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

                                    FORM 10-K

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

                   For the fiscal year ended December 31, 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>

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

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

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

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


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

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

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

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

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

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

As of June 30, 2003,  the  aggregate  market value of the voting and  non-voting
common   equity  of  Progress   Energy,   Inc.   held  by   non-affiliates   was
$10,586,386,401.  As of June 30, 2003, the aggregate  market value of the common
equity of Carolina Power & Light Company held by  non-affiliates  was $0. All of
the common stock of Carolina Power & Light Company is owned by Progress  Energy,
Inc.

                                       1
<PAGE>

As of January 30, 2004, 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)             245,640,831
Carolina Power & Light Company             Common Stock (Without Par Value)             159,608,055
</TABLE>


                       DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Progress Energy and PEC definitive  proxy statements dated March
31, 2004 are incorporated into PART III, ITEMS 10, 11, 12 , 13 and 14 hereof.

This combined Form 10-K 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.


                                       2
<PAGE>

                                TABLE OF CONTENTS

GLOSSARY OF TERMS

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS


                                     PART I

ITEM 1.  BUSINESS

ITEM 2.  PROPERTIES

ITEM 3.  LEGAL PROCEEDINGS

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

         EXECUTIVE OFFICERS OF THE REGISTRANTS

                                     PART II

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

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

ITEM 8.  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9A. CONTROLS AND PROCEDURES

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

                                     PART IV

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

PROGRESS ENERGY, INC. RISK FACTORS

CAROLINA POWER & LIGHT COMPANY RISK FACTORS

                                       3
<PAGE>

                                GLOSSARY OF TERMS

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

   TERM                                                DEFINITION

401(k)                         Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC                          Allowance for funds used during construction
the Agreement                  Stipulation and Settlement Agreement related to retail rate matters
AHI                            Affordable Housing investment
ARO                            Asset Retirement Obligation
Bcf                            Billion cubic feet
Broad River                    Skygen Energy LLC's Broad River Facility
Btu                            British thermal units
Caronet                        Caronet, Inc.
CCO                            Competitive Commercial Operations business segment
CERCLA or Superfund            Comprehensive Environmental Response, Compensation and Liability Act of
                               1980, as amended
Code                           Internal Revenue Code
Colona                         Colona Synfuel Limited Partnership, L.L.L.P.
the Company                    Progress Energy, Inc. and subsidiaries
CP&L                           Carolina Power & Light Company
CR3                            Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3
CVO                            Contingent value obligation
DOE                            United States Department of Energy
DWM                            North Carolina Department of Environment and Natural Resources, Division of
                               Waste Management
ENCNG                          Eastern North Carolina Natural Gas Company, formerly referred to as
                               EasternNC
EITF                           Emerging Issues Task Force
E&TW                           Engineering and Trackwork
EPA                            United States Environmental Protection Agency
EPA of 1992                    Energy Policy Act of 1992
EPIK                           EPIK Communications, Inc.
ESOP                           Employee Stock Ownership Plan
FASB                           Financial Accounting Standards Board
FERC                           Federal Energy Regulatory Commission
FDEP                           Florida Department of Environment and Protection
FIN No. 46                     FASB Interpretation No. 46, "Consolidation of Variable Interest Entities -
                               an Interpretation of ARB No. 51"
FIN No. 46R                    December 2003 revision of FIN No. 46
Florida Progress or FPC        Florida Progress Corporation
FPSC                           Florida Public Service Commission
Fuels                          Fuels business segment
Funding Corp.                  Florida Progress Funding Corporation
Genco                          Progress Genco Ventures LLC
Georgia Power                  Georgia Power Company
Global                         U.S. Global LLC
Harris Plant                   Shearon Harris Nuclear Plant
Interpath                      Interpath Communications, Inc.
IBEW                           International Brotherhood of Electrical Workers
IRS                            Internal Revenue Service
ISO                            Independent System Operator
Jackson                        Jackson Electric Membership Corporation
kV                             Kilovolt
kVA                            Kilovolt-ampere
LIBOR                          London Inter Bank Offering Rate
LRS                            Locomotive and Railcar Services
LSEs                           Load-serving entities
MACT                           Maximum Achievable Control Technology
MDC                            Maximum Dependable Capability
MGP                            Manufactured Gas Plant
MW                             Megawatt

                                       4
<PAGE>

MWh                            Megawatt-hour
NCNG                           North Carolina Natural Gas Corporation
NCUC                           North Carolina Utilities Commission
NEIL                           Nuclear Electric Insurance Limited
NOx                            Nitrogen oxide
NOx SIP Call                   EPA rule which requires 22 states including North and South Carolina to
                               further reduce nitrogen oxide emissions.
NRC                            United States Nuclear Regulatory Commission
Nuclear Waste Act              Nuclear Waste Policy Act of 1982
OPEB                           Postretirement benefits other than pensions
Odyssey                        Odyssey Telecorp, Inc.
P11                            Intercession Unit P11
PEC                            Progress Energy Carolinas, Inc.
PESC                           Progress Energy Service Company, LLC
PFA                            IRS Prefiling Agreement
the Plan                       Revenue Sharing Incentive Plan
PLR                            Private Letter Ruling
Power Agency                   North Carolina Eastern Municipal Power Agency
PCH                            Progress Capital Holdings, Inc.
Progress Energy                Progress Energy, Inc.
Progress Fuels                 Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail                  Progress Rail Services Corporation
Progress Ventures              Business unit of Progress Energy primarily made up of nonregulated energy
                               generation and marketing activities, as well as gas, coal and synthetic
                               fuel operations
Preferred Securities           FPC-obligated mandatorily redeemable preferred securities of FPC Capital I
PRP                            Potentially responsible party, as defined in CERCLA
PSSP                           Performance Share Sub-Plan
PTC                            Progress Telecommunications Corporation
PTC LLC                        Progress Telecom, LLC
PUHCA                          Public Utility Holding Company Act of 1935, as amended
PURPA                          Public Utilities Regulatory Policies Act of 1978
PVI                            Progress Ventures, Inc. (formerly referred to as CPL Energy Ventures, Inc.)
PWR                            Pressurized water reactor
QF                             Qualifying facilities
Rail Services                  Rail Services business segment
Rockport                       Indiana Michigan Power Company's Rockport Unit No. 2
RSA                            Restricted Stock Awards program
RTO                            Regional Transmission Organization
SCPSC                          Public Service Commission of South Carolina
SEC                            United States Securities and Exchange Commission
Section 29                     Section 29 of the Internal Revenue Service Code
SFAS                           Statement of Financial Accounting Standards
SFAS No. 5                     Statement of Financial Accounting Standards No. 5, "Accounting for
                               Contingencies"
SFAS No. 71                    Statement of Financial Accounting Standards No. 71, "Accounting for the
                               Effects of Certain Types of Regulation"
SFAS No. 87                    Statement of Financial Accounting Standards No. 87, "Employers' Accounting
                               for Pensions"
SFAS No. 121                   Statement of Financial Accounting Standards No. 121, "Accounting for the
                               Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
                               Of"
SFAS No. 123                   Statement of Financial Accounting Standards No. 123, "Accounting for
                               Stock-Based Compensation"
SFAS No. 133                   Statement of Financial Accounting Standards No. 133, "Accounting for
                               Derivative and Hedging Activities"
SFAS No. 138                   Statement of Financial Accounting Standards No. 138, "Accounting for
                               Certain Derivative Instruments and Certain Hedging Activities - an
                               Amendment of FASB Statement No. 133"
SFAS No. 142                   Statement of Financial Accounting Standards No. 142, "Goodwill and Other
                               Intangible Assets"

                                       5
<PAGE>

SFAS No. 143                   Statement of Financial Accounting Standards No. 143, "Accounting for Asset
                               Retirement Obligations"
SFAS No. 144                   Statement of Financial Accounting Standards No. 144, "Accounting for the
                               Impairment or Disposal of Long-Lived Assets"
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. 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
SO2                            Sulfur dioxide
SRS                            Strategic Resource Solutions Corp.
Tax Agreement                  Intercompany Income Tax Allocation Agreement
the Trust                      FPC Capital I
Westchester                    Westchester Gas Company
</TABLE>



                                       6
<PAGE>

                   SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

In addition, examples of forward-looking statements discussed in this Form 10-K,
include a) PART II, ITEM 7,  "Management's  Discussion and Analysis of Financial
Condition and Results of Operations"  including,  but not limited to, statements
under the  following  headings:  1)  "Liquidity  and  Capital  Resources"  about
operating cash flows,  estimated capital  requirements through the year 2006 and
future  financing plans 2) "Strategy"  about Progress  Energy's  strategy and 3)
"Other  Matters"  about the effects of new  environmental  regulations,  nuclear
decommissioning costs and the effect of electric utility industry restructuring,
and b) statements made in the "Risk Factors" sections.

Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy nor 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;  recurring seasonal  fluctuations
in demand for electricity;  fluctuations in the price of energy  commodities and
purchased power;  economic fluctuations and the corresponding impact on Progress
Energy,   Inc.  and  subsidiaries'  (the  Company)   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;
investment  performance  of pension and benefit plans and the ability to control
costs; the availability and use of Internal Revenue Code Section 29 (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  fuel  businesses;
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 manage the risks involved with the operation
of its nonregulated  plants,  including  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   operations;   and
unanticipated  changes in operating expenses and capital  expenditures.  Many of
these risks similarly impact the Company's subsidiaries.

These and other risk  factors are  detailed  from time to time in the  Company's
United States  Securities and Exchange  Commission (SEC) reports.  Many, but not
all of the factors  that may impact  actual  results are  discussed in the "Risk
Factors"  sections of this report.  You should carefully read the "Risk Factors"
sections of this  report.  All such factors are  difficult  to predict,  contain
uncertainties  that may  materially  affect actual results and may be beyond the
control of Progress Energy and 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.

                                       7

<PAGE>

PART I

ITEM 1.  BUSINESS

GENERAL

COMPANY

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

Effective  January  1,  2003,  CP&L,  Florida  Power  Corporation  and  Progress
Ventures,  Inc. began doing business under the names Progress Energy  Carolinas,
Inc. (PEC),  Progress Energy Florida,  Inc. (PEF) and Progress Energy  Ventures,
Inc. (Progress Ventures),  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  regulated subsidiaries PEC and PEF, Progress Energy is
primarily  engaged in the  generation,  transmission,  distribution  and sale of
electricity in portions of North Carolina,  South Carolina and Florida.  Through
its Competitive Commercial Operations (CCO) business segment, Progress Energy is
involved in nonregulated  electricity generation  operations.  Through its Fuels
business  segment  (Fuels),  Progress Energy is involved in natural gas drilling
and production,  coal terminal services, coal mining, synthetic fuel production,
fuel  transportation  and  delivery.  Both CCO and Fuels are involved in limited
energy  trading  activities.  Through its Rail Services  business  segment (Rail
Services), Progress Energy engages in various rail and railcar related services.
The Other Businesses  segment  primarily  includes  telecommunication  services,
miscellaneous  nonregulated  activities,  and holding  company  operations.  For
information  regarding  the  revenues,  income  and assets  attributable  to the
Company's business segments, see PART II, ITEM 8, Note 19 to the Progress Energy
Consolidated Financial Statements.

The Company has more than 24,000 megawatts (MW) of electric  generation capacity
and serves more than 2.8 million retail electric  customers in portions of North
Carolina,  South  Carolina and Florida.  PEC's and PEF's utility  operations are
complementary:  PEC has a summer peaking demand,  while PEF has a winter peaking
demand.  In addition,  PEC's greater  proportion of  commercial  and  industrial
customers  combined  with PEF's  greater  proportion  of  residential  customers
creates a balanced  customer  base.  The Company is dedicated  to expanding  the
region's electric  generation  capacity and delivering  reliable,  competitively
priced energy.

Progress  Energy revenues for the year ended December 31, 2003 were $8.7 billion
and assets at year-end were $26.2 billion.  Its principal  executive offices are
located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone
number (919) 546-6111.  The Progress Energy home page on the Internet is located
at  http://www.progress-energy.com,  the contents of which are not and shall not
be deemed a part of this  document  or any other U.S.  Securities  and  Exchange
Commission  (SEC)  filing.  The Company  makes  available  free of charge on its
website its annual report on Form 10-K,  quarterly reports on Form 10-Q, current
reports on Form 8-K and all  amendments  to those  reports as soon as reasonably
practicable after such material is electronically filed with or furnished to the
SEC.

SIGNIFICANT TRANSACTIONS

Progress Telecommunications Corporation Business Combination

In December 2003,  Progress  Telecommunications  Corporation  (PTC) and Caronet,
Inc.  (Caronet),  both  wholly-owned  subsidiaries of Progress Energy,  and EPIK
Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc.
(Odyssey), contributed substantially all of their assets and transferred certain
liabilities  to  Progress   Telecom,   LLC  (PTC  LLC),  a  subsidiary  of  PTC.
Subsequently,  the stock of Caronet was sold to an  affiliate  of Odyssey for $2
million  in cash  and  Caronet  became a  wholly-owned  subsidiary  of  Odyssey.
Following  consummation of all the transactions  described above, PTC holds a 55
percent  ownership  interest in, and is the parent of PTC LLC. See PART II, ITEM
8, Note 4A to the Progress Energy Consolidated Financial Statements.

                                       8
<PAGE>

Mesa Hydrocarbons, Inc. Divestiture

In October 2003, the Company sold certain gas-producing properties owned by Mesa
Hydrocarbons,  LLC, a  wholly-owned  subsidiary  of Progress  Fuels  Corporation
(Progress  Fuels),  which is  included  in the Fuels  segment.  Net  proceeds of
approximately $97 million were used to reduce debt. See PART II, ITEM 8, Note 3C
to the Progress Energy Consolidated Financial Statements.

NCNG Divestiture

On September 30, 2003, the Company  completed the sale of 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. As a
result of this  action,  the  operating  results  of NCNG were  reclassified  to
discontinued  operations for all reportable periods.  Net proceeds from the sale
of NCNG and ENCNG of  approximately  $450 million were used to reduce debt.  See
PART  II,  ITEM  8,  Note  3A to  the  Progress  Energy  Consolidated  Financial
Statements.

Natural Gas Reserves Acquisition

During 2003,  Progress Fuels entered into several  independent  transactions  to
acquire  approximately 200 natural  gas-producing  wells with proven reserves of
approximately 190 billion cubic feet (Bcf) from Republic Energy,  Inc. and three
other  privately-owned  companies,  all  headquartered  in Texas. The total cash
purchase price for the transactions was approximately $168 million. See PART II,
ITEM 8, Note 4B to the Progress Energy Consolidated Financial Statements.

Wholesale Energy Contract Acquisition

In May 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 Electric Membership  Corporation  (Jackson),  for $188 million. See PART
II, ITEM 8, Note 4C to the Progress Energy Consolidated Financial Statements.

Railcar Ltd. Divestiture

In December  2002, the Progress  Energy Board of Directors  adopted a resolution
approving  the sale of the  majority  of the assets of Railcar  Ltd.,  a leasing
subsidiary  included in the Rail Services  segment.  An estimated  impairment on
assets held for sale was recognized in December 2002 to write-down the assets to
fair value less the costs to sell.

In March  2003,  the Company  signed a letter of intent to sell the  majority of
Railcar Ltd.  assets to The  Andersons,  Inc. The asset  purchase  agreement was
signed in November  2003, and the  transaction  closed on February 12, 2004. Net
proceeds from the sale were approximately $82 million. See PART II, ITEM 8, Note
3B to the Progress Energy Consolidated Financial Statements.

Westchester Acquisition

In  April  2002,  Progress  Fuels  acquired  100%  of  Westchester  Gas  Company
(Westchester).  The acquisition included approximately 215 natural gas-producing
wells,  52 miles of  intrastate  gas  pipeline  and 170  miles of  gas-gathering
systems.  The aggregate purchase price was approximately $153 million.  See PART
II, ITEM 8, Note 4E to the Progress Energy Consolidated Financial Statements.

Generation Acquisition

In February  2002,  PVI  acquired  100% of two electric  generating  projects in
Georgia from LG&E Energy  Corp.,  a subsidiary of Powergen plc. for a total cash
purchase price of approximately $348 million.  The transaction  included tolling
agreements and two power purchase  agreements with LG&E Energy  Marketing,  Inc.
See PART II,  ITEM 8,  Note 4D to the  Progress  Energy  Consolidated  Financial
Statements.

                                       9
<PAGE>

COMPETITION

GENERAL

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

The 108th  Congress spent much of 2003 working on a  comprehensive  energy bill.
While  that  legislation  passed  the  House,  the  Senate  failed  to pass  the
legislation  in  2003.  There  will  probably  be an  effort  to  resurrect  the
legislation in 2004. The  legislation  would have further  clarified the Federal
Energy  Regulatory  Commission's  (FERC) role with  respect to  Standard  Market
Design and mandatory Regional  Transmission  Organizations (RTOs) and would have
repealed PUHCA. The Company cannot predict the outcome of this matter.

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

In  2000,   the  FERC  issued  Order  No.  2000  on  RTOs,   which  set  minimum
characteristics  and  eight  functions  for  transmission  entities,   including
independent system operators (ISOs) and transmission companies that are required
to become  FERC-approved  RTOs. The rule stated that public  utilities that own,
operate or control  interstate  transmission  facilities  had to have filed,  by
October  2000,  either a proposal  to  participate  in an RTO or an  alternative
filing describing efforts and plans to participate in an RTO. The order provided
guidance and specified minimum  characteristics and functions required of an RTO
and also stated that all RTOs should be operational by December 15, 2001. During
2001, the deadline for RTOs to be operational was extended.

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).  The proposed rules
set  forth  in the SMD NOPR  would  require,  among  other  things,  that 1) all
transmission-owning  utilities transfer control of their transmission facilities
to an  independent  third  party;  2)  transmission  service to  bundled  retail
customers be provided under the FERC-regulated  transmission tariff, rather than
state-mandated   terms  and   conditions;   3)  new  terms  and  conditions  for
transmission  service be adopted  nationwide,  including  provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities (LSEs) be required to meet minimum criteria for generating reserves. In
2003,  the FERC released a White Paper on the  Wholesale  Market  Platform.  The
White Paper  provides an overview of what the FERC 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.  The FERC has not yet
issued a final rule on SMD NOPR.

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

The developments  described above have created changing markets for energy. As a
strategy for  competing  in these  changing  markets,  the Company is becoming a
total energy provider in the region by providing a full array of  energy-related
services to its current  customers and  expanding its market reach.  The Company
took a major step towards  implementing this strategy through its acquisition of
Florida Progress Corporation (FPC) in November 2000.

Since passage of the EPA of 1992,  competition in the wholesale electric utility
industry  has  significantly   increased  due  to  a  greater  participation  by
traditional electricity suppliers, wholesale power marketers and brokers and due
to the trading of energy  futures  contracts on various  commodities  exchanges.
This increased competition could affect PEC and PEF's load forecasts,  plans for
power supply and wholesale energy sales and related  revenues.  The impact could

                                       10
<PAGE>

vary depending on the extent to which additional  generation is built to compete
in the wholesale market, new opportunities are created for PEC and PEF to expand
their  wholesale  load, or current  wholesale  customers  elect to purchase from
other suppliers after existing contracts expire.

An issue  encompassed  by industry  restructuring  is the  recovery of "stranded
costs."  Stranded costs  primarily  include the  generation  assets of utilities
whose value in a competitive  marketplace  would be less than their current book
value,  as  well as  above-market  purchased  power  commitments  to  qualifying
facilities  (QFs).   Thus  far,  all  states  that  have  passed   restructuring
legislation  have provided for the opportunity to recover a substantial  portion
of stranded costs. Assessing the amount of stranded costs for a utility requires
various  assumptions about future market conditions,  including the future price
of electricity.

In November 2003, the FERC adopted new standards of conduct that apply uniformly
to interstate  natural gas pipelines and public utilities.  The new standards of
conduct govern the relationship between transmission  providers and their energy
affiliates in a manner that prevents  market power and  preferential  treatment.
Each utility was required to submit a plan and schedule for compliance  with the
new rules by February  2004.  All utilities  must be in compliance  with the new
rules no later  than  June  2004.  PEC and PEF have  submitted  their  plans and
schedules for timely compliance.

See  PART  I,  ITEM  1,  "Competition"  of  Electric-PEC  and  Electric-PEF  for
discussions of franchises as they relate to PEC and PEF.

See PART I, ITEM 1, "Competition,"  under  Electric-PEC,  Electric-PEF and Other
for further discussion of competitive developments within these segments.

PUHCA

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

While various proposals, including the 2003 energy bill, have been introduced in
Congress  regarding  PUHCA,  the prospects for legislative  reform or repeal are
uncertain at this time.

REGULATORY MATTERS

GENERAL

PEC and PEF are subject to  regulation in North  Carolina by the North  Carolina
Utilities  Commission (NCUC), in South Carolina by the Public Service Commission
of  South  Carolina  (SCPSC)  and in  Florida  by  the  Florida  Public  Service
Commission  (FPSC) with  respect to, among other  things,  rates and service for
electric  energy sold at retail,  retail  service  territory  and  issuances  of
securities.  In addition, PEC and PEF are subject to regulation by the FERC with
respect to  transmission  and sales of wholesale  power,  accounting and certain
other matters. The underlying concept of utility ratemaking is to set rates at a
level that allows the utility to collect revenues equal to its cost of providing
service  including  a  reasonable  rate  of  return  on  its  equity.  Increased
competition  as a result of  industry  restructuring  may affect the  ratemaking
process.

NUCLEAR MATTERS

GENERAL

PEC owns and operates  four nuclear  units and PEF owns and operates one nuclear
generating  unit which are  regulated by the United  States  Nuclear  Regulatory
Commission   (NRC)  under  the  Atomic   Energy  Act  of  1954  and  the  Energy
Reorganization  Act of  1974.  In the  event of  noncompliance,  the NRC has the
authority to impose fines, set license conditions,  shut down a nuclear unit, or
some combination of these,  depending upon its assessment of the severity of the
situation,  until  compliance is achieved.  The nuclear  units are  periodically
removed from service to accommodate  normal  refueling and maintenance  outages,
repairs and certain other modifications.

                                       11
<PAGE>

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

NRC operating  licenses  held by PEC currently  expire in July 2010 for Robinson
Unit No. 2, in December  2014 and September  2016 for  Brunswick  Units 2 and 1,
respectively  and in October 2026 for the Shearon  Harris  Nuclear Plant (Harris
Plant).  An application to extend the Robinson license 20 years was submitted in
June 2002 and a similar  application  is expected  to be made for the  Brunswick
Plant in December  2004 and for the Harris  Plant in 2006.  According to the NRC
schedule,  the Company expects to receive the new license extension for Robinson
in April 2004. A condition of the  operating  license for each unit  requires an
approved plan for decontamination and decommissioning.

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

PEF has a  license  to  operate  its  Crystal  River  Unit No.  3 (CR3)  nuclear
generating  plant through  December 3, 2016. On February 20, 2003,  PEF notified
the NRC of its intent to submit an  application  to extend the plant  license in
the first quarter of 2009.

PRESSURIZED WATER REACTORS

In 2002, the NRC sent a bulletin to companies that hold licenses for pressurized
water reactors (PWRs) requiring  information on the structural  integrity of the
reactor  vessel  head and a basis  for  concluding  that the  vessel  head  will
continue to perform its function as a coolant pressure boundary.  Inspections of
the vessel heads at the Company's PWR plants had been performed  during previous
outages.  At the Robinson and Harris Plants,  inspections were completed in 2001
and  there  was no  degradation  of the  reactor  vessel  heads.  The  Company's
Brunswick  Plant  has a  different  design  and is not  affected  by the  issue.
Inspection of the vessel head at CR3 was performed  during a previous outage and
no degradation of the reactor vessel head was identified.

In 2002, the NRC issued an additional  bulletin dealing with head leakage due to
cracks  near the  control  rod  nozzles,  asking  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 2002.  The
Company  completed  a  series  of  examinations  in 2002 of the  entire  reactor
pressure  vessel head and found no  indications  of control rod drive  mechanism
cracking and no corrosion of the head itself.  During the outage,  a 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 2004 and  replace  the head in 2005.  The
Harris Plant is ranked in the lowest susceptibility classification. PEF replaced
the vessel head at CR3 during its regularly scheduled refueling outage in 2003.

In 2003, the NRC issued an order requiring  specific  inspections of the reactor
pressure  vessel head and  associated  penetration  nozzles at PWRs. The Company
responded,  stating that it intended to comply with the provisions of the Order.
No adverse impact is anticipated.  The NRC also issued a bulletin requesting PWR
licensees to address  inspection  plans for reactor  pressure  vessel lower head
penetrations.  The Company  plans to perform  bare metal visual  inspections  of
Robinson  during the next  regularly  scheduled  refueling  outages in 2004. The
Company  completed a bare metal visual inspection of the vessel bottom at Harris
and CR3 during  their 2003 outages and found no signs of corrosion or leakage at
either unit.  The Company plans to do additional,  more detailed  inspections as
part of the next scheduled 10-year in-service inspections.

In February 2004, the NRC issued a revised Order for inspection requirements for
reactor  pressure  vessel  heads at  PWRs.  The  Company  is in the  process  of
reviewing the Order. No adverse impact is anticipated.

                                       12

<PAGE>

SECURITY

The NRC has issued various  orders since  September 2001 with regard to security
at nuclear  plants.  These orders  include  additional  restrictions  on access,
increased security measures and closer  coordination with the Company's partners
in  intelligence,  military,  law  enforcement  and  emergency  response  at the
federal,  state and local levels.  The Company is completing the requirements as
outlined  in the  orders  by  the  established  deadlines.  As  the  NRC,  other
governmental  entities and the industry continue to consider security issues, it
is possible that more extensive security plans could be required.

SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE

The Nuclear Waste Policy Act of 1982 (Nuclear  Waste Act) provides the framework
for  development  by the federal  government  of interim  storage and  permanent
disposal  facilities for high-level  radioactive  waste  materials.  The Nuclear
Waste Act promotes  increased  usage of interim storage of spent nuclear fuel at
existing nuclear plants.  The Company will continue to maximize the use of spent
fuel storage capability within its own facilities for as long as feasible.  With
certain   modifications  and  additional  approval  by  the  NRC  including  the
installation  of onsite dry storage  facilities at Robinson (2005) and Brunswick
(2008),  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.  PEF  currently is storing spent nuclear fuel onsite in spent fuel pools.
PEF will seek  renewal  of the CR3  operating  license  and  currently,  CR3 has
sufficient  storage  capacity in place for fuel consumed  through the end of the
expiration of the current  license in 2016. If PEF receives  approval of the CR3
operating  license renewal,  dry storage may be necessary.  See PART II, ITEM 8,
Note 21E to the Progress Energy Consolidated  Financial  Statements and Note 16D
to the PEC Consolidated  Financial  Statements for a discussion of the Company's
contract with the U.S. Department of Energy (DOE) for spent nuclear waste.

DECOMMISSIONING

In PEC's and PEF's retail jurisdictions,  provisions for nuclear decommissioning
costs  are  approved  by the  NCUC,  the  SCPSC  and the FPSC  and are  based on
site-specific  estimates  that include the costs for removal of all  radioactive
and other structures at the site. In the wholesale jurisdiction,  the provisions
for nuclear decommissioning costs are approved by the FERC. See PART II, ITEM 8,
Note 5D to the Progress Energy Consolidated  Financial Statements and Note 3D to
the PEC  Consolidated  Financial  Statements  for a discussion  of PEC and PEF's
nuclear decommissioning costs.

ENVIRONMENTAL

GENERAL

In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and local authorities. The
Company considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and operations
and believes it has all necessary permits to conduct such operations.
Environmental laws and regulations constantly evolve and the ultimate costs of
compliance cannot always be accurately estimated. The estimated capital costs
associated with compliance with pollution control laws and regulations at the
Company's existing fossil facilities that the Company expects to incur from 2004
through 2006 are included in the "Investing Activities" discussion under PART
II, ITEM 7, "Liquidity and Capital Resources".

