 16, 2003. A decision from the  arbitration
     panel has not yet been issued in that case. A fourth  arbitration (with the
     City of Apopka) has been scheduled for January 2004. On August 4, 2003, the
     City of Longwood  approved a 30-year  franchise and a settlement  agreement
     with PEF,  which  will  resolve  all  pending  litigation  with the City of
     Longwood.  Arbitration  in the  remaining  city's  litigation  (the City of
     Edgewood) has not yet been scheduled.

     As part of the above  litigation,  two  appellate  courts have also reached
     opposite  conclusions  regarding  whether PEF must continue to collect from
     its  customers and remit to the cities  "franchise  fees" under the expired
     franchise  ordinances.  PEF has filed an appeal  with the  Florida  Supreme
     Court to resolve the conflict between the two appellate courts. The Florida
     Supreme Court has set oral argument for August 27, 2003. The Company cannot
     predict the outcome of these matters at this time.

     Progress Energy Carolinas, Inc.

     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 PEC: RESULTS OF OPERATIONS;  LIQUIDITY AND CAPITAL  RESOURCES and
     OTHER MATTERS.

     RESULTS OF OPERATIONS

     The  results of  operations  for the PEC  Electric  segment  are  identical
     between  PEC and  Progress  Energy.  The  results of  operations  for PEC's
     non-utility  subsidiaries  for the six months  ended June 30, 2003 and 2002
     are not material to PEC's consolidated financial statements.

     LIQUIDITY AND CAPITAL RESOURCES

     Cash  provided by operating  activities  increased  $61 million for the six
     months ended June 30, 2003,  when compared to the  corresponding  period in
     the prior year.  The  increase  was caused  primarily by changes in working
     capital.

     Cash used in investing activities increased  approximately $150 million for
     the six months  ended June 30,  2003,  when  compared to the  corresponding
     period in the prior year.  The  increase  was mostly due to $244 million in
     cash proceeds  received  during the second  quarter of 2002 for the sale of
     generating  assets to Progress  Ventures  during the first quarter of 2002.
     The sales  proceeds  were  offset by a decrease in  construction  spending.
     During  the  first  six  months of 2003,  $322  million  was spent on PEC's
     construction  program,  nuclear fuel  additions  and  contributions  to its
     nuclear  decommissioning  fund. This amount was  approximately  $80 million
     less than the corresponding period last year. The decrease was due to lower
     construction  expenditures associated with generation assets transferred to
     PVI during 2002.

     As of June 30, 2003,  PEC's  liquidity,  contractual  cash  obligations and
     other  commercial  commitments  have not changed  materially  from what was
     reported in the 2002 Annual Report on Form 10-K, as amended.

     On April 1, 2003,  PEC  reduced  the size of its  existing  364-day  credit
     facility  from  $285  million  to $165  million.  The  other  terms of this
     facility were not changed.  On July 30, 2003,  PEC renewed its $165 million
     364-day credit  agreement PEC's $285 million  three-year  credit  agreement
     entered into in July 2002 remains in place,  for total  facilities  of $450
     million.

     On May 27, 2003,  PEC redeemed $150 million of First Mortgage  Bonds,  7.5%
     Series, Due March 1, 2023 at 103.22% of the principal amount of such bonds.
     PEC funded the redemption with commercial paper.

     On July 14, 2003,  PEC  announced  the  redemption of $100 million of First
     Mortgage Bonds,  6.875% Series Due August 15, 2023 at 102.84%.  The date of
     the redemption will be August 15, 2003 and the redemption will be funded by
     PEC with commercial paper.

     The current portion of long-term debt includes $400 million of secured debt
     issued by PEC.  The  current  portion of  long-term  debt is expected to be
     refinanced or retired through commercial paper, capital market transactions
     and internal generation of funds.

                                       54
<PAGE>

Item 3.  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.

     The  Company's  exposure  to  return  on  marketable   securities  for  the
     decommissioning  trust funds has not changed  materially since December 31,
     2002. The Company's  exposure to market value risk with respect to the CVOs
     has also not changed materially since December 31, 2002.

     On February 21,  2003,  PEF issued $425  million of First  Mortgage  Bonds,
     4.80% Series,  Due March 1, 2013 and $225 million of First Mortgage  Bonds,
     5.90% Series,  Due March 1, 2033.  Proceeds from this issuance were used to
     repay the balance of its  outstanding  commercial  paper,  to refinance its
     secured and unsecured  indebtedness,  including  PEF's First Mortgage Bonds
     6.125% Series Due March 1, 2003,  and to redeem the  aggregate  outstanding
     balance of its 8% First Mortgage Bonds Due 2022.

     In March,  April and June of 2003,  PEC entered into treasury rate locks to
     hedge its  exposure to interest  rates with regard to a future  issuance of
     debt.  These  agreements have a  computational  period of ten years and are
     designated as cash flow hedges for accounting purposes. The agreements have
     a total notional amount of $60 million.

     Effective  March 24,  2003,  PEF redeemed  $150  million of First  Mortgage
     Bonds, 8% Series,  Due December 1, 2022 at 103.75% of the principle  amount
     of such bonds.