AIR QUALITY

Amendments to the Federal Clean Air Act require substantial reductions in sulfur
dioxide (SO2) and nitrogen  oxide (NOx)  emissions from  fossil-fueled  electric
generating  plants.  The  Company  meets  the  SO2  emissions   requirements  by
maintaining  sufficient  SO2 emission  allowances.  Installation  of  additional
equipment  was  necessary  to reduce  NOx  emissions.  Increased  operation  and
maintenance  costs,  including  emission  allowance  expense,   installation  of
additional   equipment  and  increased  fuel  costs  are  not  material  to  the
consolidated financial position or results of operations of the Company.

                                       13
<PAGE>

There  has  been  and may be  further  proposed  federal  legislation  requiring
reductions in air emissions for NOx, SO2,  carbon  dioxide and mercury.  Some of
these  proposals  establish  nationwide caps and emission rates over an extended
period of time. This national  multi-emission  approach to air pollution control
could involve significant capital costs which could be material to the Company's
financial  operations.  Some  companies  may seek  recovery of the related costs
through rate adjustments or similar  mechanisms.  Control equipment that will be
installed on North Carolina  fossil  generating  facilities as part of the North
Carolina  law  discussed  below may address some of the issues  outlined  above.
However, the Company cannot predict the outcome of this matter.

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

In 2003, the EPA published a final rule addressing routine equipment replacement
under  the New  Source  Review  program.  The  rule  defines  routine  equipment
replacement  and the types of  activities  that are not  subject  to New  Source
Review requirements or New Source Performance Standards under the Clean Air Act.
The rule was challenged in federal court and its implementation has been stayed.
The Company cannot predict the outcome of this matter.

In 1998,  the EPA  published  a final rule at  Section  110 of the Clean Air Act
addressing  the issue of regional  transport of ozone (NOx SIP Call).  The EPA's
rule requires 23  jurisdictions,  including North  Carolina,  South Carolina and
Georgia,  but not Florida,  to further reduce NOx emissions in order to attain a
pre-set state  emission level during each year's "ozone  season,"  beginning May
31, 2004. PEC is currently installing controls necessary to comply with the rule
and  expects  to be in  compliance  as  required  by  the  final  rule.  Capital
expenditures  to meet these  measures in North Carolina and South Carolina could
reach approximately $370 million, which has not been adjusted for inflation. The
Company  has  spent   approximately  $258  million  to  date  related  to  these
expenditures.  Increased operation and maintenance costs relating to the NOx SIP
Call are not expected to be material to the Company's results of operations. 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 NOx emissions by May 1, 2003. The final rule also includes a
set of  regulations  that  affect NOx  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.  In April 2002, the EPA published a final rule  harmonizing the dates
for the Section 126 rule and the NOx SIP Call. The new  compliance  date for all
affected  sources is now May 31,  2004,  rather  than May 1,  2003.  The EPA has
approved  North  Carolina's  NOx SIP Call rule and has indicated it will rescind
the Section 126 rule in a future rulemaking.

In June 2002,  legislation  was enacted in North Carolina  requiring the state's
electric  utilities to reduce the emissions of NOx and SO2 from coal-fired power
plants.  Operation and  maintenance  costs will  increase due to the  additional
personnel,  materials and general  maintenance  associated  with the  equipment.
Operation and maintenance  expenses are recoverable  through base rates,  rather
than as part of this program.  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.  See PART II, ITEM 8, Note 21E to the
Progress Energy Consolidated  Financial  Statements and Note 16D to the Progress
Energy Carolinas Consolidated Financial Statements for further discussion.

                                       14
<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.  In December
2003, the EPA proposed and solicited  comment on two  alternative  control plans
that would limit mercury emissions from coal-fired power plants.  The agency has
indicated that it will choose one of the  alternatives as the final rule,  which
is expected to be promulgated in December 2004. Achieving compliance with either
proposal could involve significant capital costs. The Company cannot predict the
outcome of this matter.

In  conjunction  with the  proposed  mercury  rule,  the EPA  proposed a Maximum
Achievable  Control Technology (MACT) standard to regulate nickel emissions from
residual oil-fired units. The agency estimates the proposal will reduce national
nickel emissions to approximately 103 tons. The rule is expected to become final
in December 2004. The company cannot predict the outcome of this matter.

In December  2003,  the EPA released its  proposed  Interstate  Air Quality Rule
(commonly  known as the Fine  Particulate  Transport  Rule  and/or the  Regional
Transport Rule). The EPA's proposal requires 28  jurisdictions,  including North
Carolina,  South  Carolina,  Georgia and Florida,  to further reduce NOx and SO2
emissions in order to attain  pre-set state NOx and SO2 emissions  levels (which
have not yet been determined). The rule is expected to become final in 2004. The
installation  of  controls  necessary  to  comply  with the rule  could  involve
significant  capital  costs.  The  Company  cannot  predict  the outcome of this
matter.

WATER QUALITY

As a result of the operation of certain control  equipment needed to address the
air quality issues  outlined  above,  new  wastewater  streams may be generated.
Integration of these new wastewater streams into existing  wastewater  treatment
processes may result in permitting,  construction and water treatment challenges
to the Company in the immediate and extended future.

After many years of litigation  and  settlement  negotiations  the EPA published
final  regulations in February 2004 for the  implementation of Section 316(b) of
the Clean Water Act. The purpose of these regulations is to minimize any adverse
environmental  impact  caused by  cooling  water  intake  structures  and intake
systems  located at  existing  facilities.  Over the next  several  years  these
regulations  may  require  the  facilities  to  mitigate  the effects to aquatic
organisms by undertaking intake  modifications or other restorative  activities.
Substantial  costs could be incurred by the  facilities  in order to comply with
the new  regulations.  The Company cannot predict the outcome and impacts to the
facilities at this time or its cost to comply with any new regulations.

SUPERFUND

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

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

                                       15
<PAGE>

Both electric utilities,  Progress Fuels and Progress Rail Services  Corporation
(Progress  Rail) are  periodically  notified by  regulators  such as the EPA and
various state agencies of their  involvement or potential  involvement in sites,
other  than  MGP  sites,  that may  require  investigation  and/or  remediation.
Although  the  Company's  subsidiaries  may incur costs at the sites about which
they have been  notified,  based upon the  current  status of these  sites,  the
Company cannot predict the outcome of this matter.

EMPLOYEES

As  of  January  31,  2004,  Progress  Energy  and  its  subsidiaries   employed
approximately  15,300 full-time  employees.  Of this total,  approximately 2,200
employees at PEF are represented by the International  Brotherhood of Electrical
Workers  (IBEW).  PEF and the IBEW reached  agreement in December  2002 on a new
three-year labor contract.

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

As of January 31, 2004, PEC employed approximately 5,200 full-time employees.

ELECTRIC - PEC

GENERAL

PEC is a public service  corporation  formed under the laws of North Carolina in
1926, and is primarily engaged in the generation, transmission, distribution and
sale of  electricity  in portions of North and South  Carolina.  At December 31,
2003,  PEC had a  total  summer  generating  capacity  (including  jointly-owned
capacity) of approximately 12,416 MW.

PEC  distributes  and  sells  electricity  in 56 of the 100  counties  in  North
Carolina and 15 counties in northeastern South Carolina. The territory served is
an area of approximately 34,000 square miles, including a substantial portion of
the coastal plain of North Carolina  extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont section of North
Carolina,  an area in  northeastern  South Carolina and an area in western North
Carolina in and around the city of Asheville.  The estimated total population of
the  territory  served is more than 4.0 million.  At December 31, 2003,  PEC was
providing electric services,  retail and wholesale, to approximately 1.3 million
customers.  Major wholesale power sales customers include North Carolina Eastern
Municipal  Power Agency (Power  Agency) and North Carolina  Electric  Membership
Corporation.  PEC is subject to the rules and  regulations of the FERC, the NCUC
and the SCPSC.

BILLED ELECTRIC REVENUES

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

                   BILLED ELECTRIC REVENUES

      Revenue Class            2003           2002            2001
      -------------            ----           ----            ----
      Residential               35%            35%             34%
      Commercial                24%            24%             23%
      Industrial                18%            18%             19%
      Wholesale                 19%            19%             19%
      Other retail               4%             4%              5%

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

                                       16
<PAGE>

FUEL AND PURCHASED POWER

Sources of Generation

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

                            ENERGY MIX PERCENTAGES

                                2003        2002        2001
                                ----        ----        ----
         Coal                    46%         46%         49%
         Nuclear                 44%         42%         41%
         Hydro                    1%          1%          0%
         Oil/Gas                  2%          3%          2%
         Purchased power          7%          8%          8%

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

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

                                AVERAGE FUEL COST
                                (per million Btu)

                                  2003        2002        2001
                                  ----        ----        ----
         Coal                   $ 2.00      $ 1.93      $ 1.78
         Nuclear                  0.43        0.43        0.44
         Hydro                     -            -           -
         Oil                      6.69        5.48        6.38
         Gas                      8.32        5.31        4.69
         Weighted-average         1.43        1.38        1.26

Changes in the unit price for oil and gas are due to market conditions.  Changes
in the  unit  price  for  coal  between  2001  and  2002  are  primarily  due to
transportation  costs.  Changes in the unit price for coal between 2002 and 2003
are being  driven by increases  in market  prices for coal in 2003.  Since these
costs  are  primarily   recovered   through  recovery  clauses   established  by
regulators, fluctuations do not materially affect net income.

Coal

PEC anticipates a requirement of approximately 11.3 million to 11.6 million tons
of coal in 2004.  Almost all of the coal will be supplied from  Appalachian coal
sources in the United States and is primarily delivered by rail.

For 2004, PEC has short-term, intermediate and long-term agreements from various
sources for approximately 83% of its burn requirements of its coal units. Two of
these contracts are index priced and the remainder are annually fixed price. The
contracts have expiration  dates ranging from 2004 to 2008. PEC will continue to
sign contracts of various  lengths,  terms and quality to meet its expected burn
requirements.  All of the coal that PEC has  purchased  under  intermediate  and
long-term agreements is considered to be low sulfur coal by industry standards.

Nuclear

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

                                       17
<PAGE>

PEC has sufficient uranium, conversion,  enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement  needs. PEC typically  contracts for
all of its enrichment  services and  fabrication  needs with contract  durations
ranging  from five to ten  years.  Recent  shutdown  of a major  North  American
conversion  facility and increased  uncertainty of uranium supply has raised the
risk of supply disruption. As a result, Progress Energy has adjusted its nuclear
fuel inventory and procurement  strategy  accordingly to offset increased supply
disruption  risk  by  increasing  planned  delivery  lead  times  and  strategic
inventory stockpiles. For a discussion of PEC's plans with respect to spent fuel
storage, see PART I, ITEM 1, "Nuclear Matters."

Hydroelectric

Hydroelectric  power is electric energy generated by the force of falling water.
PEC has three  hydroelectric  generating  plants licensed by the FERC:  Walters,
Tillery  and  Blewett.  PEC also  owns the  Marshall  Plant  which has a license
exemption.  The total maximum dependable capacity for these units is 218 MW. PEC
is seeking to relicense its Tillery and Blewett Plants.  These plants'  licenses
currently expire in April 2008. The Walters Plant license will expire in 2034.

Oil & Gas

Natural gas and oil supply for PEC's  generation  fleet is purchased  under term
and spot  contracts  from  several  suppliers.  The cost of PEC's oil and gas is
determined by market prices as reported in certain  industry  publications.  PEC
believes  that it has  access to an  adequate  supply of oil for the  reasonably
foreseeable  future.  PEC's natural gas  transportation  is purchased under term
firm  transportation  contracts with  interstate  pipelines.  PEC also purchases
capacity  on a seasonal  basis  from  numerous  shippers  for its  peaking  load
requirements.  PEC believes  that existing  contracts for oil are  sufficient to
cover its  requirements  if natural gas is  unavailable  during a normal  winter
period for PEC's combustion turbine and combined cycle fleet.

Purchased Power

PEC purchased  approximately 4.5 million MWh in 2003,  approximately 5.2 million
MWh in 2002 and  approximately  5.3  million  MWh in 2001 of its  system  energy
requirements  and had available 1,810 MW in 2003,  1,737 MW in 2002 and 1,756 MW
in 2001 of firm purchased  capacity under contract at the time of peak load. PEC
may acquire  purchased  power capacity in the future to accommodate a portion of
its system load needs.

COMPETITION

Electric Industry Restructuring

PEC continues to monitor any  developments  that occur toward a more competitive
environment and has actively  participated in regulatory reform deliberations in
North Carolina and South Carolina.  PEC expects that both the North Carolina and
South Carolina  General  Assemblies  will continue to monitor the experiences of
states that have implemented electric restructuring legislation.

Regional Transmission Organizations

In  October  2000,  as a result of Order  2000,  PEC,  along  with  Duke  Energy
Corporation and South Carolina Electric & Gas Company, filed an application with
the FERC for approval of a GridSouth RTO. In July 2001, the FERC issued an order
provisionally approving GridSouth. However, in July 2001, the FERC issued orders
recommending  that companies in the southeast engage in a mediation to develop a
plan for a single RTO for the Southeast.  PEC participated in the mediation. The
FERC has not issued an order specifically on this mediation.

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

Standard Market Design

See PART I, ITEM 1,  "General,"  under  Competition  for further  discussion  of
Standard Market Design developments.

                                       18
<PAGE>

Franchises

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

Wholesale Competition

See PART I, ITEM 1, "General,"  under  Competition for a discussion of wholesale
competition.

Stranded Costs

See PART I, ITEM 1,  "General,"  under  Competition for a discussion of stranded
costs.

REGULATORY MATTERS

Retail Rate Matters

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

Legislation  enacted in North  Carolina in 2002 freezes  PEC's base retail rates
for five years unless there are extraordinary  events beyond the control of PEC,
in which case PEC can  petition for a rate  increase.  See PART II, ITEM 8, Note
21E to the Progress Energy Consolidated Financial Statements and Note 16D to the
PEC  Consolidated  Financial  Statements  for further  discussion  of PEC's rate
freeze.

See PART II,  ITEM 8,  Note 7B to the  Progress  Energy  Consolidated  Financial
Statements and Note 5B to the PEC Consolidated  Financial Statements for further
discussion of PEC's retail rate developments during 2003.

Wholesale Rate Matters

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

Fuel Cost Recovery

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

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

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

                                       19
<PAGE>

NUCLEAR MATTERS

PEC is currently implementing power uprate projects at its nuclear facilities to
increase  electrical  generation  output.  A power  uprate was  completed at the
Harris  Plant  during  2001 and at the  Robinson  Nuclear  Plant in 2002.  Power
uprates are also in progress at the Brunswick Plant.  Brunswick Unit 1 increased
its capacity by 52 MW in 2002 and Brunswick 2 increased its capacity by 89 MW in
2003. Additional increases will be implemented in phases over the next couple of
years. The total increased generation from all these projects is estimated to be
approximately  290 MW.  See  PART I,  ITEM 1,  "Nuclear  Matters,"  for  further
discussion of these and other nuclear matters.

ENVIRONMENTAL MATTERS

There are nine  former MGP sites and other sites  associated  with PEC that have
required or are anticipated to require  investigation  and/or remediation costs.
In September 2003, the Company sold NCNG to Piedmont  Natural Gas Company,  Inc.
As part of the sales agreement, the Company retained responsibility to remediate
five former  NCNG MGP sites to state  standards  pursuant  to an  Administrative
Order by consent. At the time of the sale, the liability for these costs and the
related  accrual was  transferred to PEC.  Presently,  PEC cannot  determine the
total costs that may be incurred in connection  with the  remediation  of any of
these  MGP  sites.  See  PART  II,  ITEM  8,  Note  21E to the  Progress  Energy
Consolidated Financial Statements and Note 16D to the PEC Consolidated Financial
Statements for further discussion of these environmental matters.

ELECTRIC - PEF

GENERAL

PEF was  incorporated  in Florida in 1899,  and is an operating  public  utility
engaged in the  generation,  purchase,  transmission,  distribution  and sale of
electricity.  At December 31, 2003, PEF had a total summer  generating  capacity
(including jointly-owned capacity) of approximately 8,544 MW.

PEF provided electric service during 2003 to an average of 1.5 million customers
in west central  Florida.  Its service area covers  approximately  20,000 square
miles and includes the densely  populated areas around  Orlando,  as well as the
cities of St. Petersburg and Clearwater. PEF is interconnected with 20 municipal
and nine  rural  electric  cooperative  systems.  Major  wholesale  power  sales
customers include Seminole Electric  Cooperative,  Inc., Florida Municipal Power
Agency, Florida Power & Light Company and Tampa Electric Company. PEF is subject
to the rules and regulations of the FERC and the FPSC.

BILLED ELECTRIC REVENUES

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

                            BILLED ELECTRIC REVENUES

       Revenue Class              2003           2002            2001
       -------------              ----           ----            ----
       Residential                 55%            55%             54%
       Commercial                  24%            24%             24%
       Industrial                   7%             7%              7%
       Others                       6%             6%              6%
       Wholesale                    8%             8%              9%

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

                                       20
<PAGE>

FUEL AND PURCHASED POWER

General

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

                             ENERGY MIX PERCENTAGES

       Fuel Type                   2003         2002          2001
       ---------                   ----         ----          ----
       Coal (a)                     36%          33%           33%
       Oil                          16%          16%           16%
       Nuclear                      14%          15%           15%
       Gas                          13%          15%           14%
       Purchased Power              21%          21%           22%

(a) Amounts  include  synthetic fuel from unrelated  third parties and petroleum
coke.

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

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

                                AVERAGE FUEL COST
                                (per million Btu)

                                       2003           2002            2001
                                     ------         ------          ------
       Coal (a)                      $ 2.42         $ 2.43          $ 2.16
       Oil                             4.38           3.77            3.81
       Nuclear                         0.50           0.46            0.47
       Gas                             5.98           4.06            4.52
       Weighted-average                3.07           2.60            2.59

(a) Amounts  include  synthetic fuel from unrelated  third parties and petroleum
coke.

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

Coal

PEF  anticipates  a combined  requirement  of  approximately  6.0 million to 6.5
million tons of coal in 2004.  Most of the coal is expected to be supplied  from
Appalachian coal sources in the United States.  Approximately  two-thirds of the
fuel is expected to be delivered by rail and the remainder by barge. All of this
fuel is supplied by Progress Fuels, a subsidiary of Progress Energy, pursuant to
contracts between PEF and Progress Fuels.

For 2004,  Progress Fuels has medium-term  and long-term  contracts with various
sources for  approximately  100% of the burn  requirements  of PEF's coal units.
These  contracts  have price  adjustment  provisions and have  expiration  dates
ranging from 2004 to 2006.  Progress  Fuels will  continue to sign  contracts of
various lengths, terms and quality to meet PEF's expected burn requirements. All
the coal to be purchased for PEF is considered to be low sulfur coal by industry
standards.

Oil and Gas

Natural gas and oil supply for PEF's  generation  fleet is purchased  under term
and spot contracts from several suppliers. The majority of the cost of PEF's oil
and  gas is  determined  by  market  prices  as  reported  in  certain  industry
publications.  PEF believes that it has access to an adequate  supply of oil for
the reasonably foreseeable future. PEF's natural gas transportation is purchased
under term firm  transportation  contracts with interstate  pipelines.  PEF also
purchases  capacity on a seasonal  basis from numerous  shippers and  interstate

                                       21
<PAGE>

pipelines to serve its peaking load  requirements.  PEF also uses  interruptible
transportation  contracts on certain occasions when available. PEF believes that
existing  contracts for oil are sufficient to cover its  requirements if natural
gas is unavailable during certain time periods.

Nuclear

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

PEF has sufficient uranium, conversion,  enrichment and fabrication contracts to
meet its near-term nuclear fuel requirements  needs. PEF typically contracts for
all of its future  long-term  uranium,  conversion and enrichment  service needs
with contract  durations  ranging from five to ten years.  Recent  shutdown of a
major North American  conversion  facility and increased  uncertainty of uranium
supply has raised the risk of supply  disruption.  As a result,  Progress Energy
has adjusted its nuclear fuel inventory and procurement  strategy accordingly to
offset  increased  supply  disruption risk by increasing  planned  delivery lead
times and strategic inventory stockpiles.

Purchased Power

PEF, along with other Florida  utilities,  buys and sells power in the wholesale
market on a short-term  and  long-term  basis.  At December 31, 2003,  PEF had a
variety of purchase power agreements for the purchase of approximately  1,313 MW
of firm power. These agreements include (1) long-term contracts for the purchase
of  about  474  MW of  purchased  power  with  other  investor-owned  utilities,
including a contract with The Southern  Company for  approximately  414 MWs, and
(2)  approximately  839 MWs of capacity  under  contract  with  certain QFs. The
capacity  currently  available  from QFs  represents  about  10% of PEF's  total
installed system capacity.

COMPETITION

Electric Industry Restructuring

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

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

Regional Transmission Organizations

As a result of Order 2000,  PEF,  along with Florida  Power & Light  Company and
Tampa Electric Company (the  Applicants)  filed with the FERC in October 2000 an
application  for  approval of a  GridFlorida  RTO. The  GridFlorida  proposal is
pending before both the FERC and the FPSC. The FERC  provisionally  approved the
structure and governance of GridFlorida.  The Commission's  most recent order in
December 2003 ordered further state proceedings.  It is unknown when the FERC or
the FPSC will take final action with regard to the status of GridFlorida or what
the impact of further proceedings will have on the Company's earnings,  revenues
or pricing.  See PART II, ITEM 7, "Other  Matters,"  for a discussion of current
developments of GridFlorida RTO.

Standard Market Design

See PART I, ITEM 1,  "General,"  under  Competition  for further  discussion  of
standard market design developments.

                                       22
<PAGE>

Franchise Agreements

PEF holds franchises with varying  expiration dates in 107 of the municipalities
in which it distributes electric energy. PEF also serves 14 other municipalities
and in all its unincorporated  areas without franchise  agreements.  The general
effect of these  franchises  is to provide for the manner in which PEF  occupies
rights-of-way  in  incorporated  areas  of  municipalities  for the  purpose  of
constructing,  operating and maintaining an energy transmission and distribution
system.

Approximately  44% of  PEF's  total  utility  revenues  for 2003  were  from the
incorporated  areas  of the 107  municipalities  that had  franchise  ordinances
during the year. Since 2000, PEF has renewed 32 expiring  franchises and reached
agreement on a franchise with a city that did not  previously  have a franchise.
Franchises with five municipalities have expired without renewal.

All but 26 of the  existing  franchises  cover a  30-year  period  from the date
enacted.  The  exceptions  are 22  franchises,  each with a term of 10 years and
expiring  between 2005 and 2012; two franchises each with a term of 15 years and
expiring in 2017; one 30-year franchise that was extended in 1999 for five years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 107 franchises,  36 expire between January 1, 2004 and December 31, 2012 and
71 expire between January 1, 2013 and December 31, 2034.

Ongoing  negotiations  and,  in some  cases,  litigation  are taking  place with
certain  municipalities  to reach  agreement on franchise terms and to enact new
franchise ordinances.  See PART II, ITEM 7, "Other Matters," for a discussion of
PEF's franchise litigation.

Stranded Costs

The largest  stranded  cost  exposure for PEF is its  commitment to QFs. PEF has
taken a proactive approach to this industry issue. PEF continues to seek ways to
address the impact of  escalating  payments  from  contracts it was obligated to
sign under provisions of PURPA. See PART I, ITEM 1, "General," under Competition
for further discussion.

Wholesale Competition

See PART I, ITEM 1, "General,"  under  Competition for a discussion of wholesale
competition.

REGULATORY MATTERS

General

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

Retail Rate Matters

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

In March 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 and is generally  effective  from May 1, 2002
through  December 31, 2005. The Agreement  eliminates  the authorized  Return on
Equity  (ROE)  range  normally  used by the FPSC for the  purpose of  addressing
earning levels; provided, however, that if PEF's base rate earnings fall below a
10% return on equity,  PEF may  petition  the FPSC to amend its base rates.  The
Agreement  is  described  in more  detail  in PART  II,  ITEM 8,  Note 7D to the
Progress Energy Consolidated Financial Statements.

                                       23
<PAGE>

Fuel and Other Cost Recovery

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

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

NUCLEAR MATTERS

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

See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other
nuclear matters.

ENVIRONMENTAL MATTERS

There are two former  MGP sites and other  sites  associated  with PEF that have
required or are anticipated to require  investigation  and/or remediation costs.
In addition,  there are distribution substations and transformers which are also
anticipated to incur investigation and remediation costs. Presently,  PEF cannot
determine  the  total  costs  that  may  be  included  in  connection  with  the
remediation of all sites.  See PART II, ITEM 8, Note 21E to the Progress  Energy
Consolidated  Financial Statements for further discussion of these environmental
matters.

FUELS

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

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

     o    Natural gas properties in Texas and Louisiana  producing  about 30 Bcf
          per year;
     o    Five  terminals  on the Ohio  River and its  tributaries,  part of the
          trucking, rail and barge network for coal delivery;
     o    Three coal-mining complexes,  expected to produce about 3 million tons
          per year:
     o    Five wholly-owned synthetic fuel entities, and a 10% minority interest
          in one  synthetic  fuel entity,  capable of producing up to 18 million
          tons per year;
     o    Majority-ownership  in a barge  partnership  that moves coal  products
          from  the  mouth  of the  Mississippi  River  to the CR3  facility  in
          Florida.

During 2003,  Progress Fuels acquired  approximately  200 natural  gas-producing
wells with proven reserves of approximately  190 Bcf from Republic Energy,  Inc.
and three other privately-owned companies, all headquartered in Texas. The total
cash purchase price for the transactions  was  approximately  $168 million.  See
PART  II,  ITEM  8,  Note  4B to  the  Progress  Energy  Consolidated  Financial
Statements.

                                       24
<PAGE>

COMPETITION

Fuels'  synthetic  fuel  operations and coal  operations  compete in the eastern
United States  industrial coal markets.  Factors  contributing to the success in
these markets  include a  competitive  cost  structure and strategic  locations.
There are, however,  numerous competitors in each of these markets,  although no
one competitor is dominant in any industry.

Fuels' gas  production  operations  compete in the East  Texas,  North Texas and
North Louisiana  region.  Factors  contributing to success include a competitive
cost structure.  Although there are numerous small,  independent  competitors in
this market, the major oil and gas producers dominate this industry.

ENVIRONMENTAL MATTERS

See PART II,  ITEM 8, Note 21E to the  Progress  Energy  Consolidated  Financial
Statements for a discussion of Fuel's environmental matters.

COMPETITIVE COMMERCIAL OPERATIONS (CCO)

CCO sells  capacity  and energy on the  wholesale  market  outside  the realm of
retail regulation.  CCO currently owns six plants with approximately 3,100 MW of
generation  capacity.  CCO has contracts  representing 85% of planned production
capacity for 2004 and 50% of planned production capacity for 2005 and 2006.

In May 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, for $188 million.

CCO is responsible for marketing the energy produced by the nonregulated plants.
The energy is sold under both term contracts and in the spot market. CCO markets
the  nonregulated  plants not under  contract into the  nonregulated  market and
engages in limited financial trading  activities  primarily for hedging the fuel
and economic  value of its generation  portfolio.  CCO is also  responsible  for
purchasing fuel for the merchant  generation fleet, such as natural gas and oil.
CCO also  uses  financial  instruments  to  manage  the  risks  associated  with
fluctuating  commodity  prices and  increase  the value of the  Company's  power
generation assets.

COMPETITION

CCO does not operate in the same environment as regulated utilities. It operates
specifically  in the wholesale  market,  which means  competition is its primary
driver.  CCO competes in the eastern  United  States  utility  markets.  Factors
contributing  to the  success  in  these  markets  include  a  competitive  cost
structure and strategic locations.

RAIL SERVICES

The Rail Services business segment,  led by Progress Rail, is one of the largest
integrated and diversified suppliers of railroad and transit system products and
services in North America and is  headquartered  in Albertville,  Alabama.  Rail
Services'  principal business  functions include two business units:  Locomotive
and Railcar Services (LRS) and Engineering and Trackwork (E&TW).

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

Rail Services' key railroad industry  customers are Class 1 railroads,  regional
and short line railroads, North American transit systems, railcar and locomotive
builders,  and railcar lessors. The U.S. operations are located in 23 states and
include further  geographic  coverage  through mobile crews on a selected basis.
This coverage allows for Rail Services' customer base to be dispersed throughout
the U.S., Canada and Mexico.

                                       25
<PAGE>

In March  2003,  the Company  signed a letter of intent to sell the  majority of
Railcar Ltd. assets to the Andersons,  Inc. A definitive  purchase agreement was
signed in November 2003 and the  transaction  closed in February  2004. See PART
II, ITEM 8, Note 3B to the Progress Energy Consolidated Financial Statements for
a discussion of this transaction.

ENVIRONMENTAL MATTERS

See PART II,  ITEM 8, Note 21E to the  Progress  Energy  Consolidated  Financial
Statements for a discussion of Rail's environmental matters.

OTHER

GENERAL

The Other Businesses  segment  primarily  includes the operations of PTC LLC and
Strategic  Resource  Solutions  Corp.  (SRS).  This segment also includes  other
nonregulated operations of PEC and FPC.

PROGRESS TELECOM LLC

In December 2003, PTC and Caronet,  both  wholly-owned  subsidiaries of Progress
Energy,   and  EPIK,  a   wholly-owned   subsidiary   of  Odyssey,   contributed
substantially  all of their assets and  transferred  certain  liabilities to PTC
LLC, a  subsidiary  of PTC.  Subsequently,  the stock of Caronet  was sold to an
affiliate  of Odyssey for $2 million in cash and Caronet  became a  wholly-owned
subsidiary of Odyssey.  Following consummation of all the transactions described
above, PTC holds a 55 percent  ownership  interest in, and is the parent, of PTC
LLC; Odyssey holds a combined 45 percent  ownership  interest in PTC LLC through
EPIK  and  Caronet.  The  accounts  of PTC LLC  are  included  in the  Company's
Consolidated Financial Statements since the transaction date.

PTC LLC has data fiber network transport capabilities that stretch from New York
to Miami,  Florida,  with  gateways to Latin  America and  conducts  primarily a
carrier's carrier business. PTC LLC markets wholesale fiber-optic-based capacity
service in the Eastern United States to long-distance carriers, internet service
providers and other telecommunications  companies. PTC LLC also markets wireless
structure  attachments  to wireless  communication  companies  and  governmental
entities.  At December 31, 2003, PTC LLC owned and managed more than 8,500 route
miles and more than 420,000 fiber miles of fiber-optic cable.

PTC  LLC  competes  with  other  providers  of  fiber-optic   telecommunications
services, including local exchange carriers and competitive access providers, in
the Eastern United States.

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

For additional information regarding asset and investment impairments related to
the Company's investments in the telecommunications  industry, see PART II, ITEM
8, Note 9 to the Progress Energy Consolidated  Financial Statements,  and Note 6
to the PEC Consolidated Financial Statements.

NCNG

In October 2002, the Company  approved the sale of NCNG. In September  2003, the
Company  completed the sale of NCNG and the Company's equity investment in ENCNG
to  Piedmont  Natural  Gas  Company,  Inc.  See PART II,  ITEM 8, Note 3A to the
Progress Energy Consolidated Financial Statements for further discussion of this
transaction.

                                       26
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

ELECTRIC UTILITY OPERATING STATISTICS - PROGRESS ENERGY

                                                                               Years Ended December 31
                                                                2003          2002         2001         2000(d)        1999
                                                         ------------   -----------  -----------    -----------   ----------
Energy supply (millions of kilowatt-hours)
  Generated - Steam                                           51,501        49,734       48,732         31,132       28,260
              Nuclear                                         30,576        30,126       27,301         23,857       22,451
              Hydro                                              955           491          245            441          520
              Combustion Turbines/Combined Cycle               7,819         8,522        6,644          1,337          435
  Purchased                                                   13,848        14,305       14,469          5,724        5,132
                                                         ------------   -----------  -----------    -----------   ----------
      Total energy supply (Company share)                    104,699       103,178       97,391         62,491       56,798
  Jointly-owned share (a)                                      5,213         5,258        4,886          4,505        4,353
                                                         ------------   -----------  -----------    -----------   ----------
      Total system energy supply                             109,912       108,436      102,277         66,996       61,151
                                                         ============   ===========  ===========    ===========   ==========

Average fuel cost (per million Btu)
  Fossil                                               $        2.94  $       2.62 $       2.46  $        1.96  $      1.75
  Nuclear fuel                                         $        0.44  $       0.44 $       0.45  $        0.45  $      0.46
  All fuels                                            $        2.05  $       1.84 $       1.77  $        1.30  $      1.16

Energy sales (millions of kilowatt-hours)
Retail
   Residential                                                34,712        33,993       31,976         15,365       13,348
   Commercial                                                 24,110        23,888       23,033         12,221       11,068
   Industrial                                                 16,749        16,924       17,204         14,762       14,568
   Other Retail                                                4,382         4,287        4,149          1,626        1,359
Wholesale                                                     19,841        19,204       17,715         15,012       14,526
Unbilled                                                         189           275       (1,045)         1,098        (110)
                                                         ------------   -----------  -----------    -----------   ----------
      Total energy sales                                      99,983        98,571       93,032         60,084       54,759
      Company uses and losses                                  3,753         3,604        3,478          2,286        2,039
                                                         ------------   -----------  -----------    -----------   ----------
      Total energy requirements                              103,736       102,175       96,510         62,370       56,798
                                                         ============   ===========  ===========    ===========   ==========

Electric revenues (in millions)
  Retail                                               $       5,620  $      5,515 $      5,462  $       2,799  $     2,531
  Wholesale                                                      915           881          923            665          556
  Miscellaneous revenue                                          206           205          172             81           60
                                                       --------------   -----------  -----------    -----------   ----------
      Total electric revenues                          $       6,741  $      6,601 $      6,557  $       3,545  $     3,147
                                                         ============   ===========  ===========    ===========   ==========

Peak demand of firm load (thousands of kW)
  System (b)                                                  19,876        20,365       19,166         18,874      10,948
  Company                                                     19,235        19,746       18,564         18,272      10,344

Total regulated capability at year-end (thousands of kW)
  Fossil plants                                               16,522        16,006       15,826  (e)    14,747       6,736
  Nuclear plants                                               4,220  (g)    4,127  (f)   4,008          4,008       3,174
  Hydro plants                                                   218           218          218            218         218
  Purchased                                                    2,826         2,929        2,890          2,278       1,088
                                                         ------------   -----------  -----------     ----------   ---------
      Total system capability                                 23,786        23,280       22,942         21,251      11,216
   Less jointly-owned portion (c)                                698           682          668            662         593
                                                         ------------   -----------  -----------     ----------   ---------
      Total Company capability - regulated                    23,088        22,598       22,274         20,589      10,623
                                                         ============   ===========  ===========     ==========   =========
</TABLE>

(a)  Amounts  represent  co-owner's  share of the energy  supplied  from the six
     generating facilities that are jointly owned.
(b)  For 2000 - 2003, this represents the combined summer  non-coincident system
     net peaks for PEC and PEF.
(c)  For PEC, this  represents  Power Agency's  retained share of  jointly-owned
     facilities  per the  Power  Coordination  Agreement  between  PEC and Power
     Agency.
(d)  Amounts  include  information  for PEF since November 30, 2000, the date of
     acquisition.
(e)  Amount includes 459 MW related to Rowan units that were  transferred to PVI
     in February 2002.
(f)  Amount  includes  power uprates for Harris,  Brunswick 1 and Robinson.  The
     Maximum  Dependable  Capability (MDC) for Harris was restated January 2002;
     the MDCs for Brunswick 1 and Robinson were restated January 2003.
(g)  Amount  includes  power  uprates  for CR3 and  Brunswick  2. The MDC's were
     restated January 2004.

                                       27
<PAGE>

OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                               Years Ended December 31
                                                               2003           2002          2001           2000        1999
                                                         -----------    -----------   -----------    -----------   ---------
Energy supply (millions of kilowatt-hours)
  Generated - Steam                                          28,522         28,547        27,913         29,520      28,260
              Nuclear                                        24,537         23,425        21,321         23,275      22,451
              Hydro                                             955            491           245            441         520
              Combustion Turbines/Combined Cycle              1,344          1,934           802            733         435
  Purchased                                                   4,467          5,213         5,296          4,878       5,132
                                                         -----------    -----------   -----------    -----------   ---------
      Total energy supply (Company share)                    59,825         59,610        55,577         58,847      56,798
  Power Agency share (a)                                      4,670          4,659         4,348          4,505       4,353
                                                         -----------    -----------   -----------    -----------   ---------
      Total system energy supply                             64,495         64,269        59,925         63,352      61,151
                                                         ===========    ===========   ===========    ===========   =========

Average fuel cost (per million Btu)
  Fossil                                               $       2.29  $        2.16  $       1.91  $        1.83  $     1.75
  Nuclear fuel                                         $       0.43  $        0.43  $       0.44  $        0.45  $     0.46
  All fuels                                            $       1.43  $        1.38  $       1.26  $        1.21  $     1.16

Energy sales (millions of kilowatt-hours)
Retail
   Residential                                               15,283         15,239        14,372         14,091      13,348
   Commercial                                                12,557         12,468        11,972         11,432      11,068
   Industrial                                                12,749         13,089        13,332         14,446      14,568
   Other Retail                                               1,408          1,437         1,423          1,423       1,359
Wholesale                                                    15,518         15,024        12,996         14,582      14,526
Unbilled                                                        (44)           270          (534)           679        (110)
                                                         -----------    -----------   -----------    -----------   ---------
      Total energy sales                                     57,471         57,527        53,561         56,653      54,759
      Company uses and losses                                 2,354          2,083         2,016          2,194       2,039
                                                         -----------    -----------   -----------    -----------   ---------
      Total energy requirements                              59,825         59,610        55,577         58,847      56,798
                                                         ===========    ===========   ===========    ===========   =========

Electric revenues (in millions)
  Retail                                               $      2,825  $       2,795  $      2,666  $       2,609  $    2,531
  Wholesale                                                     687            652           634            577         556
  Miscellaneous revenue                                          77             92            44            122          59
                                                         -----------    -----------   -----------    -----------   ---------
      Total electric revenues                          $      3,589  $       3,539  $      3,344  $       3,308  $    3,146
                                                         ===========    ===========   ===========    ===========   =========

Peak demand of firm load (thousands of kW)
  System                                                     11,771         11,977        11,376         11,157      10,948
  Company                                                    11,130         11,358        10,774         10,555      10,344

Total regulated capability at year-end (thousands of kW)
  Fossil plants                                               8,816          8,816         8,648  (c)     7,569       6,891
  Nuclear plants                                              3,382  (e)     3,293  (d)    3,174          3,174       3,174
  Hydro plants                                                  218            218           218            218         218
  Purchased                                                   1,513          1,617         1,586            978       1,088
                                                         -----------    -----------    ----------     ----------   ---------
      Total system capability                                13,929         13,944        13,626         11,939      11,371
  Less Power Agency-owned portion (b)                           629            613           599            593         593
                                                         -----------    -----------    ----------     ----------   ---------
      Total Company capability                               13,300         13,331        13,027         11,346      10,778
                                                         ===========    ===========    ==========     ==========   =========
</TABLE>

(a)  Amounts represent Power Agency's share of the energy supplied from the four
     generating facilities that are jointly owned.
(b)  Amounts represent Power Agency's retained share of jointly-owned facilities
     per the Power Coordination Agreement between PEC and Power Agency.
(c)  Amount includes 459 MW related to Rowan units that were  transferred to PVI
     in February 2002.
(d)  Amount  includes power upgrades for Harris,  Brunswick 1 and Robinson.  The
     MDC for Harris was  restated  January  2002;  the MDCs for  Brunswick 1 and
     Robinson were restated January 2003.
(e)  Amount includes power uprate for Brunswick 2; the MDC was restated  January
     2004.

                                       28
<PAGE>

ITEM 2. PROPERTIES

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

ELECTRIC - PEC

At December 31, 2003, PEC's eighteen  generating plants represent a flexible mix
of fossil,  nuclear,  hydroelectric,  combustion  turbines  and  combined  cycle
resources,  with a total summer generating capacity of 12,416 MW. Of this total,
Power  Agency owns  approximately  682 MW. On  December  31,  2003,  PEC had the
following generating facilities:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

--------------------------------------------------------------------------------------------------------------------
                                                                                    PEC           Summer Net
                                             No. of    In-Service                Ownership      Capability (a)
        Facility              Location        Units       Date         Fuel       (in %)           (in MW)
--------------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Asheville                Skyland, NC            2      1964-1971       Coal         100              392
Cape Fear                Moncure, NC            2      1956-1958       Coal         100              316
Lee                      Goldsboro, NC          3      1952-1962       Coal         100              407
Mayo                     Roxboro, NC            1         1983         Coal        83.83             745       (b)
Robinson                 Hartsville, SC         1         1960         Coal         100              174
Roxboro                  Roxboro, NC            4      1966-1980       Coal        96.32    (c)     2,462      (b)
Sutton                   Wilmington, NC         3      1954-1972       Coal         100              613
Weatherspoon             Lumberton, NC          3      1949-1952       Coal         100              176
                                             --------                                           ---------------
                         Total                 19                                                   5,285
COMBINED CYCLE
Cape Fear                Moncure, NC            2         1969          Oil         100               84
Richmond                 Hamlet, NC             1         2002        Gas/Oil       100              472
                                             --------                                           ---------------
                         Total                  3                                                    556
COMBUSTION TURBINES
Asheville                Skyland, NC            2      1999-2000      Gas/Oil       100              330
Blewett                  Lilesville, NC         4         1971          Oil         100               52
Darlington               Hartsville, SC        13      1974-1997      Gas/Oil       100              812
Lee                      Goldsboro, NC          4      1968-1971        Oil         100               91
Morehead City            Morehead City,  NC     1         1968          Oil         100               15
Richmond                 Hamlet, NC             5      2001-2002      Gas/Oil       100              775
Robinson                 Hartsville, SC         1         1968        Gas/Oil       100               15
Roxboro                  Roxboro, NC            1         1968          Oil         100               15
Sutton                   Wilmington, NC         3      1968-1969      Gas/Oil       100               64
Wayne County             Goldsboro, NC          4         2000        Gas/Oil       100              668
Weatherspoon             Lumberton, NC          4      1970-1971      Gas/Oil       100              138
                                             --------                                           ---------------
                         Total                 42                                                  2,975
NUCLEAR
Brunswick                Southport, NC          2      1975-1977      Uranium      81.67           1,772       (b)(d)
Harris                   New Hill, NC           1         1987        Uranium      83.83             900       (b)
Robinson                 Hartsville, SC         1         1971        Uranium       100              710
                                             --------                                           ---------------
                         Total                  4                                                  3,382
HYDRO
Blewett                  Lilesville, NC         6         1912         Water        100               22
Marshall                 Marshall, NC           2         1910         Water        100                5
Tillery                  Mount Gilead, NC       4      1928-1960       Water        100               86
Walters                  Waterville, NC         3         1930         Water        100              105
                                             --------                                           ---------------
                         Total                 15                                                    218

TOTAL                                          83                                                 12,416
--------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts  represent  PEC's net summer  peak  rating,  gross of  co-ownership
     interest in plant capacity.
(b)  Facilities are jointly owned by PEC and Power Agency.  The capacities shown
     include Power Agency's share.
(c)  PEC and Power Agency are  co-owners of Unit 4 at the Roxboro  Plant.  PEC's
     ownership interest in this 700 MW turbine is 87.06%.
(d)  During 2003, a power uprate  increased the net summer  capability of Unit 2
     to 900 MWs. The MDC was restated in January 2004.

                                       29
<PAGE>

At December 31, 2003, including both the total generating capacity of 12,416 MWs
and the total firm contracts for purchased power of approximately 1,513 MWs, PEC
had total capacity resources of approximately 13,929 MWs.

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

At December 31, 2003, PEC had approximately  6,000 circuit miles of transmission
lines including about 300 miles of 500 kilovolt (kV) lines and about 3,000 miles
of 230 kV lines.  PEC had  distribution  lines of  approximately  45,000 circuit
miles of overhead conductor and about 17,000 circuit miles of underground cable.
Distribution and transmission  substations in service had a transformer capacity
of  approximately  12,000,000   kilovolt-ampere  (kVA)  in  2,411  transformers.
Distribution line transformers numbered  approximately 502,700 with an aggregate
capacity of about 21,000,000 kVA.

ELECTRIC - PEF

At December 31, 2003, PEF's fourteen  generating plants represent a flexible mix
of fossil, nuclear, combustion turbine and combined cycle resources with a total
summer generating  capacity (including  jointly-owned  capacity) of 8,544 MW. At
December 31, 2003, PEF had the following generating facilities:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

------------------------------------------------------------------------------------------------------------------
                                                                                   PEF      Summer Net
                                               No. of  In-Service               Ownership   Capability (a)
        Facility                Location       Units      Date         Fuel       (in %)      (in MW)
------------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Anclote                   Holiday, FL            2      1974-1978    Gas/Oil       100          993
Bartow                    St. Petersburg, FL     3      1958-1963    Gas/Oil       100          444
Crystal River             Crystal River, FL      4      1966-1984      Coal        100        2,302
Suwannee River            Live Oak, FL           3      1953-1956    Gas/Oil       100          143
                                               -------                                     ---------------
                          Total                 12                                            3,882
COMBINED CYCLE
Hines                     Bartow, FL             2      1999-2003    Gas/Oil       100          998
Tiger Bay                 Fort Meade, FL         1        1997         Gas         100          207
                                               -------                                     ---------------
                          Total                  3                                            1,205
COMBUSTION TURBINES
Avon Park                 Avon Park, FL          2        1968       Gas/Oil       100           52
Bartow                    St. Petersburg, FL     4      1958-1972    Gas/Oil       100          187
Bayboro                   St. Petersburg, FL     4        1973         Oil         100          184
DeBary                    DeBary, FL            10      1975-1992    Gas/Oil       100          667
Higgins                   Oldsmar, FL            4      1969-1970    Gas/Oil       100          122
Intercession City         Intercession City, FL 14      1974-2000    Gas/Oil       100 (c)    1,041       (b)
Rio Pinar                 Rio Pinar, FL          1        1970         Oil         100           13
Suwannee River            Live Oak, FL           3        1980       Gas/Oil       100          164
Turner                    Enterprise, FL         4      1970-1974      Oil         100          154
University of             Gainesville, FL        1        1994         Gas         100           35
   Florida Cogeneration
                                               -------                                     ---------------
                          Total                 47                                            2,619
NUCLEAR
Crystal River             Crystal River, FL      1        1977       Uranium      91.8          838       (b)
                                                                                                          (d)
                                               -------                                     ---------------
                          Total                  1                                              838

TOTAL                                           63                                            8,544
------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts  represent  PEF's net summer  peak  rating,  gross of  co-ownership
     interest in plant capacity.
(b)  Facilities  are jointly owned.  The capacities  shown include joint owners'
     share.
(c)  PEF and Georgia  Power  Company  (Georgia  Power) are co-owners of a 143 MW
     advanced  combustion turbine located at PEF's Intercession City site (P11).
     Georgia Power has the exclusive right to the output of this unit during the
     months of June through  September.  PEF has that right for the remainder of
     the year.
(d)  During 2003, a power uprate  increased  the net summer  capability  of this
     unit to 838 MWs. The MDC was restated in January 2004.

                                       30
<PAGE>

At December 31, 2003, PEF had total capacity  resources of  approximately  9,857
MWs,  including  both the total  generating  capacity of 8,544 MWs and the total
firm contracts for purchased power of 1,313 MWs.

Several  entities  have  acquired  undivided  ownership  interests in CR3 in the
aggregate amount of 8.2%. The joint ownership  participants are: City of Alachua
- 0.08%,  City of  Bushnell  - 0.04%,  City of  Gainesville  - 1.41%,  Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New  Smyrna  Beach - 0.56%,  City of Ocala -  1.33%,  Orlando  Utilities
Commission  - 1.60% and Seminole  Electric  Cooperative,  Inc. - 1.70%.  PEF and
Georgia Power are co-owners of a 143 MW advance  combustion  turbine  located at
PEF's Intercession City site (P11). Georgia Power has the exclusive right to the
output of this unit during the months of June  through  September.  PEF has that
right for the  remainder  of the year.  Otherwise,  PEF has good and  marketable
title to its principal  plants and important  units,  subject to the lien of its
mortgage and deed of trust, with minor exceptions, restrictions and reservations
in  conveyances,  as well as minor  defects  of the nature  ordinarily  found in
properties of similar  character and magnitude.  PEF also owns certain easements
over private property on which transmission and distribution lines are located.

At December 31, 2003, PEF had approximately  5,000 circuit miles of transmission
lines  including about 200 miles of 500 kV lines and about 1,500 miles of 230 kV
lines.  PEF had  distribution  lines of  approximately  25,000  circuit miles of
overhead  conductor  and  about  15,000  circuit  miles  of  underground  cable.
Distribution and transmission  substations in service had a transformer capacity
of  approximately   45,000,000  kVA  in  614  transformers.   Distribution  line
transformers  numbered  356,930 with an aggregate  capacity of about  18,000,000
kVA.

FUELS

The Fuels business segment controls,  either directly or through business units,
coal reserves located in eastern Kentucky and southwestern Virginia.  Fuels owns
properties that contain estimated coal reserves of approximately 60 million tons
and controls,  through  mineral  leases,  additional  estimated coal reserves of
approximately  18 million  tons.  The reserves  controlled  include  substantial
quantities of high quality, low sulfur coal that is appropriate for use at PEF's
existing  generating  units.  Fuels'  total  production  of coal during 2003 was
approximately 3.5 million tons.

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

The  Fuels  business  segment,  through  its  business  units,  owns  all of the
interests  in five  synthetic  fuel  entities  and a  minority  interest  in one
synthetic fuel entity that owns  facilities that produce  synthetic fuel.  These
facilities  are in six  different  locations  in  West  Virginia,  Virginia  and
Kentucky.

Fuels' natural gas and oil production in 2003 was 25.4 Bcf equivalent. Fuels has
oil and gas leases in East Texas,  North Texas and  Louisiana  with total proven
natural gas and oil reserves of approximately 360 Bcf equivalent.

CCO

At December 31, 2003, CCO had the following  nonregulated  generation  plants in
service.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

----------------------------------------------------------------------------------------------------------------
                                             Construction        Commercial        Configuration/
        Project              Location         Start Date       Operation Date      Number of Units     MW (a)
----------------------------------------------------------------------------------------------------------------
Monroe Units 1 and 2        Monroe, GA     4Q 1998/1Q 2000     4Q 1999/2Q 2001     Simple-Cycle, 2        315
Rowan Phase I (b)         Salisbury, NC        1Q 2000             2Q 2001         Simple-Cycle, 3        459
Walton (c)                  Monroe, GA         2Q 2000             2Q 2001         Simple-Cycle, 3        460
DeSoto Units               Arcadia, FL         2Q 2001             2Q 2002         Simple-Cycle, 2        320
Effingham                   Rincon, GA         1Q 2001             3Q 2003        Combined-Cycle, 1       480
Rowan Phase II (b)        Salisbury, GA        4Q 2001             2Q 2003        Combined-Cycle, 1       466
Washington (c)           Sandersville, GA      2Q 2002             2Q 2003         Simple-Cycle, 4        600
                                                                                                     -----------

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

(a) Amounts represent CCO's summer rating.
(b) This project was transferred from PEC to PVI in February 2002.
(c) These projects were purchased from LG&E Energy Corp. in February 2002.

                                       31
<PAGE>

RAIL SERVICES

Progress Rail is one of the largest integrated  processors of railroad materials
in the United States, and is a leading supplier of new and reconditioned freight
car  parts;  rail,  rail  welding  and track  work  components;  railcar  repair
facilities;  railcar and locomotive  leasing;  maintenance-of-way  equipment and
scrap metal recycling. It has facilities in 23 states, Mexico and Canada.

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

PTC

PTC  LLC  provides   wholesale   telecommunications   services   throughout  the
Southeastern  United States.  PTC LLC incorporates more than 420,000 fiber miles
of fiber-optic cable in its network including more than 185  Points-of-Presence,
or physical locations where a presence for network access exists.

                                       32
<PAGE>



ITEM 3. LEGAL PROCEEDINGS

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

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

In November  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. In March 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.  SRS has amended its claims and asserted new claims  against
the  District  and other  parties,  including a former SRS employee and a former
District employee.

On March 13, 2003,  the City Attorney and the District  filed new claims 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 filing states
that the City and the  District  seek  "more than $300  million  in damages  and
penalties." PEC was added as a cross-defendant.

The Company,  SRS, Progress Energy  Solutions,  Inc. and PEC all have denied the
District's allegations and cross-claims. Discovery is in progress in the matter.
The case has been  assigned  to a judge  under the  Sacramento  County  superior
court's  case  management  rules,  and the  judge  and  the  parties  have  been
conferring on scheduling and processes to narrow or resolve issues, if possible,
and to  prepare  the case for  trial.  No trial  date has been set.  SRS and the
Company are vigorously defending all of these claims. The Company cannot predict
the outcome of this matter, but will vigorously defend against the allegations.

2.   Collins v. Duke Energy Corporation et al, Civil Action No. 03CP404050

In August 2003,  PEC was served as a  co-defendant  in a purported  class action
lawsuit  styled as Collins v. Duke Energy  Corporation  et al,  Civil Action No.
03CP404050,  in South  Carolina's  Circuit  Court of Common  Pleas for the Fifth
Judicial  Circuit.  PEC is one of three  electric  utilities  operating in South
Carolina named in the suit.  The plaintiffs are seeking  damages for the alleged
improper use of electric  easements  but have not  asserted a dollar  amount for
their damage claims.  The complaint alleges that the licensing of attachments on
electric utility poles, towers and other structures to non-utility third parties
or  telecommunication  companies for other than the electric utilities' internal
use along the electric right-of-way constitutes a trespass.

In September  2003, PEC filed a motion to dismiss all counts of the complaint on
substantive  and procedural  grounds.  In October 2003,  the plaintiffs  filed a
motion to amend their complaint.  PEC believes the amended complaint asserts the
same factual  allegations as are in the original  complaint and also seeks money
damages and injunctive relief.

The court has not yet held any  hearings  or made any  rulings in this case.  In
November  2003,  PEC filed a motion to dismiss  the  plaintiffs'  first  amended
complaint.  PEC cannot  predict  the outcome of any future  proceedings  in this
matter, but will vigorously defend against the allegations.

                                       33
<PAGE>

3.   U.S. Global,  LLC v. Progress Energy,  Inc. et al, Case No. 03004028-03 and
     Progress  Synfuel  Holdings,  Inc.  et al. v. U.S.  Global,  LLC,  Case No.
     03004028-03

A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two
lawsuits  arising  out of an Asset  Purchase  Agreement  dated as of October 19,
1999, by and among U.S.  Global LLC  (Global),  EARTHCO,  certain  affiliates of
EARTHCO  (collectively  the  EARTHCO  Sellers),  EFC Synfuel LLC (which is owned
indirectly by Progress  Energy,  Inc.) and certain of its affiliates,  including
Solid Energy LLC,  Solid Fuel LLC,  Ceredo  Synfuel  LLC,  Gulf Cost Synfuel LLC
(currently   named  Sandy  River   Synfuel  LLC)   (Collectively   the  Progress
Affiliates),  as amended by an Amendment to Purchase  Agreement as of August 23,
2000 (the Asset  Purchase  Agreement).  Global has asserted that pursuant to the
Asset  Purchase  Agreement it is entitled to (1) interest in two synthetic  fuel
facilities  currently  owned by the  Progress  Affiliates,  and (2) an option to
purchase additional interests in the two synthetic fuel facilities.