     The exposure to changes in interest rates from the Company's fixed rate and
     variable rate long-term debt at June 30, 2003 has changed from December 31,
     2002.  The  total  fixed  rate  long-term  debt at June 30,  2003 was $9.27
     billion,  with an average  interest  rate of 6.70% and fair market value of
     $10.68  billion.  The total  variable rate long-term debt at June 30, 2003,
     was $1.10 billion,  with an average  interest rate of 1.41% and fair market
     value of $1.11 billion.

     The  exposure to changes in interest  rates from the  Company's  commercial
     paper and FPC mandatorily  redeemable securities of trust at June 30, 2003,
     was not materially different than at December 31, 2002.

     Progress Energy Carolinas, Inc.

     PEC has certain market risks inherent in its financial  instruments,  which
     arise from  transactions  entered  into in the normal  course of  business.
     PEC's  primary  exposures  are  changes in interest  rates with  respect to
     long-term  debt and commercial  paper,  and  fluctuations  in the return on
     marketable  securities  with respect to its nuclear  decommissioning  trust
     funds.   PEC's  exposure  to  return  on  marketable   securities  for  the
     decommission  trust funds has not changed  materially  since  December  31,
     2002.

     In March,  April and June of 2003,  PEC entered into treasury rate locks to
     hedge its  exposure to interest  rates with regard to a future  issuance of
     debt.  These  agreements have a  computational  period of ten years and are
     designated as cash flow hedges for accounting purposes.

     The  exposure  to  changes  in  interest  rates  from the PEC's  fixed rate
     long-term debt,  variable rate long-term debt and commercial  paper at June
     30, 2003 was not materially different than at December 31, 2002.


                                       54
<PAGE>

Item 4.  Controls and Procedures

     Progress Energy, Inc.

     Pursuant  to Rule  13a-15(b)  under the  Securities  Exchange  Act of 1934,
     Progress  Energy  carried  out an  evaluation,  with the  participation  of
     Progress  Energy's  management,  including  Progress  Energy's Chairman and
     Chief Executive Officer,  and Chief Financial Officer, of the effectiveness
     of Progress Energy's  disclosure  controls and procedures (as defined under
     Rule 13a-15(e) under the Securities  Exchange Act of 1934) as of the end of
     the period  covered by this report.  Based upon that  evaluation,  Progress
     Energy's Chairman and Chief Executive Officer,  and Chief Financial Officer
     concluded  that Progress  Energy's  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  Progress  Energy's  periodic  SEC  filings.  There has been no
     change in Progress  Energy's  internal  control  over  financial  reporting
     during the quarter ended June 30, 2003 that has materially affected,  or is
     reasonably likely to materially affect,  Progress Energy's internal control
     over financial reporting.

     Progress Energy Carolinas, Inc.

     Pursuant to Rule 13a-15(b)  under the Securities  Exchange Act of 1934, PEC
     carried out an  evaluation,  with the  participation  of PEC's  management,
     including PEC's Chairman and Chief Executive  Officer,  and Chief Financial
     Officer,  of the effectiveness of PEC's disclosure  controls and procedures
     (as defined under Rule 13a-15(e) under the Securities Exchange Act of 1934)
     as of the  end of the  period  covered  by this  report.  Based  upon  that
     evaluation, PEC's Chairman and Chief Executive Officer, and Chief Financial
     Officer  concluded  that  PEC's  disclosure  controls  and  procedures  are
     effective in timely alerting them to material  information  relating to PEC
     (including its consolidated  subsidiaries) required to be included in PEC's
     periodic SEC filings.  There has been no change in PEC's  internal  control
     over  financial  reporting  during the quarter ended June 30, 2003 that has
     materially  affected,  or is reasonably likely to materially affect,  PEC's
     internal control over financial reporting.


                                       55
<PAGE>



                           PART II. OTHER INFORMATION

Item 1.  Legal Proceedings

Legal aspects of certain matters are set forth in Part I, Item 1. See Note 15 to
the Progress Energy, Inc.  Consolidated  Interim Financial Statements and Note 9
to the PEC's Consolidated Interim Financial Statements.

1.   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 in the form of a  cross-complaint  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.  SRS filed its answer to the new
pleadings on April 14, 2003.  The Company has reviewed the new pleadings and the
Company believes that the new claims are not meritorious.  The Company has filed
responsive  pleadings  denying the  allegations,  and the  discovery  process is
underway.  SRS, the Company and Progress Energy Solutions,  Inc. 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

Progress Energy, Inc.

(a)  The Annual Meeting of the Shareholders of Progress Energy, Inc. was held on
     May 14, 2003.

(b)  The meeting  involved  the election of five Class II directors to serve for
     three-year  terms.  Proxies  for the  meeting  were  solicited  pursuant to
     Regulation  14, there was no  solicitation  in opposition  to  management's
     nominees as listed below, and all nominees were elected.