The first suit, U.S. Global,  LLC v. Progress  Energy,  Inc. et al, was filed in
the Circuit  Court for  Broward  County,  Florida on March 4, 2003 (the  Florida
Global  Case).  The Florida  Global Case asserts  claims for breach of the Asset
Purchase  Agreement and other  contract and tort claims  related to the Progress
Affiliates'  alleged  interference with Global's rights under the Asset Purchase
Agreement.   The  Florida  Global  Case  requests  an   unspecified   amount  of
compensatory  damages,  as well as declaratory relief. On December 15, 2003, the
Progress Affiliates filed a motion to dismiss the Third Amended Complaint in the
Florida Global Case.

The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was
filed by the Progress  Affiliates in the Superior  Court for Wake County,  North
Carolina seeking declaratory relief consistent with the Company's interpretation
of the Asset Purchase  Agreement (the North  Carolina  Global Case).  Global was
served with the North Carolina Global Case on April 17, 2003.

On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack
of personal jurisdiction over Global. In the alternative,  Global requested that
the court decline to exercise its  discretion  to hear the Progress  Affiliates'
declaratory  judgment action.  On August 7, 2003, the Wake County Superior Court
denied  Global's  motion to  dismiss  and  entered  an order  staying  the North
Carolina  Global  Case,  pending  the outcome of the Florida  Global  Case.  The
Progress  Affiliates have appealed the Superior  Court's order staying the case;
Global  has cross  appealed  the  denial of its  motion to  dismiss  for lack of
personal jurisdiction. The North Carolina Court of Appeals has not set a hearing
date for the Progress  Affiliates'  Appeal or Global's cross appeal. The Company
cannot predict the outcome of these matters,  but will vigorously defend against
the allegations.

4.   Gerber Asset  Management LLC v. William  Cavanaugh III and Progress Energy,
     Inc. et al, Case No. 04 CV 636

On February  3, 2004,  Progress  Energy,  Inc.  was served  with a class  action
complaint  alleging  violations of federal  security laws in connection with the
Company's issuance of Contingent Value Obligations  (CVOs). The action was filed
in the United States  District  Court for the Southern  District of New York and
names Progress Energy,  Inc. Chairman William Cavanaugh III and Progress Energy,
Inc. as defendants.  The Complaint alleges that Progress Energy failed to timely
disclose the impact of the Alternative Minimum Tax required under Sections 55-59
of the  Internal  Revenue  Code  (Code) on the value of certain  CVOs  issued in
connection  with  the  Florida  Progress  Corporation  merger.  The  suit  seeks
unspecified  compensatory  damages,  as well as attorneys'  fees and  litigation
costs.  The Company is currently  reviewing the complaint and cannot predict the
outcome of this matter, but will vigorously defend against the allegations.

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

         NONE

                                       34
<PAGE>





                     EXECUTIVE OFFICERS OF THE REGISTRANTS

Name                        Age              Recent Business Experience

Robert B. McGehee           60     President   and  Chief   Executive   Officer,
                                   Progress  Energy,  October  2002 and March 1,
                                   2004,  respectively,  to present. Mr. McGehee
                                   joined the Company (formerly CP&L) in 1997 as
                                   Senior Vice  President  and General  Counsel.
                                   Since that time,  he has held several  senior
                                   management     positions    of     increasing
                                   responsibility.  Most  recently,  Mr. McGehee
                                   served  as  President  and  Chief   Operating
                                   Officer of the Company, having responsibility
                                   for   the   day-to-day   operations   of  the
                                   Company's    regulated    and    nonregulated
                                   businesses. Prior to that, Mr. McGehee served
                                   as President and Chief  Executive  Officer of
                                   Progress Energy Service Company, LLC.

                                   Before joining Progress  Energy,  Mr. McGehee
                                   chaired  the  board  of Wise  Carter  Child &
                                   Caraway, a law firm headquartered in Jackson,
                                   Miss.  He  primarily   handled   corporation,
                                   contract,  nuclear  regulatory and employment
                                   matters.  During the 1990s,  he also provided
                                   significant  counsel  to  U.S.  companies  on
                                   reorganizations,  business growth initiatives
                                   and  preparing  for  deregulation  and  other
                                   industry changes.

William S. Orser            59     Group President,  Energy Supply, PEC and PEF,
                                   November  2000  to  present.   Mr.  Orser  is
                                   responsible  for the  operation of 38 utility
                                   and  nonregulated  power  plants of  Progress
                                   Energy.  He also  oversees the  organizations
                                   that  support  those  plants,  as well as the
                                   Company's   System  Planning  and  Operations
                                   function.

                                   Mr. Orser joined  Progress  Energy  (formerly
                                   CP&L) in 1993 as Executive Vice President and
                                   Chief  Nuclear   Officer.   He  later  became
                                   Executive  Vice  President  - Energy  Supply,
                                   PEC, a position he held until the acquisition
                                   of Florida Progress in 2000.

                                   Before joining the Company in April 1993, Mr.
                                   Orser was an executive at the Detroit  Edison
                                   Company,  serving as Executive Vice President
                                   - Nuclear Generation.  Previously,  he worked
                                   with Portland General Electric Co.


William D. Johnson          50     Group President,  Energy  Delivery,  Progress
                                   Energy,  January  2004 to present;  Executive
                                   Vice   President,   Progress  Energy  Service
                                   Company,  LLC,  January  1, 2004 to  present;
                                   PEC,  FPC and PEF  November  2000 to present.
                                   Mr.  Johnson  has been with  Progress  Energy
                                   (formerly  CP&L) since 1992 and most recently
                                   served  as   President,   CEO  and  Corporate
                                   Secretary,  Progress Energy Service  Company,
                                   LLC,  October 2002 to December 2003. Prior to
                                   that,  he  was  Executive  Vice  President  -
                                   Corporate    Relations    &    Administrative
                                   Services,  General  Counsel and  Secretary of
                                   Progress  Energy.  Mr. Johnson served as Vice
                                   President - Legal  Department  and  Corporate
                                   Secretary, CP&L from 1997 to 1999.

                                   Before joining Progress Energy, Johnson was a
                                   partner  with the Raleigh  office of Hunton &
                                   Williams,   where  he   specialized   in  the
                                   representation of utilities.

                                       35
<PAGE>

Peter M. Scott III          54     President   and  Chief   Executive   Officer,
                                   Progress Energy Service Company, LLC, January
                                   2004 to present;  Executive  Vice  President,
                                   FPC,  PEC, PEF, and Progress  Energy  Service
                                   Company,  LLC, 2000 to present. Mr. Scott has
                                   been with the Company since May 2000 and most
                                   recently  served as Executive  Vice President
                                   and  Chief  Financial   Officer  of  Progress
                                   Energy,  Inc.,  May 2000 to December 2003. In
                                   that   position,   Mr.   Scott   oversaw  the
                                   Company's strategic  planning,  financial and
                                   enterprise risk management functions.

                                   Before joining Progress Energy, Mr. Scott was
                                   the  founding  president  of Scott,  Madden &
                                   Associates,   Inc.,   a  general   management
                                   consulting  firm  headquartered  in  Raleigh,
                                   N.C.  The firm served  clients in a number of
                                   industries,      including     energy     and
                                   telecommunications.  Particular practice area
                                   specialties for Mr. Scott included  strategic
                                   planning and operations management.

Geoffrey S. Chatas          41     Executive Vice President and Chief  Financial
                                   Officer,  Progress Energy, Inc., FPC, PEC and
                                   PEF,  January  2004 to  present.  Mr.  Chatas
                                   oversees the Company's accounting,  strategic
                                   planning,   tax,   financial  and  regulatory
                                   services  and  enterprise   risk   management
                                   functions.  He  previously  served  as Senior
                                   Vice  President,   Progress   Energy,   Inc.,
                                   October 2003 to December 2003.

                                   Before joining  Progress  Energy,  Mr. Chatas
                                   served as Senior Vice President - Finance and
                                   Treasurer  for  American  Electric  Power,  a
                                   multi-state  energy holding  company based in
                                   Columbus,  Ohio.  During his time at AEP,  he
                                   managed  investor   relations  and  corporate
                                   finance.   In  addition,   Mr.   Chatas  held
                                   executive financial positions at Banc One and
                                   Citibank.

Robert H. Bazemore, Jr.     49     Chief  Accounting   Officer  and  Controller,
                                   Progress Energy,  Inc., June 2000 to present;
                                   Controller,  FPC and  PEF,  November  2000 to
                                   present;   Vice  President  and   Controller,
                                   Progress Energy Service Company,  LLC, August
                                   2000 to present; Chief Accounting Officer and
                                   Controller,  PEC,  May 2000 to  present.  Mr.
                                   Bazemore  has  been  with   Progress   Energy
                                   (formerly  CP&L) since 1986 and has served in
                                   a number of roles in  corporate  support  and
                                   field positions,  including  Director,  CP&L,
                                   Operations    &     Environmental     Support
                                   Department,   December   1998  to  May  2000;
                                   Manager,    CP&L   Financial   &   Regulatory
                                   Accounting, September 1995 to December 1998.

                                   Prior  to  joining   Progress   Energy,   Mr.
                                   Bazemore  worked in managerial and accounting
                                   positions with  companies in Roanoke,  VA and
                                   Jacksonville, FL.

Brenda F. Castonguay        51     Senior  Vice   President,   Progress   Energy
                                   Service  Company,  LLC, July 2002 to present.
                                   Ms. Castonguay  directs the work of the Human
                                   Resources,  Corporate Services,  Real Estate,
                                   IT/Telecommunications  and Corporate Security
                                   departments.   She  joined   Progress  Energy
                                   (formerly CP&L) in February 1994 as assistant
                                   to the Vice President - Human Resources.  She
                                   has also served as Manager - Human  Resources
                                   Administrative  Services and Vice President -
                                   Human  Resources.   During  her  tenure  with
                                   Progress Energy's Human Resources Department,
                                   Ms.  Castonguay  has managed human  resources
                                   activities    and    initiatives    affecting
                                   approximately 16,000 full-time employees.

                                   Before  joining the Company,  Ms.  Castonguay
                                   held  managerial  positions with Maine Yankee
                                   Atomic Power Co., Central Maine Power Co. and
                                   General Telephone & Electronics (GTE) Corp.

                                       36
<PAGE>

Donald K. Davis             58     Executive  Vice  President,  PEC, May 2000 to
                                   present.  Mr.  Davis  is also  President  and
                                   Chief  Executive  Officer,  SRS, June 2000 to
                                   present and was President and Chief Executive
                                   Officer,  NCNG,  July 2000 to September 2003.
                                   Mr.  Davis  joined the Company in May 2000 as
                                   Executive  Vice  President,  Gas  and  Energy
                                   Services.

                                   Before  joining the  Company,  Mr.  Davis was
                                   Chairman,   President  and  Chief   Executive
                                   Officer of Yankee  Atomic  Electric  Company,
                                   and served as Chairman,  President  and Chief
                                   Executive Officer of Connecticut Atomic Power
                                   Company  from  1997 to May 2000  where he was
                                   responsible   for  two   electric   wholesale
                                   generating  companies.  Before joining Yankee
                                   Atomic Power Co., Davis served as a principal
                                   of   PRISM   Consulting   Inc.,   a   utility
                                   management  consulting  firm  he  founded  in
                                   1992.

Fred N. Day IV              60     President and Chief Executive  Officer,  PEC,
                                   October  2003  to  present;   Executive  Vice
                                   President, PEF, November 2000 to present. Mr.
                                   Day   oversees   all  aspects  of   Carolinas
                                   Delivery operations,  including  distribution
                                   and  customer  service,   transmission,   and
                                   products and services.  He previously  served
                                   as  Executive  Vice  President,  PEC and PEF.
                                   During his more than 30 years  with  Progress
                                   Energy  (formerly  CP&L),  Mr.  Day has  held
                                   several  management  positions of  increasing
                                   responsibility.   He  was  promoted  to  Vice
                                   President - Western Region in 1995.

*H. William Habermeyer, Jr. 61     President and Chief Executive  Officer,  PEF,
                                   November  2000  to  present.  Mr.  Habermeyer
                                   joined Progress Energy (formerly PEC) in 1993
                                   after a career in the U.S.  Navy.  During his
                                   tenure with the Company,  Mr.  Habermeyer has
                                   served as Vice  President - Nuclear  Services
                                   and Environmental  Support;  Vice President -
                                   Nuclear  Engineering;  and Vice  President  -
                                   Western  Region.   While  overseeing  Western
                                   Region   operations,   Mr.   Habermeyer   was
                                   responsible    for   regional    distribution
                                   management,  customer  support and  community
                                   relations.

*Bonnie V. Hancock          42     President,    Progress   Fuels   Corporation,
                                   September  2002 to present.  Ms.  Hancock has
                                   served in  several  positions  since  joining
                                   Progress  Energy  (formerly  CP&L)  in  1993,
                                   including   Director  -  Federal  Tax,   Vice
                                   President and Controller and Vice President -
                                   Strategic Planning.

                                   Before  joining  the  Company,   Ms.  Hancock
                                   directed   all  tax   planning  and  research
                                   activities at Potomac  Electric  Power Co. in
                                   Washington,   D.C.   She   also   worked   in
                                   management  positions with Finalco,  Inc. and
                                   Aronson, Greene, Fisher and Co. CPAs.

C.S. Hinnant                59     Senior  Vice   President  and  Chief  Nuclear
                                   Officer,  PEC,  June  1998  to  present.  Mr.
                                   Hinnant  joined  Progress  Energy   (formerly
                                   CP&L) in 1972 at the Brunswick  Nuclear Plant
                                   near Southport,  N.C.,  where he held several
                                   positions   in  the   startup   testing   and
                                   operating  organizations.  He  left  Progress
                                   Energy in 1976 to work for Babcock and Wilcox
                                   in the  Commercial  Nuclear  Power  Division,
                                   returning to Progress  Energy in 1977.  Since
                                   that   time,   he  has   served  in   various
                                   management  positions  at three  of  Progress
                                   Energy's nuclear plant sites.

                                       37
<PAGE>

Tom D. Kilgore              56     Group   President,   PEC  (November  2000  to
                                   present);   President   and   CEO,   Progress
                                   Ventures,   Inc.,   March  2000  to  present.
                                   Progress  Ventures,  Inc. was created in 2000
                                   to  manage   Progress   Energy's  assets  and
                                   operations in fuel extraction,  manufacturing
                                   and  delivery,  nonregulated  generation  and
                                   energy marketing and trading.

                                   Mr. Kilgore joined Progress Energy  (formerly
                                   CP&L) in August 1998 as Senior Vice President
                                   -  Power   Operations.   Before  joining  the
                                   Company,  Mr. Kilgore was President and Chief
                                   Executive Officer - Oglethorpe Power Corp. He
                                   held other management positions at Oglethorpe
                                   including   Senior  Vice  President  -  Power
                                   Supply.  Before joining Oglethorpe Power, Mr.
                                   Kilgore  was  Director  -  Fossil  and  Hydro
                                   Operations  for Arkansas Power and Light Co.,
                                   where  he  held  numerous  other   management
                                   positions.

Jeffrey J. Lyash            42     Senior Vice President,  PEF, November 2003 to
                                   present.  Mr.  Lyash  oversees all aspects of
                                   energy delivery  operations for PEF. Prior to
                                   coming to PEF, Mr. Lyash was Vice President -
                                   Transmission   in  Energy   Delivery  in  the
                                   Carolinas since January 2002.

                                   Mr. Lyash joined  Progress Energy in 1993 and
                                   spent his first  eight years with the Company
                                   at the Brunswick  Nuclear Plant in Southport,
                                   North   Carolina.   His  last   position   at
                                   Brunswick was as Director of site operations.

John R. McArthur            48     Senior Vice  President,  General  Counsel and
                                   Secretary of Progress Energy, January 2004 to
                                   present.  Mr.  McArthur  oversees  the  Audit
                                   Services, Corporate Communications, Corporate
                                   Relations and Administrative Services, Legal,
                                   Economic Development,  Environment,  Health &
                                   Safety and Public  Affairs  departments.  Mr.
                                   McArthur is also Senior  Vice  President  and
                                   Corporate  Secretary,  Florida  Progress  and
                                   PEC, and Senior Vice President,  PEF, January
                                   1  to  present.  Previously,  he  served  the
                                   Company as Senior Vice  President - Corporate
                                   Relations  (December  2002 to December  2003)
                                   and  as  Vice   President  -  Public  Affairs
                                   (December 2001 to December 2002).

                                   Before  joining  Progress  Energy in December
                                   2001,  Mr.  McArthur  was a  member  of North
                                   Carolina   Governor  Mike   Easley's   senior
                                   management   team,   handling   major  policy
                                   initiatives   as  well  as  media  and  legal
                                   affairs.  He also directed  Governor Easley's
                                   transition team after the election of 2000.

                                   Prior  to  joining   Governor   Easley,   Mr.
                                   McArthur handled state government  affairs in
                                   10 southeastern  states for General  Electric
                                   Co. He also  served as chief  counsel  in the
                                   North  Carolina  Attorney  General's  office,
                                   where he supervised utility, consumer, health
                                   care, and  environmental  protection  issues.
                                   Before  that,  he was a  partner  at Hunton &
                                   Williams.

E. Michael Williams         55     Senior Vice President, PEC and PEF, June 2000
                                   and November 2000, respectively, to present.

                                   Before  joining  the  Company  in  2000,  Mr.
                                   Williams  was  with  Central  and   Southwest
                                   Corp., Inc. and subsidiaries for 28 years and
                                   served in various positions prior to becoming
                                   Vice President - Fossil Generation in Dallas.


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

                                       38
<PAGE>

                                     PART II

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

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

2003                   High            Low              Dividends Declared
----                   ----            ---              ------------------

First Quarter        $ 46.10         $ 37.45                $ 0.560
Second Quarter         48.00           38.99                  0.560
Third Quarter          45.15           39.60                  0.560
Fourth Quarter         46.00           41.60                  0.575

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

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

The December 31 closing price of the Company's  Common Stock was $45.26 for 2003
and $43.35 for 2002.

As of January  30,  2004,  the  Company  had 70,118  holders of record of Common
Stock.

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

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

PROGRESS ENERGY

Information  on the equity  compensation  plans of Progress  Energy is set forth
under the heading "Equity Compensation Plant Information" in the Progress Energy
2003  definitive  proxy  statement  dated  March 31,  2004 and  incorporated  by
reference herein.

PEC

PEC  does  not have  any  equity  compensation  plans  under  which  its  equity
securities are issued.

                                       39
<PAGE>

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

PROGRESS ENERGY, INC.

The selected consolidated  financial data should be read in conjunction with the
consolidated  financial  statements and the notes thereto included  elsewhere in
this report.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                       Years Ended December 31

                                          2003 (a)     2002 (a)      2001 (a)      2000 (a)(b)      1999
                                        ----------   ----------    ----------    -------------  -----------

                                               (dollars in millions, except per share data)
Operating results
  Operating revenues                    $   8,743    $   8,091     $   8,129     $   3,769      $    3,265
  Income from continuing
     operations before cumulative       $     811    $     552     $     541     $     478      $      383
     effect
  Net Income                            $     782    $     528     $     542     $     478      $      379

Per share data
  Basic earnings
  Income from continuing
     operations                         $    3.42    $    2.54     $    2.64     $    3.04      $     2.58
  Net income                            $    3.30    $    2.43     $    2.65     $    3.04      $     2.56

  Diluted earnings
  Income from continuing
     operations                         $    3.40    $    2.53     $    2.63     $    3.03      $     2.58
  Net income                            $    3.28    $    2.42     $    2.64     $    3.03      $     2.55
  Dividends declared per common
     share                              $    2.26    $    2.20     $    2.14     $    2.08      $     2.02

Assets (d)                              $  26,202    $  24,208     $  23,647     $  22,842      $   10,655

Capitalization
  Common stock equity                   $   7,444    $   6,677     $   6,004     $   5,424      $    3,413
  Preferred stock - redemption
     not required                              93           93            93            93              59
  Long-term debt, net (c)                   9,934        9,747         8,619         4,904           2,162
  Current portion of long-term debt           868          275           688           184             197
  Short-term obligations                        4          695           942         4,959           1,035
                                       -----------  -----------   -----------   -----------    -------------
   Total capitalization and total debt  $  18,343    $  17,487     $  16,346     $  15,564      $    6,866
                                       ===========  ===========   ===========   ===========    =============
</TABLE>

(a)  Operating   results  and  balance   sheet  data  have  been   restated  for
     discontinued operations.
(b)  Operating results and balance sheet data includes information for FPC since
     November 30, 2000, the date of acquisition.
(c)  Includes long-term debt to affiliated trust of $309 million at December 31,
     2003.
(d)  All periods have been restated for the reclassification of cost of removal,
     nuclear decommissioning and fossil dismantlement (See Note 5F).

                                       40
<PAGE>

PROGRESS ENERGY CAROLINAS, INC.

The selected consolidated  financial data should be read in conjunction with the
consolidated  financial  statements and the notes thereto included  elsewhere in
this report.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                     Years Ended December 31

                                           2003           2002            2001       2000(a)(b)     1999(b)
                                        -----------    -----------    ------------  ------------  ----------

                                                                      (dollars in millions)
Operating results
  Operating revenues                    $    3,600     $    3,554     $    3,360    $    3,528    $   3,365
  Net income                            $      482     $      431     $      364    $      461    $     382
  Earnings for common stock             $      479     $      428     $      361    $      458    $     379

Assets (d)                              $   11,008     $   10,405     $   10,604    $   10,525    $  10,656

Capitalization
  Common stock equity                   $    3,237     $    3,089     $    3,095    $    2,852    $   3,413
  Preferred stock - redemption
   not required                                 59             59             59            59           59
  Long-term debt, net                        3,086          3,048          2,698         3,134        2,162
  Current portion of long-term debt            300              -            600             -          197
  Short-term obligations (c)                    29            438            309           486        1,035
                                        -----------    -----------    -----------   -----------  -----------
   Total capitalization and total debt  $    6,711     $    6,634     $    6,761    $    6,531    $   6,866
                                        ===========    ===========    ===========   ===========  ===========
</TABLE>

(a)  Operating  results and balance  sheet data do not include  information  for
     NCNG, SRS, Monroe Power Company or PVI subsequent to July 1, 2000, the date
     PEC distributed  its ownership  interest in the stock of these companies to
     Progress Energy.
(b)  Operating results include NCNG results for the period July 15, 1999 to July
     1, 2000. Balance sheet data includes NCNG for December 31, 1999.
(c)  Includes notes payable to affiliated  companies,  related to the money pool
     program,  of $25 million  and $48  million at  December  31, 2003 and 2001,
     respectively.
(d)  All periods have been restated for the  reclassification of cost of removal
     and nuclear decommissioning (See Note 3F).

                                       41
<PAGE>

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

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

Management's  Discussion  and Analysis  should be read in  conjunction  with the
Progress Energy Consolidated Financial Statements.

INTRODUCTION

Progress Energy is an integrated  energy company,  with its primary focus on the
end-use and wholesale  electricity  markets.  The Company's  reportable business
segments and their primary operations include:

     o    Progress Energy Carolinas  Electric (PEC Electric) - primarily engaged
          in the generation, transmission,  distribution and sale of electricity
          in portions of North Carolina and South Carolina;

     o    Progress  Energy Florida (PEF) - primarily  engaged in the generation,
          transmission,  distribution  and sale of  electricity  in  portions of
          Florida;

     o    Competitive  Commercial  Operations  (CCO) - engaged  in  nonregulated
          electric generation  operations and marketing  activities primarily in
          the southeastern United States;

     o    Fuels -  primarily  engaged in  natural  gas  production  in Texas and
          Louisiana,  coal mining and related  services,  and the  production of
          synthetic  fuels and  related  services,  both of which are located in
          Kentucky, West Virginia, and Virginia;

     o    Rail  Services  (Rail) - engaged in various  rail and railcar  related
          services in 23 states, Mexico and Canada; and

     o    Other  Businesses  (Other) - engaged  in other  nonregulated  business
          areas,  including  telecommunications  primarily in the eastern United
          States  and  energy  services  operations,   which  do  not  meet  the
          requirements for separate segment reporting disclosure.

In 2003,  the Company  realigned  its  business  segments to reflect the current
management  structure  and assigned new names to the segments to better  reflect
their operations.  For comparative  purposes,  2002 and 2001 segment information
has been restated to align with the 2003 organizational and reporting structure.

Strategy

The  Company's  goals  related  to  its  regulated  utilities  and  nonregulated
businesses are to continue  focusing on achieving  their  financial  objectives,
delivering   excellent  customer   satisfaction  and  continually  striving  for
operational   excellence.   The  target  is  to  maintain  a  business   mix  of
approximately  80% regulated  and 20%  nonregulated  business.  A summary of the
significant  financial  objectives  or issues  impacting  Progress  Energy,  its
regulated utilities and nonregulated  operations are addressed more fully in the
following discussion.

     o    Progress Energy, Inc.

          Progress  Energy has several key  financial  objectives,  the first of
          which is to achieve  operating  cash flows  sufficient to meet planned
          capital  expenditures  and support its current  dividend  policy.  Any
          excess cash flow would be used for debt  reduction,  primarily  at the
          holding  company.  In addition,  the Company seeks to achieve earnings
          growth  through  its core  regulated  utility  businesses  and through
          improving  returns at its  nonregulated  businesses.  The Company also
          seeks to maintain ready access to credit markets.

          The  ability to meet these  objectives  is  largely  dependent  on the
          earnings and cash flows of its two regulated utilities.  The regulated
          utilities contributed $787 million of net income and produced over 90%
          of  consolidated  cash  flow from  operations  in 2003.  In  addition,
          synthetic fuel income of $200 million also  contributed  significantly
          to net  income.  Partially  offsetting  the  net  income  contribution
          provided by the regulated  utilities and synthetic fuels was a loss of
          $236  million  recorded at  Corporate,  primarily  related to interest
          expense.   While  the  Company's  synthetic  fuel  operations  provide
          significant  earnings,  the  significant  amount of cash flow benefits
          from synthetic fuels will come in the future when deferred tax credits
          ultimately  are  utilized.  Credits  generated  but not  utilized  are

                                       42
<PAGE>

          carried forward  indefinitely  as alternative  minimum tax credits and
          will provide  positive cash flow when utilized.  At December 31, 2003,
          deferred  credits were $659 million.  The Company does not  anticipate
          any significant acquisitions in the near term.

          Progress  Energy  reduced  its debt to total  capitalization  ratio to
          58.9% at the end of 2003 as compared to 61.3% at the end of 2002.  The
          Company  expects  to  continue  to  improve  this ratio as it plans to
          reduce  total  debt  through  growth  in  operating  cash  flow  after
          dividends,  ongoing  equity  issuances  and with  proceeds  from asset
          sales.  The Company expects capital  expenditures to be  approximately
          $1.3 billion in 2004 and in 2005.

          Progress Energy continues to maintain investment grade credit ratings,
          despite a ratings  downgrade  in 2003 by both  Moody's and  Standard &
          Poor's.  Both these ratings  agencies  upgraded the Company's  outlook
          from   "negative"  to  "stable"  in  2003.  The  downgrades  have  not
          materially  affected Progress Energy's access to liquidity or the cost
          of its short-term borrowings.

     o    Regulated Utilities

          The regulated  utilities earnings and operating cash flows are heavily
          influenced by weather, the economy,  demand for electricity related to
          customer growth, actions of regulatory agencies and cost controls.