(c)  Results of matters voted on were as follows:

Election of Directors

Class II                   Votes For                        Votes Withheld
(Term Expiring in 2006)

Edwin B. Borden            193,007,893                        4,613,431
James E. Bostic, Jr.       192,204,838                        5,416,487
David L. Burner            192,182,065                        5,439,259
Richard L. Daugherty       192,186,613                        5,434,712
Richard A. Nunis           193,138,277                        4,483,047


                                       56
<PAGE>



Shareholder Proposals

The shareholder proposal requesting that the Board adopt a policy requiring that
all stock option grants to senior executives be performance-based was presented,
but was not approved by the shareholders.

The number of shares voted for the proposal was 32,819,916.
The number of shares voted against the proposal was  129,021,383.
The number of abstaining votes was 4,662,102.
The delivered not voted total was 31,157,923.

The  shareholder  proposal  requesting  that the  Board  establish  a policy  of
expensing  stock options on its annual income  statement was presented,  but was
not approved by the shareholders.

The number of shares voted for the proposal was 72,431,261.
The number of shares voted against the proposal was  88,376,736
The number of  abstaining  votes was 5,655,400.
The delivered not voted total was 31,157,926.

Carolina Power & Light Company,  doing  business as Progress  Energy  Carolinas,
Inc.

(a)  The Annual  Meeting of the  Shareholders  of Carolina Power & Light Company
     was held on May 14, 2003.

(b)  The  meeting  involved  the  election of five Class II  directors  to serve
     three-year  terms.  Proxies  for the  meeting  were  solicited  pursuant to
     Regulation  14, there was no  solicitation  in opposition  to  management's
     nominees as listed below, and all nominees were elected.

(c)  The total votes for the election of directors were as follows:

Class II                     Votes For                    Votes Withheld
(Term Expiring in 2006)

Edwin B. Borden            159,941,669                        1,470
James E. Bostic, Jr.       159,941,819                        1,320
David L. Burner            159,941,802                        1,339
Richard L. Daugherty       159,941,826                        1,313
Richard A. Nunis           159,941,437                        1,702

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     Exhibit                                                                         Progress            Progress Energy
     Number                                 Description                            Energy, Inc.          Carolinas, Inc.
     ------                                 -----------                            ------------          ---------------

      10(i)          Amended and Restated  Progress Energy,  Inc.  Restoration          X                       X
                     Retirement Plan, effective as of July 10, 2002

     10(ii)          Progress Energy,  Inc.  Non-Employee  Director Stock Unit          X                       X
                     Plan, amended and restated effective July 10, 2002

     10(iii)         Amended  and  Restated   Supplemental   Senior  Executive          X                       X
                     Retirement  Plan  of  Progress  Energy,  Inc.,  effective
                     January 1, 1984 (As last amended effective July 10, 2002)

     10(iv)          Amended   Management   Incentive   Compensation  Plan  of          X                       X
                     Progress Energy, Inc., as amended January 1, 2003

                                       57
<PAGE>

      10(v)          Amendment and Restatement,  dated as of July 30, 2003, to                                  X
                     the 364-Day  Revolving  Credit  Agreement  among Carolina
                     Power & Light Company (d/b/a Progress  Energy  Carolinas,
                     Inc.) and certain Lenders

      31(a)          Certifications   pursuant   to   Section   302   of   the          X                       X
                     Sarbanes-Oxley   Act  of  2002  -   Chairman   and  Chief
                     Executive Officer

      31(b)          Certifications   pursuant   to   Section   302   of   the          X                       X
                     Sarbanes-Oxley  Act of 2002 -  Executive  Vice  President
                     and Chief Financial Officer

      32(a)          Certifications   pursuant   to   Section   906   of   the          X                       X
                     Sarbanes-Oxley   Act  of  2002  -   Chairman   and  Chief
                     Executive Officer

      32(b)          Certifications   pursuant   to   Section   906   of   the          X                       X
                     Sarbanes-Oxley  Act of 2002 -  Executive  Vice  President
                     and Chief Financial Officer
</TABLE>

(b)  Reports on Form 8-K since the beginning of the quarter:

     Progress Energy, Inc.

                       Financial
         Item          Statements
       Reported         Included             Date of Event          Date Filed

          5                No                 April 1, 2003        April 1, 2003
        9, 12             Yes                April 23, 2003       April 23, 2003
         7, 9              No                April 30, 2003       April 30, 2003
          9                No                  May 30, 2003         May 30, 2003
         7, 9              No                  May 30, 2003        June 11, 2003
          5                No                 June 24, 2003        June 24, 2003
        9, 12             Yes                 July 23, 2003        July 23, 2003


     Carolina Power & Light Company
     d/b/a Progress Energy Carolinas, Inc.

                       Financial
         Item          Statements
       Reported         Included             Date of Event          Date Filed

          5                No                 April 1, 2003        April 1, 2003
        9, 12             Yes                April 23, 2003       April 23, 2003
        9, 12             Yes                 July 23, 2003        July 23, 2003



                                       58

<PAGE>




                                   SIGNATURES


Pursuant to requirements 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: August 11, 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

                                       59