          Both PEC Electric and PEF operate in retail service  territories  that
          are forecast to have income and population growth higher than the U.S.
          average.  New  housing  starts  in both  these  territories  are  also
          expected to exceed the U.S. average. In recent years, lower industrial
          sales, primarily at PEC Electric and mainly related to weakness in the
          textile sector,  have negatively impacted earnings growth. The Company
          does not expect any significant improvement in industrial sales in the
          near term. These combined  factors,  and assuming normal weather,  are
          expected to contribute to approximately  2%-3% annual KWh sales growth
          at  the  utilities  through  at  least  2006.  The  Company  does  not
          anticipate any  significant  additional  generation  expansion to meet
          this growth other than the  previously  planned 500 MW  combined-cycle
          unit at PEF in 2005.

          PEC  Electric  and PEF  continue  to  monitor  progress  toward a more
          competitive environment.  No retail electric restructuring legislation
          has been introduced in the jurisdictions in which PEC Electric and PEF
          operate and both operate under rate  agreements.  As part of the Clean
          Smokestacks  bill in North  Carolina and an agreement  with the Public
          Service  Commission  of  South  Carolina  (SCPSC),   PEC  Electric  is
          operating  under a rate freeze in North  Carolina  through  2007 and a
          rate cap in South Carolina through 2005. PEF is operating under a rate
          agreement in Florida  through 2005. See Note 7 of the Progress  Energy
          Consolidated  Financial  Statements  for  further  discussion  of  the
          utilities' rates.

          The utilities will continue to exercise strong financial discipline as
          it relates to  controlling  operation  and  maintenance  costs despite
          expected  increases in  benefit-related  costs and insurance  expense.
          Operating  cash flows are expected to be more than  sufficient to fund
          capital spending in 2004 and in 2005.

     o    Nonregulated businesses

          The  Company's  primary  nonregulated  businesses  are CCO,  Fuels and
          Progress Rail.

          Cash flows and earnings of the  nonregulated  businesses  are impacted
          largely by the ability to obtain  additional  term  contracts  or sell
          energy on the spot market at favorable  terms, the volume of synthetic
          fuel produced and tax credits utilized, and volumes and prices of both
          coal and natural gas sales.

          Progress Energy expects an excess of supply in the wholesale  electric
          energy market for the next several  years.  During 2003, CCO completed
          the build out of its  nonregulated  generation  assets  bringing CCO's
          total capacity to 3,100 MW. The Company has no current plans to expand
          its  portfolio  of  nonregulated  generating  plants.  The Company has
          contracts for planned  production  capacity of 85% in 2004 and 50% for
          both 2005 and 2006. CCO will continue to seek to secure term contracts
          with load-serving entities to utilize its excess capacity.

          Fuels will continue to develop its natural gas  production  asset base
          both as a  long-term  economic  hedge for the  Company's  nonregulated
          generation  fuel needs and to obtain a meaningful  presence in natural
          gas markets that will allow it to provide  attractive  returns for the
          Company's shareholders. In 2004, Fuels anticipates that, with budgeted
          capital expenditures, it will have a 25% increase in gas production.

                                       43
<PAGE>

          The Company's  majority-owned  synthetic fuel entities  participate in
          the Internal Revenue Service (IRS) Prefiling  Agreement (PFA) program.
          The PFA program is a program  that  allows  taxpayers  to  voluntarily
          accelerate  the IRS  exam  process  in  order  to seek  resolution  of
          specific issues.  The Company has resolved certain issues with the IRS
          and is  continuing  to work  with  the IRS to  resolve  any  remaining
          issues.  The Company  cannot  predict  when the exam  process  will be
          completed or the final  resolution of any outstanding  matters.  These
          facilities  have  private  letter  rulings  (PLRs)  from  the IRS with
          respect to their synthetic fuel operations. The Company has no current
          plans to alter its synthetic fuel  production  schedule as a result of
          these matters.  The Company plans to produce  approximately 11 million
          to 12 million tons of  synthetic  fuel in 2004.  Through  December 31,
          2003,  the Company had generated  $1,243 million of synthetic fuel tax
          credits  to  date  (including  FPC  prior  to the  acquisition  by the
          Company).  See additional  discussion at Synthetic Fuel Tax Credits in
          the OTHER MATTERS  section below and at Note 14 to the Progress Energy
          Consolidated Financial Statements.

          Progress Energy  continues to look for  opportunities to divest of its
          Progress Rail  subsidiary at an opportune time as it is not considered
          part of its core business strategy in the future.  The Company expects
          to accomplish the divestiture within the next three years.

Progress Energy and its consolidated  subsidiaries are subject to various risks.
For a complete discussion of these risks see the Risk Factors section.

RESULTS OF OPERATIONS

FOR 2003 AS COMPARED TO 2002 AND 2002 AS COMPARED TO 2001

In this section,  earnings and the factors affecting earnings are discussed. The
discussion  begins  with a  summarized  overview of the  Company's  consolidated
earnings  which is  followed  by a more  detailed  discussion  and  analysis  by
business segment.

PROGRESS ENERGY

In 2003, Progress Energy's net income was $782 million, a 48% increase from $528
million in 2002.  Income from continuing  operations before cumulative effect of
changes in accounting principles and discontinued operations was $811 million in
2003, a 47% increase  from $552 million in 2002.  Net income for 2003  increased
compared to 2002 primarily due to the inclusion in 2002 of an impairment of $265
million  after-tax  related  to  assets  in  the   telecommunications  and  rail
businesses. The Company recorded impairments of $23 million after-tax in 2003 on
an investment  portfolio and on long-lived assets. The increase in net income in
2003 of $12 million, excluding the impairments, is primarily due to:

o    An increase in retail customer growth at the utilities.
o    Growth in natural gas production and sales.
o    Higher synthetic fuel sales.
o    Absence of severe storm costs incurred in 2002.
o    Lower loss recorded in 2003 related to the sale of NCNG,  with the majority
     of the loss on the sale being recorded in 2002.
o    Lower interest charges in 2003.

Partially offsetting these items were the:
o    Net impact of the 2002 Florida Rate settlement.
o    Impact of the change in the fair value of the CVOs.
o    Milder weather in 2003 as compared to 2002.
o    Increased benefit-related costs.
o    Higher  depreciation  expense  at  both  utilities  and the  Fuels  and CCO
     segments.
o    The impact of changes in accounting principles in 2003.

Each of these items is discussed  further in the results of  operations  for the
segments below.

Basic earnings per share from net income  increased from $2.43 per share in 2002
to $3.30 per share in 2003 in part due to the factors  outlined above.  Dilution
related to a November 2002 equity  issuance of 14.7 million shares and issuances
under the Company's Investor Plus and employee benefit programs in 2002 and 2003
also reduced basic earnings per share by $0.33 in 2003.

                                       44
<PAGE>

Net income in 2002 decreased 2.6% from $542 million in 2001. The decrease in net
income in 2002 is primarily due to impairments  and other charges related to the
telecommunications and rail business operations,  the discontinued operations of
NCNG,  the rate case  settlement  of PEF, PEC severe  storm costs and  increased
benefit costs.  Partially  offsetting these items were continued customer growth
and usage at the utilities,  lower  depreciation at PEF, 2001 impairments in the
telecommunications  and SRS business  units,  the impact of the change in market
value of CVOs and the elimination of goodwill amortization in 2002.

The Company's segments contributed the following profit or loss from continuing
operations for 2003, 2002 and 2001:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

--------------------------------------------------------------------------------------------------------------------
(in millions)
--------------------------------------------------------------------------------------------------------------------
                                                       2003          Change        2002       Change      2001
--------------------------------------------------------------------------------------------------------------------
PEC Electric                                           $   515       $   2        $ 513       $  45      $ 468
PEF                                                        295         (28)         323          14        309
Fuels                                                      235          59          176         (23)       199
CCO                                                         20          (7)          27          23          4
Rail Services                                               (1)         41          (42)        (30)       (12)
Other                                                      (17)        226         (243)        (81)      (162)
                                                   -----------------------------------------------------------------
    Total Segment Profit (Loss)                        $ 1,047       $ 293        $ 754       $ (52)     $ 806
Corporate                                                 (236)        (34)        (202)         63       (265)
                                                   -----------------------------------------------------------------
    Total Income from Continuing Operations            $   811       $ 259        $ 552       $  11      $ 541
Discontinued Operations, Net of Tax                         (8)         16          (24)        (25)         1
Cumulative Effect of Changes in Accounting
    Principles                                             (21)        (21)           -           -          -
                                                   -----------------------------------------------------------------
Net Income                                             $   782       $ 254        $ 528       $ (14)     $ 542
--------------------------------------------------------------------------------------------------------------------
</TABLE>

PROGRESS ENERGY CAROLINAS ELECTRIC

PEC Electric contributed segment profits of $515 million,  $513 million and $468
million in 2003, 2002 and 2001, respectively.  The slight increase in profits in
2003,  when  compared to 2002,  was  primarily  due to customer  growth,  strong
wholesale  sales  during  the  first  quarter  of 2003,  lower  Service  Company
allocations and lower interest costs,  which were offset by unfavorable  weather
in 2003, higher depreciation  expense and increased  benefit-related  costs. The
increase in profits in 2002, when compared to 2001, was attributable to customer
growth,  favorable weather in 2002, lower interest charges and the allocation of
tax benefits from the holding company  partially offset by severe storm costs in
December 2002.

Revenues

PEC Electric's electric revenues for the years ended December 31, 2003, 2002 and
2001 and the percentage change by year and by customer class are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

-------------------------------------------------------------------------------------------------
(in millions)
-------------------------------------------------------------------------------------------------
Customer Class                        2003      % Change      2002       % Change       2001
-------------------------------------------------------------------------------------------------
Residential                         $ 1,259        1.5%     $ 1,241         7.7%     $ 1,152
Commercial                              850        2.2          832         6.0          785
Industrial                              636       (1.4)         645        (1.4)         654
Governmental                             79        1.3           78         4.0           75
                                 -------------             -------------            -------------
    Total Retail Revenues             2,824        1.0        2,796         4.9        2,666
Wholesale                               687        5.5          651         2.7          634
Unbilled                                (6)         -            15          -           (32)
Miscellaneous                            84        9.1           77         1.3           76
                                 -------------             -------------            -------------
    Total Electric Revenues         $ 3,589        1.4%     $ 3,539         5.8%     $ 3,344
-------------------------------------------------------------------------------------------------
</TABLE>

                                       45
<PAGE>

PEC Electric's  electric energy sales for 2003, 2002 and 2001 and the percentage
change by year and by customer class are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

---------------------------------------------------------------------------------------------------
(in thousands of MWh)
---------------------------------------------------------------------------------------------------
         Customer Class               2003       % Change       2002        % Change       2001
---------------------------------------------------------------------------------------------------
Residential                          15,283        0.3%         15,239         6.0%       14,372
Commercial                           12,557        0.7          12,468         4.1        11,972
Industrial                           12,749       (2.6)         13,089        (1.8)       13,332
Governmental                          1,408       (2.0)          1,437         1.0         1,423
                                 -------------             --------------             -------------
    Total Retail Energy Sales        41,997       (0.6)         42,233         2.8        41,099
Wholesale                            15,518        3.3          15,024        15.6        12,996
Unbilled                               (44)         -              270          -           (534)
                                 -------------             --------------             -------------
    Total MWh Sales                  57,471       (0.1%)        57,527         7.4%       53,561
---------------------------------------------------------------------------------------------------
</TABLE>

PEC Electric's revenues, excluding recoverable fuel revenues of $901 million and
$851 million in 2003 and 2002,  respectively,  were unchanged from 2002 to 2003.
Milder weather in 2003, when compared to 2002 accounted for a $61 million retail
revenue reduction. While heating degree days were 4.8% above prior year, cooling
degree days were 25.2% below prior year. However, the more severe weather in the
northeast  region of the United  States during the first quarter of 2003 drove a
$19 million increase in wholesale revenues. Additionally, retail customer growth
in 2003  generated an additional $42 million of revenues in 2003. PEC Electric's
retail customer base increased as approximately  23,000 new customers were added
in 2003.

PEC's electric revenues, excluding recoverable fuel revenues of $851 million and
$734 million in 2002 and 2001, respectively, increased $78 million. During 2002,
residential  and commercial  sales reflected  continued  growth in the number of
customers  served by PEC Electric,  with  approximately  26,000 new customers in
2002.  Sales of energy and revenue  increased  in 2002  compared to 2001 for all
customer  classes  except  industrial.  Increases in retail sales and  wholesale
sales were also driven by favorable  weather  during 2002 when compared to 2001.
Wholesale  sales growth was partially  offset by price declines in the wholesale
market.

Downturns in the economy during 2001, 2002 and 2003 impacted energy usage within
the  industrial  customer  class.  Total  industrial  revenues,  excluding  fuel
revenues,  declined  during  2003 when  compared  to 2002 and  during  2002 when
compared to 2001 by $13 million and $24 million,  respectively, as the number of
industrial  customers  decreased due to a slowdown in the textile  industry,  as
well as a decrease in usage in the chemical industry.

Expenses

Fuel and  Purchased  Power
Fuel expense  increased  $73 million in 2003,  when  compared to $752 million in
2002, primarily due to higher prices incurred for coal, oil and natural gas used
during  generation.  Costs for fuel per Btu increased for all three  commodities
during the year.  See movement in prices under Average Fuel Cost Summary in Part
I, Item 1, PEC Electric - Fuel and Purchased Power.  Fuel expense increased $114
million in 2002, when compared to $638 million in 2001, primarily due to an 8.2%
increase in generation with a higher  percentage of generation being produced by
combustion turbines, which have higher fuel costs.

Purchased  power expense  decreased  $51 million in 2003,  when compared to $347
million  in 2002,  mainly due to a decrease  in the volume  purchased  as milder
weather  reduced  system  requirements  and  due to the  renegotiation  at  more
favorable  terms of two  contracts  that  expired  during  the  year.  For 2002,
purchased  power  decreased $7 million,  when  compared to $354 million in 2001,
mainly due to decreases in prices and volumes purchased.

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

Operations and Maintenance (O&M)
O&M expense decreased $20 million in 2003 when compared to $802 million in 2002.
O&M expense in 2002  included  severe  storm costs of $27  million.  Those costs
along with lower 2003 Service  Company  allocations  of $16 million,  due to the
change in allocation  methodology  as required by the SEC in early 2003, are the
primary reasons for decreased O&M expenses.  This decrease was partially  offset
by higher  benefit-related costs of $21 million. PEC Electric incurred O&M costs
of $25 million related to three severe storms in 2003. The NCUC allowed deferral
of $24 million of these storm  costs.  These  costs are being  amortized  over a
five-year  period,  beginning  in the months the  expenses  were  incurred.  PEC
Electric  amortized  $3 million  of these  costs in 2003  which is  included  in
depreciation and amortization expense on the Consolidated Income Statement.

                                       46
<PAGE>

O&M expense  increased $91 million in 2002 when compared to $711 million in 2001
primarily  due to the 2002 storm costs of $27 million,  which were not deferred.
O&M expense in 2002,  when compared to 2001, was also  negatively  impacted by a
lower pension credit of $6 million, the establishment of an inventory reserve of
$11 million for materials that have no future  benefit,  increased  salaries and
benefits and other increases in maintenance and outage support.

Depreciation and Amortization
Depreciation  and  amortization  increased $38 million in 2003, when compared to
$524  million in 2002.  Depreciation  and  amortization  increased  $74  million
related to the 2003 impact of the Clean Air  legislation  in North  Carolina and
decreased  $53  million  related to the 2002 impact of the  accelerated  nuclear
amortization  program.  Both  programs  are  approved  by the  state  regulatory
agencies and are  discussed  further at Notes 7 and 21E to the  Progress  Energy
Consolidated  Financial  Statements.  In addition,  depreciation  increased  $19
million due to additional assets placed into service.

Depreciation and amortization increased $2 million in 2002 when compared to $522
million in 2001. PEC Electric  recorded $53 million of accelerated  amortization
expense in 2002 and $75  million in 2001  related  to the  nuclear  amortization
program. The year-over-year  favorability was offset by additional  depreciation
recognized  in 2002,  as  compared  to 2001,  on new assets  that were placed in
service during 2002.

PEC filed a new  depreciation  study in 2004 that provides  support for reducing
depreciation  expense  on an annual  basis by  approximately  $45  million.  The
reduction  is  primarily   attributable   to  assumption   changes  for  nuclear
generation,  offset by  increases  for  distribution  assets.  The new rates are
primarily effective January 1, 2004.

Interest Expense
Net interest  expense was $194  million,  $212 million and $241 million in 2003,
2002 and 2001, respectively.  Declines in interest expense resulted from reduced
short-term debt and refinancing  certain long-term debt with lower interest rate
debt.

Income Tax Expense
In 2003 and 2002, $24 million and $35 million,  respectively, of the tax benefit
that was previously  held at the Company's  holding company was allocated to PEC
Electric.  As  required  by an SEC order  issued in 2002,  holding  company  tax
benefits are allocated to profitable subsidiaries.  Other fluctuations in income
taxes are primarily due to changes in pretax income.

PROGRESS ENERGY FLORIDA

PEF contributed  segment profits of $295 million,  $323 million and $309 million
in 2003,  2002 and 2001,  respectively.  The  decrease in profits in 2003,  when
compared  to  2002,  was  primarily  due to the  impact  of the 2002  rate  case
stipulation,  higher  benefit-related  costs primarily related to higher pension
expense,  higher  depreciation  and the  unfavorable  impact of  weather.  These
amounts were partially  offset by continued  customer  growth and lower interest
charges.  The increase in profits in 2002, when compared to 2001, was attributed
to the impact of milder weather in 2001 as compared to 2002,  continued customer
growth and the allocation of tax benefits from the holding company.  These items
were partially offset by the impact of the 2002 rate case stipulation, increased
benefits  costs and lower  pension  credit and  higher  system  reliability  and
enhancement spending.

PEF's  profits in 2003 and 2002 were  affected  by the  outcome of the rate case
stipulation,  which  included a one-time  retroactive  revenue refund in 2002, a
decrease  in retail  rates of 9.25%  (effective  May 1,  2002),  provisions  for
revenue  sharing  with  the  retail  customer  base,   lower   depreciation  and
amortization  and increased  service revenue rates.  See Note 7B to the Progress
Energy Consolidated Financial Statements for further discussion of the rate case
settlement.

                                       47
<PAGE>

Revenues

PEF's electric revenues for the years ended December 31, 2003, 2002 and 2001 and
the percentage  change by year and by customer  class,  as well as the impact of
the rate case settlement on revenue, are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

------------------------------------------------------------------------------------------------
(in millions)
------------------------------------------------------------------------------------------------
Customer Class                           2003     % Change         2002    % Change       2001
------------------------------------------------------------------------------------------------
Residential                            $ 1,691       2.8%        $ 1,645      0.1%      $ 1,643
Commercial                                 740       1.2             731     (3.1)          754
Industrial                                 219       3.8             211     (5.4)          223
Governmental                               181       4.6             173     (1.7)          176
Revenue Sharing Refund                     (35)       -               (5)      -              -
Retroactive Retail Rate Refund               -        -              (35)      -              -
                                     ----------              ------------            -----------
    Total Retail Revenues                2,796       2.8           2,720     (2.7)        2,796
Wholesale                                  227      (1.3)            230    (20.1)          288
Unbilled                                    (2)       -               (3)      -            (22)
Miscellaneous                              131      13.9             115    (23.8)          151
                                     ----------              ------------            -----------
    Total Electric Revenues            $ 3,152       2.9%        $ 3,062     (4.7)%     $ 3,213
------------------------------------------------------------------------------------------------
</TABLE>

PEF's electric energy sales for the years ended December 31, 2003, 2002 and 2001
and the percentage change by year and by customer class are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

--------------------------------------------------------------------------------------------
(in thousands of MWh)
--------------------------------------------------------------------------------------------
Customer Class                       2003     % Change       2002      % Change      2001
--------------------------------------------------------------------------------------------
Residential                         19,429       3.6%       18,754       6.5%       17,604
Commercial                          11,553       1.2        11,420       3.2        11,061
Industrial                           4,000       4.3         3,835      (1.0)        3,872
Governmental                         2,974       4.4         2,850       4.5         2,726
                                 ----------             -----------            -----------
    Total Retail Energy Sales       37,956       3.0        36,859       4.5        35,263
Wholesale                            4,323       3.4         4,180     (11.4)        4,719
Unbilled                               233        -              5        -           (511)
                                 ----------             -----------            -----------
    Total MWh Sales                 42,512       3.6%       41,044       4.0%       39,471
--------------------------------------------------------------------------------------------
</TABLE>

PEF's revenues,  excluding fuel revenues of $1,487 million and $1,402 million in
2003 and 2002,  respectively,  increased $5 million from 2002 to 2003.  Revenues
were  favorably  impacted  by $49  million  in 2003,  primarily  as a result  of
customer growth (approximately 36,000 additional customers).  In addition, other
operating  revenues were favorable $16 million due primarily to higher  wheeling
and  transmission  revenues and higher service charge  revenues  (resulting from
increased  rates allowed under the 2002 rate  settlement).  These increases were
partially offset by the negative impact of the rate settlement,  which decreases
revenues,  lower  wholesale  sales and the impact of  unfavorable  weather.  The
provision for revenue  sharing  increased $12 million in 2003 compared to the $5
million provision  recorded in 2002.  Revenues in 2003 were also impacted by the
final  resolution of the 2002 revenue  sharing  provisions as the FPSC issued an
order in July of 2003 that required PEF to refund an  additional  $18 million to
customers  related  to 2002.  The  9.25%  rate  reduction  from  the  settlement
accounted for an additional $46 million decline in revenues.  The 2003 impact of
the rate  settlement  was  partially  offset by the  absence  of the prior  year
interim rate refund of $35 million.  Lower  wholesale  revenues  (excluding fuel
revenues)  of $17  million  and the $8  million  impact of milder  weather  also
reduced base revenues during 2003.

PEF's revenues,  excluding fuel revenues of $1,402 million and $1,453 million in
2002 and 2001,  respectively,  decreased  $100  million  from 2001 to 2002.  The
revenue  declines  were  driven by the $119  million  impact  of the rate  case,
comprised of a $35 million one-time  retroactive  refund, a $79 million decrease
due to the  rate  reduction,  and an  estimated  revenue  sharing  refund  of $5
million. Additionally, wholesale revenues (excluding fuel revenues) declined $12
million,  driven  primarily by a contract  that was not renewed.  Year-over-year
comparisons were also unfavorably  impacted by the recognition of $63 million of
revenue deferred from 2000 to 2001. Partially offsetting the unfavorable revenue
impacts was customer growth  (approximately  33,000 additional  customers),  the
impact of weather conditions, primarily a warmer than normal summer in 2002, and
an increase in other operating revenue,  resulting primarily from higher service
charge revenues (resulting from increased rates allowed under the 2002 rate case
settlement), along with higher transmission and wheeling revenues.

                                       48
<PAGE>

Expenses

Fuel and Purchased Power
Fuel used in generation and purchased  power  increased $87 million in 2003 when
compared  to $1,349  million in 2002.  The  increase  is due to higher  costs to
generate electricity and higher purchased power costs as a result of an increase
in volume due to system requirements and higher natural gas prices.

Fuel used in generation and purchased  power totaled $1,349 million for the year
ended  December 31,  2002, a decrease of $71 million from 2001.  The decrease is
primarily  due  to a  lower  recovery  of  fuel  expense  that  resulted  from a
mid-course  correction of PEF's fuel cost recovery  clause,  as part of the rate
settlement,  and lower purchased power costs, partially offset by an increase in
coal prices and volume from high system requirements.

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

Operations and Maintenance (O&M)
O&M expense  increased $49 million,  when compared to $591 million in 2002.  The
increase is largely related to increases in certain benefit-related  expenses of
$36 million,  which consisted primarily of higher pension expense of $27 million
and  higher  operational  costs  related  to the CR3  nuclear  outage  and plant
maintenance.

O&M expense increased $96 million in 2002 when compared to $495 million in 2001,
due  primarily  to a reduced  pension  credit of $31  million,  increased  costs
related to the  Commitment to Excellence  program of $11 million and an increase
in other salary and benefit costs of $22 million related  partially to increased
medical  costs.  The  Commitment to Excellence  program was initiated in 2002 to
improve service and reliability.

Depreciation and Amortization
Depreciation  and  amortization  increased  $12 million in 2003 when compared to
$295 million in 2002. Depreciation increased primarily as a result of additional
assets  being  placed  into  service  that  were   partially   offset  by  lower
amortization  of the Tiger Bay regulatory  asset of $2 million,  which was fully
amortized in September 2003.

Depreciation  and  amortization  decreased $158 million in 2002 when compared to
$453 million in 2001. In addition to the depreciation and amortization reduction
of approximately $79 million related to the rate case,  depreciation declined an
additional  $97 million  related to  accelerated  amortization  on the Tiger Bay
regulatory  asset,  which was  created as a result of the early  termination  of
certain  long-term  cogeneration  contracts.  See Note 7D to the Progress Energy
Consolidated  Financial  Statements  for further  details on the rate case.  PEF
amortized the regulatory asset according to a plan approved by the FPSC in 1997.

Interest Expense
Interest charges  decreased $15 million in 2003 compared to $106 million in 2002
primarily  due to the reversal of a regulatory  liability  for accrued  interest
related to previously resolved tax matters.

Income Tax Expense
In 2003 and 2002, $13 million and $20 million,  respectively, of the tax benefit
that was previously held at the Company's  holding company was allocated to PEF.
As required by an SEC order  issued in 2002,  holding  company tax  benefits are
allocated to profitable  subsidiaries.  Other  fluctuations  in income taxes are
primarily due to changes in pretax income.

DIVERSIFIED BUSINESSES

The  Company's  diversified  businesses  consist of the Fuels  segment,  the CCO
segment,  the Rail  Services  segment  and the  Other  segment,  which  consists
primarily of the energy services operations and telecommunications operations.

                                       49
<PAGE>

FUELS

Fuels' segment profits increased $59 million in 2003 as compared to $176 million
in 2002 primarily due to an increase in synthetic fuel earnings,  higher natural
gas earnings from increased natural gas prices,  the addition of North Texas Gas
operations in March 2003 and the addition of  Westchester  in April 2002.  These
results were partially offset by an asset  impairment  during the fourth quarter
of $11 million  after-tax at the Kentucky May Coal Company.  Fuels' 2002 profits
as  compared  to 2001  decreased  $23  million  primarily  as a result  of lower
synthetic fuel production,  which was partially offset by increased  natural gas
revenues as a result of the Westchester acquisition.

Fuels contributed segment profits of $235 million, $176 million and $199 million
in 2003, 2002 and 2001,  respectively.  The following  summarizes Fuels' segment
profits for the years ended December 31, 2003, 2002 and 2001:

---------------------------------------------------------------------
(in millions)                           2003        2002        2001
---------------------------------------------------------------------
Synthetic fuel operations              $ 200       $ 156       $ 185
Natural gas operations                    34          10           5
Coal fuel and other operations             1          10           9
                                  -----------------------------------
         Segment profits               $ 235       $ 176       $ 199
---------------------------------------------------------------------

Synthetic Fuel Operations

Synthetic fuel operations  generated  profits of $200 million,  $156 million and
$185  million,  respectively,  for the years ended  December 31, 2003,  2002 and
2001. The production and sale of the synthetic fuel generate  operating  losses,
but qualify for tax credits under Section 29, which more than offset the effects
of such losses.  See "Synthetic Fuels Tax Credits" under OTHER MATTERS below for
additional  discussion  of these tax  credits.  The  operations  resulted in the
following losses (prior to tax credits) and tax credits for 2003, 2002 and 2001:

----------------------------------------------------------------------
(in millions)                                 2003      2002      2001
----------------------------------------------------------------------
Tons sold                                     12.4      11.2      13.3

After-tax losses (excluding tax credits)    $ (145)   $ (135)   $ (164)
Tax credits                                    345       291       349
                                          ----------------------------
     Net Profit                             $  200    $  156    $  185
----------------------------------------------------------------------

Synthetic  fuels' net  profits  for 2003  increased  as  compared to 2002 due to
higher  sales,  improved  margins and a higher tax credit per ton.  The 2003 tax
credits also include a $12.7 million favorable true-up from 2002.  Additionally,
synthetic  fuels'  results  in 2003  include  13 months of  operations  for some
facilities.  Prior to the  fourth  quarter of 2003,  results of these  synthetic
fuels'  operations had been  recognized one month in arrears.  The net impact of
this action  increased net income by $2 million for the year.  Synthetic  fuels'
net profits  decreased in 2002  compared to 2001 due to lower  sales.  Synthetic
fuels' net  profits  decreased  $29 million in 2002 when  compared to 2001.  The
decrease in profits was  primarily  due to a decline in tons  produced as severe
storm costs  incurred at one of the utilities  reduced the Company's  ability to
use the tax credits generated from production.

Natural Gas Operations

Natural gas  operations  generated  profits of $34  million,  $10 million and $5
million for the years ended December 31, 2003, 2002 and 2001, respectively.  The
increase in production and price resulting from the  acquisitions of Westchester
in 2002 and North Texas Gas in the first quarter of 2003 drove increased revenue
and  earnings  in 2003 as  compared  to 2002.  In October of 2003,  the  Company
completed  the  sale  of  certain   gas-producing   properties   owned  by  Mesa
Hydrocarbons,  LLC.  See  Notes  4 and 3C to the  Progress  Energy  Consolidated
Financial  Statements for discussions of the Westchester and the North Texas Gas
acquisitions  and the Mesa  disposition.  The  increase in profits of $5 million
from 2001 to 2002 is due to an increase in gas  production of 49% as a result of
the  Westchester  acquisition  in April of 2002.  The following  summarizes  the
production and revenues of the natural gas operations for 2003, 2002 and 2001 by
facility:

                                       50
<PAGE>

----------------------------------------------------------------
                                         2003     2002     2001
----------------------------------------------------------------
      Production in Bcf equivalent
Mesa                                      4.8      6.0      8.3
Westchester                              13.5      5.8        -
North Texas Gas                           7.1        -        -
                                      --------------------------
    Total Production                     25.4     11.8      8.3
                                      --------------------------

        Revenues in millions
Mesa                                    $  13     $ 15     $ 18
Westchester                                65       24        -
North Texas Gas                            38        -        -
                                      --------------------------
    Total Revenues                      $ 116     $ 39     $ 18
                                      --------------------------

           Gross Margin
In millions of $                        $  91     $ 29     $ 15
As a % of revenues                         78%      74%      83%
----------------------------------------------------------------

Coal Fuel and Other Operations

Coal fuel and other operations  generated profits of $1 million, $10 million and
$9 million,  respectively, for the years ended December 31, 2003, 2002 and 2001.
Coal fuel and other operations segment profits decreased $9 million from 2002 to
2003. The decrease is due primarily to the recording of an impairment of certain
assets at the  Kentucky  May Coal  Mine  totaling  $11  million  after-tax.  See
discussion of impairment  recorded in Note 9 to the Progress Energy Consolidated
Financial Statements.

COMPETITIVE COMMERCIAL OPERATIONS

CCO generates and sells  electricity to the wholesale  market from  nonregulated
plants. These operations also include marketing activities.

CCO's operations  generated  segment profits of $20 million,  $27 million and $4
million  in 2003,  2002 and  2001,  respectively.  CCO's  operations  were  most
significantly  impacted by placing additional generating capability into service
in 2002 and 2003. The following summarizes the annual revenues, gross margin and
segment profits from the CCO plants:

--------------------------------------------------------
(in millions)                2003      2002        2001
--------------------------------------------------------
Total revenues              $ 170     $  92       $  16
Gross margin
   In millions of $         $ 141     $  83       $  14
   As a % of revenues          83%       90%         87%
Segment profits             $  20     $  27       $   4
--------------------------------------------------------

The  increase in revenue  for 2003 when  compared  to 2002 is  primarily  due to
increased contracted capacity on newly constructed plants, energy revenue from a
new, full-requirements power supply contract and a tolling agreement termination
payment received during the first quarter.  Generating  capacity  increased from
1,554  megawatts at December  31, 2002 to 3,100  megawatts at December 31, 2003,
with the Effingham,  Rowan Phase 2 and Washington plants being placed in service
in 2003.  In the second  quarter of 2003,  PVI  acquired  from  Williams  Energy
Marketing and Trading a full-requirements power supply agreement with Jackson in
Georgia for $188 million,  which resulted in additional  revenues of $21 million
when  compared to the same  periods in 2002.  The revenue  increases  related to
higher  volumes  were  partially  offset  by  higher  depreciation  costs of $22
million, increased interest charges of $16 million and other fixed charges.

The  increase in revenues  from 2001 to 2002 is due to the  increase in capacity
during the year.  In 2001  operations  included  one  nonregulated  plant with a
315-megawatt  capacity and, at the end of 2002,  plants with 1,554  megawatts of
capacity were  operational.  The increase in capacity was due to the transfer of
one plant from PEC  Electric,  the purchase of one  operational  plant from LG&E
Energy  Corp.  (See  Note  4D to  the  Progress  Energy  Consolidated  Financial
Statements)  and one additional  plant being placed in service.  The increase in
capacity drove the increase in net income.  The earnings potential was offset by
general softness in the energy market in 2002.

                                       51
<PAGE>

The Company has contracts  representing 85%, 50%, and 50% of planned  production
capacity for 2004 through 2006,  respectively.  The Company is actively pursuing
opportunities  with  current  customers  and other  potential  new  customers to
utilize its excess capacity.

RAIL SERVICES

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

Rail contributed losses of $1 million, $42 million and $12 million for the years
ended  December  31,  2003,  2002 and 2001,  respectively.  The net loss in 2002
includes a $40 million  after-tax  estimated  impairment of assets held for sale
related to Railcar Ltd., a leasing  subsidiary of Progress  Rail. In March 2003,
the  Company  signed a letter of intent to sell the  majority  of  Railcar  Ltd.
assets  to The  Andersons,  Inc.  The asset  purchase  agreement  was  signed in
November 2003 and the transaction  closed on February 12, 2004. As such,  assets
of Railcar Ltd. have been  reported as assets held for sale.  See Note 3B to the
Progress Energy Consolidated Financial Statements for discussion of this planned
divestiture.  Excluding the impairment  recorded in 2002,  profits for Rail were
flat year over year 2003 compared to 2002.  Earnings for Rail  increased in 2002
compared  to  2001,  excluding  the $40  million  impairment  booked  in 2002 as
discussed  above.  Rail  Services'  2002  results  were  favorably  impacted  by
aggressive  cost  cutting,   new  business   opportunities   and   restructuring
initiatives.  Rail Services'  results for both years were affected by a downturn
in the overall  economy  and  decreases  in rail  service  procurement  by major
railroads.  A downturn in the domestic  scrap market also impacted Rail Services
results for 2002.

An SEC order  approving  the  merger of FPC  required  the  Company to divest of
Progress  Rail by November 30, 2003.  However,  the SEC has granted an extension
until 2006.

OTHER

Progress   Energy's   Other  segment   includes  the   operations  of  SRS,  the
telecommunications operations of PTC and Caronet and the operation of nonutility
subsidiaries of PEC. SRS is engaged in providing  energy services to industrial,
commercial and institutional customers to help manage energy costs and currently
focuses its  activities in the  southeastern  United  States.  Telecommunication
operations provide broadband capacity services, dark fiber and wireless services
in Florida and the eastern  United  States.  In December  2003, PTC and Caronet,
both  wholly-owned  subsidiaries  of Progress  Energy,  and EPIK, a wholly-owned
subsidiary  of  Odyssey,  contributed  substantially  all of  their  assets  and
transferred certain  liabilities to PTC LLC, a subsidiary of PTC.  Subsequently,
the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash,
and Caronet  became an indirect  wholly-owned  subsidiary of Odyssey.  Following
consummation of all the transactions  described above, PTC holds a 55% ownership
interest  in,  and is the  parent of,  PTC LLC.  Odyssey  holds a  combined  45%
ownership interest in PTC LLC through EPIK and Caronet.  The accounts of PTC LLC
are  included  in the  Company's  Consolidated  Financial  Statements  since the
transaction date.

The Other segment  contributed  segment losses of $17 million,  $243 million and
$162  million,  respectively,  for the years ended  December 31, 2003,  2002 and
2001.  Included in the 2003 segment  losses is an  investment  impairment  of $6
million  after-tax on the  Affordable  Housing  portfolio held by the nonutility
subsidiaries  of PEC. The 2002 segment  losses  include an asset  impairment and
other  charges in the  telecommunications  business of $225  million  after-tax.
Segment  losses in 2001 include an asset and investment  impairment  recorded at
SRS  ($46  million   after-tax)   and   investment   impairments   in  Interpath
Communications,  Inc.  (Interpath) of $102 million after-tax.  See discussion of
impairments at Note 9 of the Progress Energy Consolidated Financial Statements.

                                       52
<PAGE>

CORPORATE SERVICES

Corporate Services  (Corporate)  includes the operations of the holding company,
Progress  Energy  Service  Company  and  other  consolidating  and  nonoperating
entities, as summarized below:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

------------------------------------------------------------------------------------------------
Income (Expense) (in millions)
------------------------------------------------------------------------------------------------
                                      2003        Change       2002        Change       2001
------------------------------------------------------------------------------------------------
Other interest expense              $ (285)      $ (10)      $ (275)       $ (14)      $ (261)
Contingent value obligations            (9)        (37)          28           30           (2)
Tax reallocation                       (38)         18          (56)         (56)           -
Other income taxes                     124          11          113           68           45
Other income (expense)                 (28)        (16)         (12)          35          (47)
                                 -------------             ------------             ------------
     Segment loss                   $ (236)      $ (34)      $ (202)       $  63       $ (265)
------------------------------------------------------------------------------------------------
</TABLE>

Net pre-tax  interest  charges in Corporate were $285 million,  $275 million and
$261 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Interest  expense  increased  $10  million  in 2003  compared  to 2002  due to a
decrease  of $9  million  in the  amount  of  interest  capitalized  related  to
construction at nonregulated  generating  plants,  as construction was completed
and plants were placed in service.  The increase in 2002, when compared to 2001,
was  primarily  related  to  increased  debt  associated  with the  purchase  of
nonregulated generating facilities.  This was partially offset by lower interest
rates and $19 million of interest capitalization in 2002 related to the building
of the nonregulated generating plants.

Progress Energy issued 98.6 million CVOs in connection with the FPC acquisition.
Each CVO  represents  the  right to  receive  contingent  payments  based on the
performance of four  synthetic fuel  facilities  owned by Progress  Energy.  The
payments,  if any,  are based on the net  after-tax  cash  flows the  facilities
generate. At December 31, 2003, 2002, and 2001, the CVOs had a fair market value
of  approximately  $23  million,  $14 million,  and $42  million,  respectively.
Progress Energy recorded  unrealized losses of $9 million and $2 million for the
years ended  December 31, 2003 and 2001,  and an unrealized  gain of $28 million
for the year ended  December  31,  2002 to record  the  changes in fair value of
CVOs,  which had average unit prices of $0.23,  $0.14, and $0.43 at December 31,
2003, 2002 and 2001, respectively.

As required by an SEC order  issued in 2002,  holding  company tax  benefits are
allocated to profitable subsidiaries.  Tax benefits reallocated from the Holding
Company to the profitable  subsidiaries increased Corporate's income tax expense
by $38 million and $56 million in 2003 and 2002.  Other  fluctuations  in income
taxes are primarily due to changes in pretax income.

As part of the acquisition of FPC,  goodwill of  approximately  $3.6 billion was
recorded, and amortization of $90 million was included in other income (expense)
at the  Corporate  segment in 2001. In  accordance  with  Statement of Financial
Accounting  Standards No. 142, "Goodwill and Other Intangible Assets," (SFAS No.
142) effective  January 1, 2002, the Company no longer amortizes  goodwill.  See
Note 8 to the Progress Energy Consolidated Financial Statements for more details
on goodwill.

DISCONTINUED OPERATIONS

In 2002, the Company  approved the sale of NCNG to Piedmont Natural Gas Company,
Inc.  As  a  result,   the  operating  results  of  NCNG  were  reclassified  to
discontinued  operations for all reportable  periods.  Progress Energy sold NCNG
and ENCNG for net  proceeds  of  approximately  $450  million.  Progress  Energy
incurred a loss from  discontinued  operations  of $8 million for the year ended
December  31, 2003  compared  with a loss of $24 million for 2002.  The loss for
2003 reflects the  finalization of the sale of NCNG. See Note 3A to the Progress
Energy   Consolidated   Financial   Statements  for  more  information  on  this
divestiture.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Progress  Energy recorded  adjustments for the cumulative  effects of changes in
accounting   principles   due  to  the   adoption  of  several  new   accounting
pronouncements.  These adjustments totaled to a $21 million loss after-tax which
was due primarily to new Financial  Accounting  Standards  Board (FASB) guidance
related to the accounting for certain contracts. This guidance discusses whether
the pricing in a contract  that  contains  broad market  indices  qualifies  for
certain  exceptions  that would not require  the  contract to be recorded at its
fair value. PEC Electric had a purchase power contract with Broad River LLC that
did not meet the criteria for an exception, and a negative fair value adjustment
was recorded in the fourth quarter of 2003 for $23 million  after-tax.  See Note
17A to the Progress Energy Consolidated Financial Statements and Note 12A to the
PEC Consolidated Financial Statements.

                                       53
<PAGE>

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

Utility Regulation

The Company's  regulated  utilities segments are subject to regulation that sets
the prices  (rates) the Company is  permitted to charge  customers  based on the
costs that regulatory agencies determine the Company is permitted to recover. At
times,  regulators  permit the future recovery through rates of costs that would
be  currently  charged to expense by a  nonregulated  company.  This  ratemaking
process  results  in  deferral  of  expense  recognition  and the  recording  of
regulatory assets based on anticipated  future cash inflows.  As a result of the
changing  regulatory  framework in each state in which the Company  operates,  a
significant  amount  of  regulatory  assets  has  been  recorded.   The  Company
continually reviews these assets to assess their ultimate  recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially  adverse  legislative,  judicial or regulatory actions in
the  future.   Additionally,   the  state  regulatory   agencies  often  provide
flexibility in the manner and timing of the  depreciation  of property,  nuclear
decommissioning  costs and amortization of the regulatory assets.  Note 7 to the
Progress  Energy   Consolidated   Financial   Statements   provides   additional
information related to the impact of utility regulation on the Company.

Asset Impairments

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

Due to the  reduction in coal  production  at the  Kentucky  May Coal Mine,  the
Company  evaluated its  long-lived  assets in 2003 and recorded an impairment of
$17 million  before tax ($11  million  after-tax).  See Note 9A to the  Progress
Energy  Consolidated  Financial  Statements  for  further  information  on  this
impairment and other charges.

During 2002, the Company recorded pre-tax  long-lived asset  impairments of $305
million related to its telecommunications  business. See Note 9A to the Progress
Energy  Consolidated  Financial  Statements  for  further  information  on  this
impairment  and other  charges.  The fair value of these  assets was  determined
using an external  valuation  study heavily  weighted on a discounted  cash flow
methodology and using market approaches as supporting information.

The Company also  continually  reviews its  investments  to determine  whether a
decline in fair value below the cost basis is other than temporary. In 2003, the
Company's  affordable housing investment (AHI) portfolio was reviewed and deemed
to be impaired based on various factors including  continued operating losses of
the  AHI  portfolio  and  management   performance  issues  arising  at  certain
properties  within  the  AHI  portfolio.  As  a  result,  the  Company  recorded
impairments of $18 million on a pre-tax basis during the fourth quarter of 2003.
The Company also  recorded an  impairment  of $3 million for a cost  investment.
During  2002 and 2001,  the Company  recorded  pre-tax  impairments  to its cost
method  investment in Interpath of $25 million and $157  million,  respectively.
The fair value of this  investment  was determined  using an external  valuation
study heavily  weighted on a discounted  cash flow  methodology and using market
approaches  as  supporting  information.  These  cash  flows  included  numerous
assumptions  including  the pace at which the  telecommunications  market  would
rebound.  In the fourth quarter of 2002, the Company sold its remaining interest
in Interpath for a nominal amount.

                                       54
<PAGE>

Goodwill

Effective January 1, 2002, the Company adopted SFAS No. 142, which requires that
goodwill be tested for  impairment at least  annually and more  frequently  when
indicators of impairment  exist. See Note 8 to the Progress Energy  Consolidated
Financial  Statements  for further  detail on goodwill.  SFAS No. 142 requires a
two-step  goodwill  impairment  test. The Company  performs the annual  goodwill
impairment  test  each  year.  The  first  step,  used  to  identify   potential
impairment,  compares  the fair value of the  reporting  unit with its  carrying
amount,  including goodwill.  The second step, used to measure the amount of the
impairment  loss if step one  indicates a  potential  impairment,  compares  the
implied fair value of the reporting  unit  goodwill with the carrying  amount of
the goodwill.

The Company completed the initial  transitional  goodwill impairment test, which
indicated  that the  Company's  goodwill was not impaired as of January 1, 2002.
The carrying  amounts of goodwill at December 31, 2003 and 2002,  for reportable
segments PEC Electric,  PEF and CCO, are $1,922 million,  $1,733 million and $64
million, respectively.

During 2003,  the Other  segment  acquired $7 million in goodwill as part of the
PTC business  combination  with EPIK. 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,  which  indicated  no  impairment.  If the fair  values for the
utility  segments  were  lower by 10%,  there  still  would be no  impact on the
reported value of their goodwill.

During 2002, the Company  completed the  acquisition of two electric  generating
projects,  Walton  County  Power,  LLC and  Washington  County  Power,  LLC. The
acquisitions resulted in goodwill of $64 million.

Synthetic Fuels Tax Credits

Progress Energy,  through the Fuels business unit, produces coal-based synthetic
fuel.  The  production  and sale of the synthetic fuel qualifies for tax credits
under Section 29 if certain requirements are satisfied,  including a requirement
that the synthetic fuel differs  significantly in chemical  composition from the
feedstock  used to produce  such  synthetic  fuel and that the fuel was produced
from a facility  that was placed in service  before July 1, 1998.  Any synthetic
fuel tax credit amounts not utilized are carried  forward  indefinitely  and are
included in deferred taxes on the accompanying  Consolidated Balance Sheets. See
Note 14 to the Progress  Energy  Consolidated  Financial  Statements for further
information  on  the  synthetic  fuel  tax  credits.  All of  Progress  Energy's
synthetic fuel  facilities have received PLRs from the IRS with respect to their
operations.  These tax credits are subject to review by the IRS, and if Progress
Energy fails to prevail through the administrative or legal process, there could
be a significant  tax liability  owed for  previously  taken Section 29 credits,
with a significant impact on earnings and cash flows.

Pension Costs

As  discussed  in  Note  16A  to  the  Progress  Energy  Consolidated  Financial
Statements, Progress Energy maintains qualified non-contributory defined benefit
retirement  (pension)  plans.  The  Company's  reported  costs are  dependent on
numerous factors resulting from actual plan experience and assumptions of future
experience.  For  example,  such costs are  impacted by  employee  demographics,
changes made to plan  provisions,  actual plan asset  returns and key  actuarial
assumptions  such as  expected  long-term  rates of  return on plan  assets  and
discount rates used in determining benefit obligations and annual costs.

Due to a slight decline in the market interest rates for  high-quality  (AAA/AA)
debt securities,  which are used as the benchmark for setting the discount rate,
the Company  lowered the discount rate to 6.3% at December 31, 2003,  which will
increase  the  2004  benefit  costs  recognized,  all  other  factors  remaining
constant.  However,  after a few years of negative  asset  returns due to equity
market  declines,  plan  assets  performed  very well in 2003,  with  returns of
approximately  30%. That  positive  asset  performance  will result in decreased
pension cost in 2004.  Evaluations of the effects of these factors have not been
completed,  but the Company  estimates  that the 2004 total cost  recognized for
pension will decrease by  approximately  $5 million from the amount  recorded in
2003, due in large part to these factors.

The Company has pension plan  assets,  with a fair value of  approximately  $1.6
billion at December 31, 2003.  The Company's  expected rate of return on pension
plan assets is 9.25%.  The Company  reviews this rate on a regular basis.  Under
Statement of Financial Accounting  Standards No. 87, "Employer's  Accounting for
Pensions"  (SFAS No.  87),  the  expected  rate of return  used in pension  cost
recognition  is a long-term  rate of return;  therefore,  the Company would only

                                       55
<PAGE>

adjust that return if its fundamental  assessment of the debt and equity markets
changes or its investment  policy changes  significantly.  The Company  believes
that its pension plans' asset investment mix and historical  performance support
the long-term  rate of 9.25% being used.  The Company did not adjust the rate in
response to short-term  market  fluctuations  such as the abnormally high market
return levels of the latter 1990s,  recent years' market declines and the market
rebound in 2003. A 0.25%  change in the  expected  rate of return for 2003 would
have changed 2003 pension cost by approximately $4 million.

Another factor affecting the Company's pension cost, and sensitivity of the cost
to plan  asset  performance,  is its  selection  of a method  to  determine  the
market-related  value of  assets,  i.e.,  the  asset  value to which  the  9.25%
expected  long-term  rate of  return is  applied.  SFAS No.  87  specifies  that
entities  may use  either  fair value or an  averaging  method  that  recognizes
changes in fair value over a period not to exceed  five  years,  with the method
selected  applied on a  consistent  basis  from year to year.  The  Company  has
historically  used a  five-year  averaging  method.  When the  Company  acquired
Florida Progress Corporation (Florida Progress) in 2000, it retained the Florida
Progress  historical  use of fair value to  determine  market-related  value for
Florida Progress pension assets. Changes in plan asset performance are reflected
in pension cost sooner under the fair value method than the five-year  averaging
method and,  therefore,  pension cost tends to be more  volatile  using the fair
value method. For example, in 2003 the expected return for assets subject to the
averaging  method was 3% lower than in 2002,  whereas  the  expected  return for
assets   subject  to  the  fair  value  method  was  18%  lower  than  in  2002.
Approximately 50% of the Company's pension plan assets is subject to each of the
two methods.

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW

Progress Energy is a registered  holding company and, as such, has no operations
of its own. As a holding company, Progress Energy's primary cash obligations are
its common dividend and interest expense  associated with $4.8 billion of senior
unsecured  debt. The ability to meet its  obligations is primarily  dependent on
the  earnings  and cash flows of its two  electric  utilities  and  nonregulated
subsidiaries,  and the ability of those  subsidiaries  to pay dividends or repay
funds to Progress Energy.

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

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

As a registered holding company under Public Utility Holding Company Act of 1935
(PUHCA), Progress Energy obtains approval from the SEC for the issuance and sale
of securities as well as the establishment of intercompany  extensions of credit
(utility and  nonutility  money pools).  PEC and PEF  participate in the utility
money pool,  which  allows the two  utilities  to lend and borrow  between  each
other.  Progress  Energy can lend money into the  utility  money pool but cannot
borrow  funds.  The  nonutility  money pool was  established  to allow  Progress
Energy's  nonregulated  operations  to lend and borrow funds amongst each other.
Progress  Energy  can also lend  money to the  nonutility  money pool but cannot
borrow funds.

During  2003,  the  Company  realized  approximately  $450  million  of net cash
proceeds from the sale of NCNG and ENCNG. The Company also received net proceeds
of  approximately  $97  million  in  October  2003  for the sale of its Mesa gas
properties  located in Colorado.  Progress  Energy used the proceeds  from these
sales to reduce indebtedness, primarily commercial paper, then outstanding.

On March 1, 2004,  Progress  Energy used  available  cash and proceeds  from the
issuance of  commercial  paper to retire $500  million  6.55%  senior  unsecured
notes.  Cash and commercial paper capacity were created  primarily from the sale
of the assets in 2003 as noted above.

For the 12 months ended  December 31, 2003, the Company  received  approximately
$309  million of net proceeds  through the sale of 7.6 million  shares of common
stock issued  through the  Progress  Energy  Direct Stock  Purchase and Dividend
Reinvestment  Plan, and its 401(k) Savings and Stock Ownership Plan. The Company
expects to reduce the issuance of common stock in 2004.

Progress  Energy's cash from  operations  and common stock  issuances in 2004 is
expected to fund its capital expenditures. To the extent necessary,  incremental
borrowings  or  commercial  paper  issuances  may  also be used as a  source  of
liquidity.

                                       56
<PAGE>

Progress Energy believes its internal and external  liquidity  resources will be
sufficient to fund its current  business  plans.  Risk factors  associated  with
commercial paper backup credit facilities and credit ratings are discussed below
and in the "Risk Factors" section of this report.

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

CASH FLOWS FROM OPERATIONS

Cash from  operations is the primary source used to meet operating  requirements
and capital expenditures.  Total cash from operations for 2003 was $1.8 billion,
compared to $1.6 billion in 2002. The increase in cash from operating activities
for 2003 when  compared  with 2002 is largely the result of  improved  operating
results at PEC. Total cash from  operations  for 2002 was $1.6 billion,  up $271
million from 2001.

Progress Energy's two electric  utilities produced over 90% of consolidated cash
from  operations in 2003. It is expected  that the two electric  utilities  will
continue to produce a majority of the  consolidated  cash flows from  operations
over  the  next  several  years  as  its  nonregulated  investments,   primarily
generation assets, improve asset utilization and begin generating operating cash
flows.

In addition,  Fuels' synthetic fuel operations do not currently produce positive
operating  cash  flow  primarily  due to the  difference  in  timing of when tax
credits are recognized for financial reporting purposes and when tax credits are
realized for tax purposes.

Total cash from  operations  provided the funding for  approximately  90% of the
Company's  capital  expenditures,  including  property  additions,  nuclear fuel
expenditures and diversified  business property additions during 2003, excluding
proceeds from asset sales of $579 million. Progress Energy expects its operating
cash flow to exceed its  projected  capital  expenditures  and common  dividends
beginning  in 2004 and  current  plans are to use the excess cash flow to reduce
debt.

INVESTING ACTIVITIES

Excluding  proceeds from sales of  subsidiaries  and  investments,  cash used in
investing  activities was $2.0 billion in 2003, down  approximately $300 million
when compared with 2002. The decrease is due primarily to lower utility property
additions  due  to  completion  of  Hines  2  construction   at  PEF  and  lower
acquisitions of nonregulated assets.

Cash used in investing  was $2.2 billion in 2002,  up $562 million when compared
with 2001.  The increase  was due  primarily to PVI  purchasing  two  generating
projects from LG&E Energy Corp. for approximately $350 million.

Capital  expenditures for Progress Energy's regulated  electric  operations were
$1.0 billion or approximately 58% of consolidated  capital expenditures in 2003,
excluding  proceeds from asset sales.  As shown in the table below,  the Company
anticipates  that the  proportion  of  nonregulated  capital  spending  to total
capital  expenditures  will  decrease  substantially  in 2004 when compared with
2003.  The decrease  reflects the  completion of PVI's  nonregulated  generation
portfolio  in  2003.  Progress  Energy  expects  the  majority  of  its  capital
expenditures to be incurred at its regulated operations. Forecasted nonregulated
expenditures  relate  primarily  to  Progress  Fuels  and  its  gas  operations,
primarily for drilling new wells.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                              Actual                           Forecasted
                                         -----------      ------------------------------------------------
                                             2003             2004              2005              2006
                                         -----------      ------------     --------------     -----------
Regulated capital expenditures            $ 1,018          $   980          $     990         $  1,020
Nuclear fuel expenditures                     117               90                120               80
AFUDC - borrowed funds                         (7)             (20)               (20)             (10)
Nonregulated capital expenditures             607              200                160              120
                                         -----------      ------------     --------------     -----------
     Total                                $ 1,735          $ 1,250           $  1,250         $  1,210
                                         ===========      ============     ==============     ===========
</TABLE>

Regulated  capital  expenditures  in the table above include total  expenditures
from 2004 through 2006 of approximately  $105 million expected to be incurred at
PEC fossil-fueled  electric generating  facilities to comply with Section 110 of
the Clean Air Act, referred to as the NOx SIP Call. See Note 21E to the Progress
Energy Consolidated Financial Statements.

                                       57
<PAGE>

In June 2002,  legislation  was enacted in North Carolina  requiring the state's
electric  utilities to reduce the  emissions of nitrogen  oxide (NOx) and sulfur
dioxide (SO2) from  coal-fired  power  plants.  PEC expects its capital costs to
meet these emission targets will be approximately  $813 million by 2013. For the
years 2004 through 2006, the Company expects to incur approximately $320 million
of total capital costs  associated with this  legislation,  which is included in
the table above.  See Note 21E to the  Progress  Energy  Consolidated  Financial
Statements and "Current  Regulatory  Environment"  under OTHER MATTERS below for
more information on this legislation.

In 2003, PEC determined that its external  funding levels did not fully meet the
nuclear decommissioning financial assurance levels required by the United States
Nuclear  Regulatory  Commission  (NRC).  The funding  levels had been  adversely
affected  by the  declines  in the  equity  markets.  The  total  shortfall  was
approximately  $95 million  (2010  dollars) for Robinson Unit No. 2, $82 million
(2016  dollars)  for  Brunswick  Unit No. 1 and $99 million  (2014  dollars) for
Brunswick Unit No. 2. PEC met the financial assurance  requirements by obtaining
a parent company  guarantee.  The funding status for these  facilities  would be
positively  affected by a continuing  recovery in the equity  markets and by the
approval of license extension applications.

PEC retains funds internally to meet decommissioning  liability.  The NCUC order
issued February 2004 found that by January 1, 2008 PEC must begin  transitioning
these  amounts  to  external  funds.  The  transition  of $131  million  must be
completed by December 31, 2017, and at least 10% must be transitioned each year.
PEC has exclusively utilized external funding for its decommissioning  liability
since 1994.

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

FINANCING ACTIVITIES

Cash provided by operating  activities  and proceeds  from asset sales  exceeded
property and fuel  additions by  approximately  $625 million.  The excess,  when
combined with $304 million of net cash  generated from the sale of common stock,
resulted in an  increase  of cash and cash  equivalents  of $212  million  after
paying common dividends.  As of December 31, 2003, on a consolidated  basis, the
Company had $868 million of  long-term  debt  maturing in 2004,  $300 million of
which was  prefunded  through  issuances of long-term  debt in 2003. On March 1,
2004,  Progress  Energy  funded the  maturity of its $500  million  6.55% senior
unsecured notes with cash on hand and commercial paper.

On January 15,  2004,  PEC funded the  maturity  of $150  million  5.875%  First
Mortgage Bonds with commercial paper proceeds.  PEC also has $150 million 7.875%
First  Mortgage  Bonds  maturing on April 15, 2004.  It plans to use  commercial
paper proceeds to fund this maturity.

During 2003, both PEC and PEF took advantage of historically  low interest rates
and refinanced several issues of debt.

In February 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 $150 million of PEF's First Mortgage  Bonds, 8% Series,
Due December 1, 2022 at 103.75% of the principal amount of such bonds.

On March 1, 2003, $70 million of PEF's First Mortgage Bonds,  6.125% Series, Due
March 1, 2003, matured. PEF funded the maturity with commercial paper.

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 1, 2003,  $110 million of PEF's First Mortgage Bonds,  6.0% Series,  Due
July 1, 2003 and $35 million of PEF's medium-term notes, 6.62% Series,  matured.
PEF funded the maturity with commercial paper.

On August 15, 2003,  PEC redeemed $100 million of First Mortgage  Bonds,  6.875%
Series,  Due  August  15,  2023 at  102.84%.  PEC  funded  the  redemption  with
commercial paper.

                                       58
<PAGE>

On September 11, 2003, PEC issued $400 million of First Mortgage  Bonds,  5.125%
Series, Due September 15, 2013 and $200 million of First Mortgage Bonds,  6.125%
Series, Due September 15, 2033.  Proceeds from this issuance were used to reduce
the balance of PEC's  outstanding  commercial paper and short-term notes payable
to  affiliated  companies,  which notes  represent  PEC's  borrowings  under the
internal money pool operated by Progress Energy.

On November 21, 2003,  PEF issued $300 million of First  Mortgage  Bonds,  5.10%
Series Due December 1, 2015.  Proceeds from this issuance were used to refinance
$100 million of PEF's First Mortgage  Bonds,  7% Series,  Due 2023 at 103.19% of
the principal amount of such bonds and to reduce the outstanding  balance of its
notes payable to affiliates.

The  amount  of  debt  issued  by  PEC  and  PEF  in  September   and  November,
respectively,  took into consideration debt maturities and other financing needs
for 2004. As such,  neither PEC nor PEF anticipate  the need to issue  long-term
debt in 2004.

In March 2003, Progress Genco Ventures LLC (Genco), a wholly-owned subsidiary of
PVI, terminated its $50 million working capital credit facility. Under a related
construction facility, Genco has drawn $241 million at December 31, 2003.

During 2003,  Progress  Energy  obtained a new three-year  financing order which
will expire  September  30,  2006.  Under the new order,  Progress  Energy,  the
holding  company,  can issue up to $2.8  billion of long-term  securities,  $1.5
billion of short-term debt and $3 billion of parent guarantees.

At December 31, 2003, the Company and its  subsidiaries  had committed  lines of
credit totaling $1.6 billion, for which there were no loans outstanding.  All of
the  credit  facilities  supporting  the $1.6  billion of credit  were  arranged
through a syndication  of  commercial  banks.  There are no bilateral  contracts
associated  with these  facilities.  These lines of credit support the Company's
commercial paper borrowings. The following table summarizes the Company's credit
facilities:

(in millions)
Company                            Description                       Total
------------------------------------------------------------------------------

Progress Energy, Inc.               364-Day (expiring 11/10/04)     $  250
Progress Energy, Inc.               3-Year (expiring 11/13/04)         450
Progress Energy Carolinas, Inc.     364-Day (expiring 7/29/04)         165
Progress Energy Carolinas, Inc.     3-Year (expiring 7/31/05)          285
Progress Energy Florida, Inc.       364-Day (expiring 3/31/04)         200
Progress Energy Florida, Inc.       3-Year (expiring 4/01/06)          200
                                                                   -----------
Total credit facilities                                            $ 1,550
                                                                   ===========

The Company's  financial policy precludes issuing  commercial paper in excess of
its supporting  lines of credit.  At December 31, 2003, the Company did not have
any commercial paper  outstanding,  leaving $1.6 billion available for issuance.
In addition,  the Company had requirements to pay minimal annual commitment fees
to maintain its credit  facilities.  At December  31, 2002,  the total amount of
commercial paper outstanding was $695 million.

In addition,  these  credit  agreements  and Genco's $241 million bank  facility
contain various terms and conditions that could affect the Company's  ability to
borrow under these  facilities.  These include a maximum  debt-to-total  capital
ratio,  an  interest  coverage  test,  a  material  adverse  change  clause  and
cross-default provisions.

All of the credit facilities and Genco's bank facility include a defined maximum
total  debt-to-total  capital ratio (leverage) and coverage ratios.  At December
31, 2003, the calculated ratios for these four companies,  pursuant to the terms
of the agreements, are as follows:

                                       59
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                        Maximum        Actual         Minimum      Actual
                                        Leverage       Leverage (a)   Coverage     Coverage
Company                                 Ratio          Ratio          Ratio        Ratio
---------------------------------------------------------------------------------------------
Progress Energy, Inc.                     68%           61.5%          2.5 : 1     3.74 : 1
Progress Energy Carolinas, Inc.           65%           51.4%            n/a          n/a
Progress Energy Florida, Inc.             65%           51.5%          3.0 : 1     9.22 : 1
Progress Genco Ventures, LLC              40%           24.6%         1.25 : 1     6.35 : 1
---------------------------------------------------------------------------------------------
     (a) Indebtedness as defined by the bank agreements includes certain letters
        of credit and guarantees which are not recorded on the Consolidated
        Balance Sheets.
</TABLE>

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

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

Additionally,  certain of Progress  Energy's  long-term debt indentures  contain
cross-default  provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other  obligations of Progress Energy,  primarily
commercial paper issued by the holding  company,  not its  subsidiaries.  In the
event that these  indenture  cross-default  provisions are  triggered,  the debt
holders  could  accelerate  payment of  approximately  $4.3 billion in long-term
debt,  as  of  March  1,  2004.  Certain  agreements  underlying  the  Company's
indebtedness  also  limit its  ability  to incur  additional  liens or engage in
certain types of sale and leaseback transactions.

The Company has on file with the SEC a shelf registration  statement under which
senior notes,  junior  debentures,  common and  preferred  stock and other trust
preferred  securities are available for issuance by the Company. At December 31,
2003,  the  Company  had  approximately  $1 billion  available  under this shelf
registration.

Progress Energy and PEF each have an uncommitted  bank bid facility  authorizing
each of them to borrow and re-borrow, and have loans outstanding at any time, up
to $300 million and $100 million, respectively. At December 31, 2003, there were
no outstanding loans against these facilities.

PEC  currently  has on file with the SEC a shelf  registration  statement  under
which it can issue up to $900  million  of  various  long-term  securities.  PEF
currently  has on file  registration  statements  under  which  it can  issue an
aggregate of $750 million of various long-term debt securities.

Both PEC and PEF can issue First  Mortgage  Bonds under their  respective  First
Mortgage Bond  indentures.  At December 31, 2003,  PEC and PEF could issue up to
$2.8 billion and $3.4 billion  based on property  additions and $1.9 billion and
$76 million based upon retirements.

The  following  table shows  Progress  Energy's and Progress  Energy  Carolinas'
capital structure at December 31, 2003 and 2002:

                          Progress Energy                  PEC
                    --------------------------   ------------------------
                      2003          2002            2003        2002
-------------------------------------------------------------------------
Common Stock          40.6%         38.2%           48.2%       46.6%
Preferred Stock        0.5%          0.5%            0.9%        0.9%
Total Debt            58.9%         61.3%           50.9%       52.5%

The amount  and timing of future  sales of  company  securities  will  depend on
market  conditions,  operating cash flow,  asset sales and the specific needs of
the Company. The Company may from time to time sell securities beyond the amount
needed to meet capital  requirements in order to allow for the early  redemption
of  long-term  debt,  the  redemption  of  preferred  stock,  the  reduction  of
short-term debt or for other general corporate purposes.

                                       60
<PAGE>

CREDIT RATING MATTERS

The major credit rating agencies have currently  rated the Company's  securities
as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                           Moody's
                                      Investors Service     Standard & Poor's     Fitch Ratings
----------------------------------------------------------------------------------------------------
Progress Energy, Inc.
Corporate Credit Rating                Not Applicable             BBB            Not Applicable
Senior Unsecured                            Baa2                  BBB-                BBB-
Commercial Paper                            P-2                   A-2            Not Applicable

Progress Energy Carolinas, Inc.
Corporate Credit Rating                Not Applicable             BBB            Not Applicable
Commercial Paper                            P-2                   A-2                 F2
Senior Secured Debt                         A3                    BBB                 A-
Senior Unsecured Debt                       Baa1                  BBB                 BBB+

Progress Energy Florida, Inc.
Corporate Credit Rating                Not Applicable             BBB            Not Applicable
Commercial Paper                            P-1                   A-2                 F2
Senior Secured Debt                         A1                    BBB                 A-
Senior Unsecured Debt                       A2                    BBB                 BBB+

FPC Capital I
Preferred Stock*                            Baa1                  BB+            Not Applicable

Progress Capital Holdings, Inc.
Senior Unsecured Debt*                      A3                    BBB-           Not Applicable
----------------------------------------------------------------------------------------------------
*Guaranteed by Florida Progress Corporation
</TABLE>

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

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

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

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

Also in February  2003,  Fitch  Ratings  Service  assigned an initial  rating to
Progress  Energy's  senior  unsecured  debt of BBB-.  No  short-term  rating was
assigned.

Fitch also  downgraded  the ratings of PEF and PEC.  PEF's senior secured rating
was changed to A- from AA- and its senior  unsecured  rating was changed to BBB+
from A+.  PEF's  short-term  rating was changed to F-2 from F-1+.  PEC's  senior
secured  rating was  changed to A- from A+ and its senior  unsecured  rating was
changed to BBB+ from A.  PEC's  short-term  rating was  changed to F-2 from F-1.
Fitch's outlook for all three rated entities is stable.

                                       61
<PAGE>

In August 2003,  Standard & Poor's (S&P) credit rating agency  announced that it
had lowered its corporate  credit rating on Progress  Energy Inc., PEC, PEF, and
Florida  Progress to BBB from BBB+.  The outlook of the ratings was changed from
negative to stable.

These changes have not had a material impact on the companies' access to capital
or their financial results.

Interest Rate Derivatives

Progress  Energy uses interest rate  derivative  instruments to manage the fixed
and variable rate debt components of its debt portfolio. The Company's long-term
objective is to maintain a debt portfolio mix of approximately 30% variable rate
debt, 70% fixed rate. At December 31, 2003,  Progress Energy's variable rate and
fixed rate debt  comprised 16% and 84%,  respectively,  including the effects of
interest rate derivatives.

During 2003,  cash  proceeds from the sale of NCNG and gas reserves were used to
pay down debt,  primarily  commercial  paper.  While this reduced the  Company's
floating rate portion well below its long-term  target of 30%, on March 1, 2004,
the  Company  issued  commercial  paper to fund a portion of the  maturing  $500
million 6.55% senior  unsecured  notes,  increasing  the amount of floating rate
debt back to over 20%.

Progress  Fuels  periodically  enters into  derivative  instruments to hedge its
exposure to price  fluctuations  on natural gas sales.  At  December  31,  2003,
Progress  Fuels had  approximately  19 Bcf of cash flow  hedges in place for its
natural gas production. These positions extend through December 2005.

Genco has a floating  rate credit  facility that  requires,  as part of the loan
terms, a cash flow hedge against  floating  interest rate exposure.  In order to
satisfy this  requirement,  Genco entered into a series of interest rate collars
during 2002 with  notional  amounts up to a maximum of $195  million and a final
maturity date of March 20, 2007.

Contractual Obligations

The following table reflects Progress Energy's  contractual cash obligations and
other commercial  commitments at December 31, 2003 in the respective  periods in
which they are due:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)
---------------------------------------------------------------------------------------------------------
                                                       Less than 1                           More than 5
Contractual Obligations                     Total          year     1-3 years  3-5 years       years
---------------------------------------------------------------------------------------------------------
Long-term debt                           $  10,874        $  868    $  1,256   $  1,742         $  7,008
Capital lease obligations                       50             4           8          7               31
Operating leases                               307            38          60         41              168
Fuel and purchased power                    10,683         1,672       1,976      1,312            5,723
Other purchase obligations                     369           140          78         27              124
North Carolina clean air capital
   commitments                                 783            90         230        210              253
Funding obligations                            182            51           -         13              118
Other commitments                              111            26          52         33                -
                                       ------------------------------------------------------------------
Total                                    $  23,359      $  2,889    $  3,660   $  3,385         $  13,425
                                       ==================================================================
</TABLE>

Information  on the Company's  contractual  obligations  at December 31, 2003 is
included in the notes to the Progress Energy Consolidated  Financial Statements.
Future  debt  maturities  are  included  in  Note  12  to  the  Progress  Energy
Consolidated  Financial  Statements.  The  Company's  fuel and  purchased  power
obligations  have expiration dates ranging from 2004 to 2025 and are included in
Note 21A to the Progress Energy Consolidated Financial Statements. The Company's
other  purchase  obligations  are  included in Note 21A to the  Progress  Energy
Consolidated Financial Statements.  The Company's lease obligations are included
in Note 21C to the Progress  Energy  Consolidated  Financial  Statements.  PEC's
North Carolina clean air legislation  capital  commitments are described in Note
21E to the Progress  Energy  Consolidated  Financial  Statements.  In 2004,  the
Company  expects  to make $51  million of  required  contributions  directly  to
retirement plan assets.  Decommissioning cost provisions are included in Note 5D
to the Progress  Energy  Consolidated  Financial  Statements.  In 2008, PEC must
begin  transitioning  amounts  currently  retained  internally  to its  external
decommissioning  funds.  The  transition  of $131  million  must be  complete by
December  31,  2017,  and at  least  10% must be  transitioned  each  year.  The
Company's  other  commitments  are included in Note 21B to the  Progress  Energy
Consolidated Financial Statements.

                                       62


<PAGE>

The Company takes into  consideration  the future  commitments  shown above when
assessing its liquidity and future financing needs.

The Company's  maturing debt obligations are generally expected to be refinanced
with new debt issuances in the capital markets.  However,  the Company does plan
to annually  reduce its leverage by one to two  percentage  points over the next
few years through the sale of assets and excess operating cash flow.

Fuel and  purchased  power  commitments  represent the majority of the Company's
remaining future commitments after its debt obligations.  Essentially all of the
Company's  fuel and  purchased  power costs are recovered  through  pass-through
clauses  in  accordance  with  North   Carolina,   South  Carolina  and  Florida
regulations and therefore do not require separate liquidity support.

OTHER MATTERS

CURRENT REGULATORY ENVIRONMENT

General

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

Electric Industry Restructuring

PEC and PEF  continue  to monitor  any  developments  toward a more  competitive
environment and have actively participated in regulatory reform deliberations in
North  Carolina,  South Carolina and Florida.  Movement  toward  deregulation in
these states has been affected by recent  developments,  including  developments
related to  deregulation of the electric  industry in other states.  The Company
expects  the  legislatures  in all three  states  will  continue  to monitor the
experiences of states that have implemented electric restructuring legislation.

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

Florida Retail Rate Proceeding

In March 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 and is generally  effective  from May 1, 2002
through December 31, 2005; provided,  however,  that if PEF's base rate earnings
fall below a 10% return on equity,  PEF may  petition the FPSC to amend its base
rates. See Note 7D to the Progress Energy Consolidated  Financial Statements for
additional information on the Agreement.

North Carolina Clean Air Legislation

In June 2002,  legislation  was enacted in North Carolina  requiring the state's
electric  utilities to reduce the emissions of NOx and SO2 from coal-fired power
plants. Progress Energy expects its capital costs to meet these emission targets
to be approximately $813 million by 2013, of which approximately $30 million has
been expended through December 31, 2003. 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  significant  cost
changes due to  governmental  action or other  extraordinary  events  beyond the
control of the  utilities  or unless the  utilities  persistently  earn a return
substantially  in excess of the rate of return  established and found reasonable
by the NCUC in the utilities' last general rate case.  Further,  the legislation
allows the  utilities  to recover  from their  retail  customers  the  projected
capital  costs  during the first seven years of the  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
law, PEC entered into an agreement  with the state of North Carolina to transfer
to the state all future  emissions  allowances it generates from  over-complying
with the federal  emission  limits when these units are completed.  The law also
requires the state to undertake a study of mercury and carbon dioxide  emissions

                                       63
<PAGE>

in North  Carolina.  Operation  and  maintenance  costs will increase due to the
additional  personnel,  materials and general  maintenance  associated  with the
equipment.  Operation  and  maintenance  expenses are  recoverable  through base
rates,  rather than as part of this program.  Progress Energy cannot predict the
future regulatory interpretation, implementation or impact of this law.

Florida Proposed Clean Air Legislation

In 2004, a bill was  introduced  in the Florida  legislature  that would require
significant  reductions in SO2, NOx and particulate emissions from certain coal,
natural gas and oil-fired  generating units owned or operated by  investor-owned
electric utilities, including PEF. The SO2 and NOx reductions would be effective
beginning  with  calendar  year  2010 and the  particulate  reductions  would be
effective beginning with calendar year 2012. Under the proposed legislation, the
FPSC  would be  authorized  to allow  the  utilities  to  recover  the  costs of
compliance  with the  emission  reductions  over a period not greater than seven
years beginning in 2005, but the utilities' rates would be frozen at 2004 levels
for at least five years of the  maximum  recovery  period.  The  Company  cannot
predict the outcome of this matter.

Other Retail Rate Matters

See  Note  7B to the  Progress  Energy  Consolidated  Financial  Statements  for
additional information on the Company's other retail rate matters.

Regional Transmission Organizations and Standard Market Design

In 2000,  the FERC  issued  Order 2000  regarding  RTOs.  This Order set minimum
characteristics  and  functions  that  RTOs  must  meet,  including  independent
transmission  service.  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. PEC and PEF, as  subsidiaries of Progress  Energy,  filed
comments in November  2002 and  supplemental  comments in January 2003. In April
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.  The FERC has
not yet issued a final rule on SMD NOPR.  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.  It is unknown what
impact the future proceedings will have on the Company's  earnings,  revenues or
prices. See Note 7C to the Progress Energy Consolidated Financial Statements for
additional information on GridFlorida and GridSouth.

FRANCHISE LITIGATION

Three cities,  with a total of approximately  18,000 customers,  have litigation
pending  against PEF in various  circuit courts in Florida.  Three other cities,
with a total of approximately 30,000 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 those circuit court
decisions  and  authorized  cities  to  determine  the  value of PEF's  electric
distribution system within the cities through arbitration. Arbitration in one of
the  cases  (the  City of  Casselberry)  was  held  in  August  2002.  Following
arbitration,  the parties entered settlement discussions,  and in July 2003, 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  13,000-customer  City of Winter  Park) was  completed in
February 2003.  That  arbitration  panel issued an award in May 2003 setting the
value  of  PEF's  distribution   system  within  the  City  of  Winter  Park  at
approximately $32 million,  not including separation and reintegration costs and
construction  work in progress,  which could add several  million dollars to the
award. The panel also awarded PEF  approximately  $11 million in stranded costs.
In September  2003,  Winter Park voters passed a referendum that would authorize
the City to issue  bonds of up to  approximately  $50  million to acquire  PEF's
electric  distribution system. The City has not yet definitively decided whether
it will acquire the system,  but has indicated that it will seek wholesale power
supply bids and bids to operate and maintain the  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  2,500-customer
Town of Belleair) was completed in June 2003. In September 2003, the arbitration
panel  issued  an  award  in  that  case  setting  the  value  of  the  electric
distribution  system  within the Town at  approximately  $6  million.  The panel
further  required the Town to pay to PEF its  requested $1 million in separation
and reintegration costs and approximately $2 million in stranded costs. The Town
has not yet decided whether it will attempt to acquire the system. At this time,
whether  and  when  there  will be  further  proceedings  regarding  the Town of
Belleair cannot be determined.  A fourth  arbitration (with the  13,000-customer
City of Apopka) had been  scheduled  for January  2004.  In December  2003,  the
Apopka City Commission voted on first reading to approve a settlement  agreement
and a 30-year  franchise with PEF. The settlement and franchise became effective
upon approval by the  Commission at a second reading of the franchise in January
2004. The settlement  resolves all outstanding  litigation  between the parties.
Arbitration  in the remaining  city's  litigation  (the  1,500-customer  City of
Edgewood) has not yet been scheduled.

                                       64
<PAGE>

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 held oral argument
in one of the appeals in August 2003. Subsequently, the Court requested briefing
from the parties in the other appeal, which was completed in November 2003. The
Court has not yet issued a decision in these cases. The Company cannot predict
the outcome of these matters at this time.

NUCLEAR

In the Company's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdictions, the provisions
for nuclear decommissioning costs are approved by the FERC. See Note 5D to the
Progress Energy Consolidated Financial Statements for a discussion of the
Company's nuclear decommissioning costs.

SYNTHETIC FUELS TAX CREDITS

Progress Energy,  through the Fuels business segment,  produces coal-based solid
synthetic  fuel. The production and sale of the synthetic fuel qualifies for tax
credits  under Section 29 if certain  requirements  are  satisfied,  including a
requirement   that  the  synthetic  fuel  differs   significantly   in  chemical
composition  from the feedstock used to produce such synthetic fuel and that the
fuel was  produced  from a facility  that was placed in service  before  July 1,
1998.  Any synthetic  fuel tax credit  amounts not utilized are carried  forward
indefinitely and are included in deferred taxes on the accompanying Consolidated
Balance  Sheets.  See  Note 14 to the  Progress  Energy  Consolidated  Financial
Statements.  All entities  have received PLRs from the 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. Total
Section 29 credits  generated to date (including FPC prior to its acquisition by
the Company) are approximately $1,243 million. The current Section 29 tax credit
program expires at the end of 2007.

One  of  the  Company's   synthetic  fuel  entities,   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 $317 million in tax
credits to date, is being  audited by the IRS. The Company is audited  regularly
in the normal course of business, as are most similarly situated companies,  and
the audit of Colona was expected.

In  September  2002,  all of Progress  Energy's  majority-owned  synthetic  fuel
entities,  including  Colona,  were accepted into the IRS  Pre-Filing  Agreement
(PFA) program.  The PFA program allows  taxpayers to voluntarily  accelerate the
IRS exam  process in order to seek  resolution  of specific  issues.  Either the
Company or the IRS can  withdraw  from the  program at any time,  and issues not
resolved  through  the  program  may  proceed  to the next level of the IRS exam
process.

                                       65
<PAGE>

In June 2003,  the  Company  was  informed  that IRS field  auditors  had 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.

In October 2003, the National Office of the IRS informed the Company that it had
rejected the IRS field auditors' challenges regarding whether the synthetic fuel
produced  at the  company's  Colona  facility  was the  result of a  significant
chemical change. The National Office had concluded that the experts,  engaged by
Colona  who  test  the  synthetic  fuel  for  chemical  change,  use  reasonable
scientific methods to reach their conclusions.  Accordingly, the National Office
will not take any adverse  action on the PLR that has been issued for the Colona
facility.

Although this ruling applies only to the Colona  facility,  the Company believes
that the National  Office's  reasoning would be equally  applicable to the other
Progress Energy  facilities.  The Company 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 other facilities.

In February 2004,  subsidiaries of the Company finalized execution of the Colona
Closing   Agreement  with  the  IRS  concerning   their  Colona  synthetic  fuel
facilities.  The Colona Closing  Agreement  provided that the Colona  facilities
were placed in service  before July 1, 1998,  which is one of the  qualification
requirements  for tax credits  under  Section 29. The Colona  Closing  Agreement
further  provides that the fuel  produced by the Colona  facilities in 2001 is a
"qualified  fuel" for  purposes  of the  Section  29 tax  credits.  This  action
concludes the IRS PFA program with respect to Colona.

Although the execution of the Colona Closing  Agreement is a significant  event,
the audits of the Company's facilities are not yet completed and the PFA process
continues  with respect to the four  synthetic  fuel  facilities  owned by other
affiliates of Progress Energy and FPC.  Currently,  the focus of that process is
to determine that the facilities  were placed in service before July 1, 1998. In
management's  opinion,  Progress  Energy  is  complying  with all the  necessary
requirements  to be allowed such credits  under  Section 29,  although it cannot
provide  certainty,  that it will  prevail if  challenged  by the IRS on credits
taken. Accordingly, the Company has no current plans to alter its synthetic fuel
production schedule as a result of these matters.

In  October  2003,   the  United  States  Senate   Permanent   Subcommittee   on
Investigations  began a  general  investigation  concerning  synthetic  fuel tax
credits claimed under Section 29. The investigation is examining the utilization
of the credits, the nature of the technologies and fuels created, the use of the
synthetic  fuel,  and other  aspects of Section  29 and is not  specific  to the
Company's synthetic fuel operations. Progress Energy is providing information in
connection  with this  investigation.  The Company cannot predict the outcome of
this matter.

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.  The final
outcome and timing of these  discussions  is  uncertain  and the Company  cannot
predict the outcome of this matter.

ENVIRONMENTAL MATTERS

The Company is subject to federal,  state and local  regulations  addressing air
and water quality,  hazardous and solid waste management and other environmental
matters.  These environmental matters are discussed in detail in Note 21E to the
Progress Energy Consolidated  Financial  Statements and Note 16D to the Progress
Energy Carolinas Consolidated  Financial Statements.  This discussion identifies
specific  environmental  issues, the status of the issues,  accruals  associated
with issue resolutions and the associated exposures to the Company.

NEW ACCOUNTING STANDARDS

See  Note 2 to the  Progress  Energy  Consolidated  Financial  Statements  for a
discussion of the impact of new accounting standards.

                                       66
<PAGE>

PEC

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; FUTURE OUTLOOK and OTHER
MATTERS.

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

RESULTS OF OPERATIONS

The results of operations for the PEC  consolidated for the years ended December
31, 2003, 2002 and 2001,  respectively,  are summarized in the table below.  The
results of operations for the PEC Electric segment are identical between PEC and
Progress Energy for all periods  presented.  The primary  difference between the
results of  operations  of the PEC  Electric  segment and the  consolidated  PEC
results of operations for the 2001, 2002 and 2003  comparison  periods relate to
the non-electric operations, as summarized below:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                       2003         2002         2001
                                               ----------    ---------    ---------
PEC Electric income before cumulative effect      $ 515        $ 513        $ 468
Caronet net income (loss)                             5          (79)         (99)
Other non-electric net loss                         (18)          (6)          (8)
Cumulative effect of accounting change              (23)           -            -
                                               ----------    ---------    ---------
Earnings for common stock                         $ 479        $ 428        $ 361
                                               ==========    =========    =========
</TABLE>

Caronet's results of operations for 2002 and 2001 include after-tax  impairments
of $87 million and $107 million, respectively, for other-than-temporary declines
in the value of the assets of Caronet and Caronet's investment in Interpath. The
Interpath investment was sold in December 2002 for a nominal amount. In December
2003, PTC and Caronet,  both wholly-owned  subsidiaries of Progress Energy,  and
EPIK, a wholly-owned  subsidiary of Odyssey,  contributed  substantially  all of
their assets and  transferred  certain  liabilities  to PTC LLC, a subsidiary of
PTC. Subsequently,  the stock of Caronet was sold to an affiliate of Odyssey for
$2 million in cash and Caronet  become an indirect  wholly-owned  subsidiary  of
Odyssey.  Following  consummation of all the  transactions  described above, PTC
holds a 55 percent ownership interest in, and is the parent, of PTC LLC. Odyssey
holds a combined  45 percent  ownership  interest  in PTC LLC  through  EPIK and
Caronet.  The  accounts of PTC LLC are  included in the  Company's  Consolidated
Financial Statements since the transaction date.

The Other  non-electric  segments  contributed  segment  losses of $18  million.
Included in the 2003 segment  losses is an  investment  impairment of $6 million
after-tax  on  the  Affordable   Housing   portfolio  held  by  the  non-utility
subsidiaries of PEC.

PEC Electric recorded cumulative effects of changes in accounting principles due
to the adoption of a new accounting pronouncement.  This adjustment totaled to a
$23 million loss which was due primarily to the new FASB guidance related to the
accounting for certain contracts. This guidance discusses whether the pricing in
a contract that contains broad market indices  qualifies for certain  exceptions
that would not  require the  contract  to be  recorded  at its fair  value.  PEC
Electric had a purchase  power  contract with Broad River LLC, that did not meet
the criteria for an exception, and a negative fair value adjustment was recorded
in the  fourth  quarter  of  2003  for  $23  million.  See  Note  12A to the PEC
Consolidated Financial Statements

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

                                       67
<PAGE>

LIQUIDITY AND CAPITAL RESOURCES

PEC's estimated  capital  requirements for 2004, 2005 and 2006 are $625 million,
$595 million and $610 million,  respectively, and primarily reflect construction
expenditures to support  customer growth,  add regulated  generation and upgrade
existing  facilities.  PEC  expects to fund its capital  requirements  primarily
through internally  generated funds. In addition,  PEC has a $450 million credit
facility  which  supports  the  issuance  of  commercial  paper.  Access  to the
commercial paper market and the utility money pool provide additional  liquidity
to help meet PEC's working capital requirements.

See Note 8 to the PEC Consolidated Financial Statements for information on PEC's
available  credit  facilities at December 31, 2003, and the discussion above for
Progress Energy under  "Financing  Activities"  for information  regarding PEC's
financing activities.

CONTRACTUAL OBLIGATIONS

The following table reflects PEC's contractual  obligations and other commercial
commitments  at December  31, 2003 in the  respective  periods in which they are
due:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)
-------------------------------------------------------------------------------------------------------
                                                   Less than 1                            More than 5
Contractual Obligations                 Total         year       1-3 years    3-5 years      years
-------------------------------------------------------------------------------------------------------
Long-term debt                         $ 3,408       $ 300        $  300      $   500       $ 2,308
Capital lease obligations                   35           2             4            4            25
Operating leases                           135           6            15           12           102
Fuel and purchased power                 2,062         543           659          313           547
Other purchase obligations                  18           5             -            -            13
North Carolina clean air capital
  commitments                              783          90           230          210           253
Funding obligations                        148          17             -           13           118
-------------------------------------------------------------------------------------------------------
Total                                  $ 6,589       $ 963       $ 1,208      $ 1,052       $ 3,366
                                      =================================================================
</TABLE>

Information on PEC's contractual obligations at December 31, 2002 is included in
the notes to the PEC Consolidated  Financial Statements.  Future debt maturities
are included in Note 8 to the PEC Consolidated Financial Statements.  PEC's fuel
and purchased power  obligations and lease obligations are included in Notes 16A
and 16B, respectively, to the PEC Consolidated Financial Statements. PEC's other
purchase obligations are included in Note 16A to the PEC Consolidated  Financial
Statements. PEC's North Carolina clean air legislation commitments are described
in Note 16E to PEC's Consolidated Financial Statements.  In 2004, PEC expects to
make  required  contributions  of $17 million  directly to pension  plan assets.
Decommissioning  cost provisions are included in Note 3D to the PEC Consolidated
Financial  Statements.  In 2008, PEC must begin transitioning  amounts currently
retained  internally to its external  decommissioning  funds.  The transition of
$131 million  must be complete by December  31,  2017,  and at least 10% must be
transitioned each year.

                                       68
<PAGE>

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PROGRESS ENERGY, INC.

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

These financial  instruments are held for purposes other than trading. The risks
discussed  below do not  include the price risks  associated  with  nonfinancial
instrument  transactions and positions associated with the Company's operations,
such as purchase and sales commitments and inventory.

Interest Rate Risk

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

The following  tables provide  information at December 31, 2003 and 2002,  about
the  Company's  interest rate  risk-sensitive  instruments.  The tables  present
principal cash flows and  weighted-average  interest rates by expected  maturity
dates  for the  fixed  and  variable  rate  long-term  debt  and  FPC  obligated
mandatorily redeemable securities of trust. The tables also include estimates of
the fair value of the Company's interest rate  risk-sensitive  instruments based
on quoted market prices for these or similar issues. For interest rate swaps and
interest  rate  forward  contracts,  the tables  present  notional  amounts  and
weighted-average  interest rates by contractual maturity dates. Notional amounts
are used to  calculate  the  contractual  cash flows to be  exchanged  under the
interest rate swaps and the  settlement  amounts under the interest rate forward
contracts. See "Interest Rate Derivatives" under LIQUIDITY AND CAPITAL RESOURCES
above for more information on interest rate derivatives.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

December 31, 2003                                                                                        Fair Value
                                                                                                         December 31,
(dollars in millions)               2004     2005      2006     2007      2008   Thereafter    Total        2003
-----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt         $  868     $ 349    $  909   $  674    $  827   $ 5,836     $ 9,463      $ 10,501
Average interest rate               6.67%     7.38%     6.78%    6.41%     6.27%     6.51%       6.55%
Variable rate long-term debt         -         -        -      $  241       -     $   861     $ 1,102      $  1,103
Average interest rate                -         -        -        3.04%      -        1.08%       1.51%
Debt to affiliated trust             -         -        -         -         -     $   309     $   309      $    313(d)
Interest rate                        -         -        -         -         -        7.10%       7.10%
Interest rate derivatives:
    Pay variable/receive
       fixed(a)                      -         -      $ (300)  $ (350)   $ (200)      -       $  (850)     $     (4)
    Payer swaptions(b)               -         -        -         -      $  400       -       $   400      $      5
    Interest rate collars(c)      $   65       -        -      $  130       -         -       $   195      $    (11)
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Receives floating rate based on three-month London Inter Bank Offering Rate
     (LIBOR). Designated as hedge of $850 million of fixed-rate debt.
(b)  PGN has the right to enter into a 3-year,  pay-fixed swap beginning January
     2005 at a fixed rate of 4.75%.
(c)  Interest  rate collars on $195  million  notional.  Designated  as hedge of
     variable rate interest.
(d)  Refer to Note 12F to the Progress Energy Consolidated Financial Statements.

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

December 31, 2002                                                                                          Fair Value
                                                                                                           December 31,
(dollars in millions)             2003      2004      2005      2006      2007      Thereafter     Total        2002
-----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt        $ 275     $  869    $  355    $  909    $  674      $ 5,614      $  8,696     $ 9,584
Average interest rate             6.42%      6.66%     7.38%     6.78%     6.41%        6.90%         6.83%          -
Variable rate long-term debt       -          -         -         -      $  225      $   861      $  1,086     $ 1,087
Average interest rate              -          -         -         -        0.03%        1.24%         1.61%          -
FPC mandatorily redeemable
    securities of trust            -          -         -         -         -        $   300      $    300     $   303
Interest rate                      -          -         -         -         -           7.10%         7.10%          -
Interest rate derivatives:
    Pay variable /receive
    fixed(a)                       -          -         -         -      $  350          -        $    350     $     5
    Interest rate forward
       contracts(b)              $  35        -         -         -         -            -        $     35     $    (1)
    Interest rate collars(c)       -       $   65       -         -      $  130          -        $    195     $   (12)
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Receives fixed and pays floating rate based on  three-month  LIBOR.

(b)  Treasury Rate Lock  agreement on $35 million  designated as cash flow hedge
     of  anticipated  debt  issuance.  (c) Interest rate collars on $195 million
     notional. Designated as hedge of variable rate interest.

Marketable Securities Price Risk

The Company's electric utility  subsidiaries  maintain trust funds,  pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents,  which
are exposed to price  fluctuations  in equity markets and to changes in interest
rates.  The fair  value of these  funds was $938  million  and $797  million  at
December  31, 2003 and 2002,  respectively.  The Company  actively  monitors its
portfolio by benchmarking  the  performance of its  investments  against certain
indices  and by  maintaining,  and  periodically  reviewing,  target  allocation
percentages   for   various   asset   classes.   The   accounting   for  nuclear
decommissioning  recognizes that the Company's  regulated electric rates provide
for  recovery  of these  costs net of any trust fund  earnings  and,  therefore,
fluctuations  in trust  fund  marketable  security  returns  do not  affect  the
earnings of the Company.

Contingent Value Obligations Market Value Risk

In  connection  with the  acquisition  of FPC,  the Company  issued 98.6 million
Contingent Value  Obligations  (CVOs).  Each CVO represents the right to receive
contingent  payments based on the  performance of four synthetic fuel facilities
purchased by  subsidiaries  of FPC in October 1999.  The  payments,  if any, are
based on the net after-tax  cash flows the facilities  generate.  These CVOs are
recorded  at fair value and  unrealized  gains and losses  from  changes in fair
value are recognized in earnings.  At December 31, 2003 and 2002, the fair value
of these CVOs was $23 million and $14 million,  respectively. A hypothetical 10%
decrease in the  December  31, 2003  market  price would  result in a $2 million
decrease in the fair value of the CVOs.

Commodity Price Risk

The  Company is exposed to the  effects of market  fluctuations  in the price of
natural  gas,  electricity  and  other  energy-related   products  marketed  and
purchased as a result of its ownership of energy-related  assets.  The Company's
exposure  to these  fluctuations  is  significantly  limited  by the  cost-based
regulation of PEC and PEF. In addition,  many of the Company's  long-term  power
sales contracts shift substantially all fuel responsibility to the purchaser.

The Company  uses  natural gas  hedging  instruments  to manage a portion of the
market  risk  associated  with  fluctuations  in the future  sales  price of the
Company's  natural gas. In addition,  the Company may engage in limited economic
hedging  and  trading  activity  using  natural  gas and  electricity  financial
instruments.  Refer to Note 17 to the  Progress  Energy  Consolidated  Financial
Statements for  additional  information  with regard to the Company's  commodity
contracts and use of derivative financial instruments.

                                       70
<PAGE>

PEC

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

Interest Rate Risk

The following  tables provide  information at December 31, 2003 and 2002,  about
PEC's interest rate risk sensitive instruments:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

December 31, 2003                                                                                     Fair Value
                                                                                                      December 31,
(dollars in millions)             2004    2005    2006    2007     2008     Thereafter       Total       2003
-----------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt        $ 300   $ 300      -    $ 200    $ 300     $  1,688      $ 2,788     $ 3,065
Average interest rate              6.9%   7.50%     -     6.80%    6.65%        6.09%        6.44%
Variable rate long-term debt       -       -        -       -        -      $    620      $   620     $   621
Average interest rate              -       -        -       -        -           -           1.09%

December 31, 2002                                                                                     Fair Value
                                                                                                     December 31,
(dollars in millions)            2003     2004     2005     2006    2007     Thereafter   Total          2002
-------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt          -     $ 300    $ 307       -    $ 200    $  1,638    $  2,445      $ 2,708
Average interest rate              -       6.9%    7.48%      -     6.80%       6.61%       6.76%           -
Variable rate long-term debt       -        -        -        -        -    $    620    $    620      $   620
Average interest rate              -        -        -        -        -        1.29%       1.29%           -
</TABLE>

Commodity Price Risk

PEC exposed to the effects of market  fluctuations  in the price of natural gas,
electricity and other energy-related products marketed and purchased as a result
of its ownership of energy-related  assets. PEC's exposure to these fluctuations
is  significantly  limited by cost-based  regulation.  PEC may engage in limited
economic  hedging  and  trading  activity  using  natural  gas  and  electricity
financial  instruments.  Refer  to  Note  12 to the  Progress  Energy  Carolinas
Consolidated  Financial  Statements  for additional  information  with regard to
PEC's commodity contracts and use of derivative financial instruments.

                                       71
<PAGE>

ITEM 8.   CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The  following  consolidated   financial  statements,   supplementary  data  and
consolidated financial statement schedules are included herein:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                                          Page
Progress Energy, Inc.
Independent Auditors' Report                                                                               74

Consolidated Financial Statements - Progress Energy, Inc.:

Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001                     75
Consolidated Balance Sheets at December 31, 2003 and 2002                                                  76
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001                 77
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2003,
   2002 and 2001                                                                                           78
Consolidated Quarterly Financial Data (Unaudited)                                                          79

Notes to Consolidated Financial Statements
   Note 1 - Organization and Summary of Significant Accounting Policies                                    80
   Note 2 - New Accounting Standards                                                                       84
   Note 3 - Divestitures                                                                                   85
   Note 4 - Acquisitions and Business Combinations                                                         87
   Note 5 - Property, Plant and Equipment                                                                  89
   Note 6 - Inventory                                                                                      93
   Note 7 - Regulatory Matters                                                                             94
   Note 8 - Goodwill and Other Intangible Assets                                                           97
   Note 9 - Impairments of Long-Lived Assets and Investments                                               98
   Note 10 - Equity                                                                                        99
   Note 11 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption                        102
   Note 12 - Debt and Credit Facilities                                                                   103
   Note 13 - Fair Value of Financial Instruments                                                          106
   Note 14 - Income Taxes                                                                                 107
   Note 15 - Contingent Value Obligations                                                                 109
   Note 16 - Benefit Plans                                                                                109
   Note 17 - Risk Management Activities and Derivatives Transactions                                      113
   Note 18 - Related Party Transactions                                                                   115
   Note 19 - Financial Information by Business Segment                                                    115
   Note 20 - Other Income and Other Expense                                                               116
   Note 21 - Commitments and Contingencies                                                                117
</TABLE>

                                       72
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
Independent Auditors' Report                                                                              128

Consolidated Financial Statements - Carolina Power & Light Company
   d/b/a Progress Energy Carolinas, Inc.:

Consolidated Statements of Income and Comprehensive Income for the Years Ended
       December 31, 2003, 2002, and 2001                                                                  129
Consolidated Balance Sheets at December 31, 2003 and 2002                                                 130
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002
   and 2001                                                                                               131
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2003, 2002
   and 2001                                                                                               132
Consolidated Quarterly Financial Data (Unaudited)                                                         132

Notes to Consolidated Financial Statements
   Note 1 - Organization and Summary of Significant Accounting Policies                                   133
   Note 2 - New Accounting Standards                                                                      136
   Note 3 - Property, Plant and Equipment                                                                 138
   Note 4 - Inventory                                                                                     141
   Note 5 - Regulatory Matters                                                                            141
   Note 6 - Impairments of Long-Lived Assets and Investments                                              143
   Note 7 - Equity                                                                                        144
   Note 8 - Debt and Credit Facilities                                                                    146
   Note 9 - Fair Value of Financial Instruments                                                           147
   Note 10 - Income Taxes                                                                                 147
   Note 11 - Benefit Plans                                                                                149
   Note 12 - Risk Management Activities and Derivatives Transactions                                      152
   Note 13 - Related Party Transactions                                                                   153
   Note 14 - Financial Information by Business Segment                                                    153
   Note 15 - Other Income and Other Expense                                                               154
   Note 16 - Commitments and Contingencies                                                                155

Independent Auditors' Report on Consolidated Financial Statement Schedule - Progress Energy, Inc.         163
Independent Auditors' Report on Consolidated Financial Statement Schedule - Carolina Power &
           Light Company d/b/a Progress Energy Carolinas, Inc.                                            164

Consolidated Financial Statement Schedules for the Years Ended December 31,
2003, 2002 and 2001:

           II-Valuation and Qualifying Accounts - Progress Energy, Inc.                                   165
           II-Valuation and Qualifying Accounts - Carolina Power & Light Company
                  d/b/a Progress Energy Carolinas, Inc.                                                   166
</TABLE>

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

                                       73
<PAGE>

INDEPENDENT AUDITORS' REPORT

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

We have audited the accompanying consolidated balance sheets of Progress Energy,
Inc.  and its  subsidiaries  at  December  31,  2003 and 2002,  and the  related
consolidated statements of income, changes in common stock equity and cash flows
for each of the  three  years in the  period  ended  December  31,  2003.  These
financial  statements are the  responsibility of the Company's  management.  Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

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

In our  opinion,  such  financial  statements  present  fairly,  in all material
respects, the financial position of the Company and its subsidiaries at December
31, 2003 and 2002, and the results of their  operations and their cash flows for
each of the three years in the period ended  December 31,  2003,  in  conformity
with accounting principles generally accepted in the United States of America.

As discussed in Notes 5F and 17A to the consolidated  financial  statements,  in
2003, the Company adopted  Statement of Financial  Accounting  Standards No. 143
and  Derivatives  Implementation  Group Issue C20. As discussed in Note 8 to the
consolidated  financial  statements,  in 2002, the Company changed its method of
accounting  for  goodwill  to  conform  to  Statement  of  Financial  Accounting
Standards No. 142.

/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004

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

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
                                                                                Years ended December 31
(In millions except per share data)                                        2003           2002           2001
--------------------------------------------------------------------------------------------------------------
Operating Revenues
   Utility                                                              $ 6,741        $ 6,601        $ 6,557
   Diversified business                                                   2,002          1,490          1,572
--------------------------------------------------------------------------------------------------------------
      Total Operating Revenues                                            8,743          8,091          8,129
--------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
   Fuel used in electric generation                                       1,695          1,586          1,543
   Purchased power                                                          862            862            868
   Operation and maintenance                                              1,419          1,390          1,228
   Depreciation and amortization                                            883            820          1,067
   Taxes other than on income                                               405            386            380
Diversified business
   Cost of sales                                                          1,746          1,410          1,589
   Depreciation and amortization                                            157            118             83
   Impairment of long-lived assets                                           17            364             43
   Other                                                                    197            145             92
--------------------------------------------------------------------------------------------------------------
        Total Operating Expenses                                          7,381          7,081          6,893
--------------------------------------------------------------------------------------------------------------
Operating Income                                                          1,362          1,010          1,236
--------------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                           11             15             22
   Impairment of investments                                                (21)           (25)          (164)
   Other, net                                                               (25)            27            (34)
--------------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                                        (35)             17          (176)
--------------------------------------------------------------------------------------------------------------
Interest Charges
   Net interest charges                                                     632            641            690
   Allowance for borrowed funds used during construction                     (7)            (8)           (17)
--------------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                         625            633            673
--------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax and
   Cumulative Effect of Changes in Accounting Principles                    702            394            387
Income Tax Benefit                                                         (109)          (158)          (154)
--------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Cumulative Effect of
   Changes in Accounting Principles                                         811            552            541
Discontinued Operations, Net of Tax                                          (8)           (24)             1
--------------------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Changes in Accounting
   Principles                                                               803            528            542
Cumulative Effect of Changes in Accounting Principles,
   Net of Tax                                                               (21)             -              -
--------------------------------------------------------------------------------------------------------------
Net Income                                                              $   782        $   528        $   542
--------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding                                           237            217            205
--------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
    Income from Continuing Operations before Cumulative Effect
       of Changes in Accounting Principles                              $  3.42        $  2.54        $  2.64
    Discontinued Operations, Net of Tax                                    (.03)          (.11)           .01
    Cumulative Effect of Changes in Accounting Principles, Net of Tax      (.09)             -              -
    Net Income                                                          $  3.30        $  2.43        $  2.65
--------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
    Income from Continuing Operations before Cumulative Effect
       of Changes in Accounting Principles                              $  3.40        $  2.53        $  2.63
    Discontinued Operations, Net of Tax                                    (.03)          (.11)           .01
    Cumulative Effect of Changes in Accounting Principles, Net of Tax      (.09)             -              -
    Net Income                                                          $  3.28        $  2.42        $  2.64
--------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share                                     $  2.26        $  2.20        $  2.14
--------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

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

PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In millions)                                                                              December 31
ASSETS                                                                               2003              2002
------------------------------------------------------------------------------------------------------------
Utility Plant
  Utility plant in service                                                     $   21,675         $  20,157
  Accumulated depreciation                                                         (8,116)           (7,540)
------------------------------------------------------------------------------------------------------------
        Utility plant in service, net                                              13,559            12,617
  Held for future use                                                                  13                15
  Construction work in progress                                                       634               752
  Nuclear fuel, net of amortization                                                   228               217
------------------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                                   14,434            13,601
------------------------------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                                           273                61
  Accounts receivable                                                                 865               737
  Unbilled accounts receivable                                                        217               225
  Inventory                                                                           808               875
  Deferred fuel cost                                                                  317               184
  Assets of discontinued operations                                                     -               490
  Prepayments and other current assets                                                348               262
------------------------------------------------------------------------------------------------------------
        Total Current Assets                                                        2,828             2,834
------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                                                   612               347
  Nuclear decommissioning trust funds                                                 938               797
  Diversified business property, net                                                2,158             1,884
  Miscellaneous other property and investments                                        464               519
  Goodwill                                                                          3,726             3,719
  Prepaid pension costs                                                               462                60
  Intangibles, net                                                                    327               155
  Other assets and deferred debits                                                    253               292
------------------------------------------------------------------------------------------------------------
        Total Deferred Debits and Other Assets                                      8,940             7,773
------------------------------------------------------------------------------------------------------------
           Total Assets                                                        $   26,202         $  24,208
------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
------------------------------------------------------------------------------------------------------------
Common Stock Equity
  Common stock without par value, 500 million shares authorized,
      246 and 238 million shares issued and outstanding,                       $    5,270         $   4,951
  respectively
  Unearned restricted shares (1 and 1 million shares, respectively)                   (17)              (21)
  Unearned ESOP shares (4 and 5 million shares, respectively)                         (89)             (102)
  Accumulated other comprehensive loss                                                (50)             (238)
  Retained earnings                                                                 2,330             2,087
------------------------------------------------------------------------------------------------------------
        Total Common Stock Equity                                                   7,444             6,677
------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption                    93                93
Long-Term Debt Affiliate                                                              309                 -
Long-Term Debt                                                                      9,625             9,747
------------------------------------------------------------------------------------------------------------
        Total Capitalization                                                       17,471            16,517
------------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                                   868               275
  Accounts payable                                                                    704               659
  Interest accrued                                                                    209               220
  Dividends declared                                                                  140               132
  Short-term obligations                                                                4               695
  Customer deposits                                                                   167               158
  Liabilities of discontinued operations                                                -               125
  Other current liabilities                                                           572               430
------------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                                   2,664             2,694
------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                                                   737               858
  Accumulated deferred investment tax credits                                         190               206
  Regulatory liabilities                                                            2,938               120
  Cost of removal                                                                       -             2,940
  Asset retirement obligations                                                      1,271                 -
  Other liabilities and deferred credits                                              931               873
------------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                                6,067             4,997
------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 21)
------------------------------------------------------------------------------------------------------------
           Total Capitalization and Liabilities                                $   26,202         $  24,208
------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

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

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
------------------------------------------------------------------------------------------------------------------------

Years ended December 31
(In millions)                                                                       2003            2002           2001
------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                      $    782        $    528       $    542
Adjustments to reconcile net income to net cash provided by operating
activities:
      Loss (income) from discontinued operations                                       8              24             (1)
      Impairment of long-lived assets and investments                                 38             389            207
      Cumulative effect of changes in accounting principles                           21               -              -
      Depreciation and amortization                                                1,146           1,099          1,266
      Deferred income taxes                                                         (276)           (402)          (367)
      Investment tax credit                                                          (16)            (18)           (23)
      Deferred fuel cost (credit)                                                   (133)            (37)            69
      Cash provided (used) by changes in operating assets and
liabilities:
         Accounts receivable                                                        (168)            (35)           183
         Inventories                                                                  78             (49)          (299)
         Prepayments and other current assets                                         25             (39)           (21)
         Accounts payable                                                             41             100           (213)
         Other current liabilities                                                   167              56            123
         Other                                                                        75              28            (93)
------------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                 1,788           1,644          1,373
------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions                                                  (1,018)         (1,174)        (1,177)
Diversified business property additions                                             (607)           (570)          (350)
Nuclear fuel additions                                                              (117)            (81)          (116)
Proceeds from sales of subsidiaries and investments                                  579              43             53
Acquisition of businesses, net of cash                                                 -            (365)             -
Acquisition of intangibles                                                          (200)            (10)             -
Other                                                                                (17)            (61)           (66)
------------------------------------------------------------------------------------------------------------------------
          Net Cash Used in Investing Activities                                   (1,380)         (2,218)        (1,656)
------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net                                                        304             687            488
Issuance of long-term debt, net                                                    1,539           1,783          4,564
Net decrease in short-term indebtedness                                             (696)           (247)        (4,018)
Retirement of long-term debt                                                        (810)         (1,157)          (322)
Dividends paid on common stock                                                      (541)           (480)          (432)
Other                                                                                  8              (5)           (42)
------------------------------------------------------------------------------------------------------------------------
           Net Cash Provided by (Used in) Financing Activities                      (196)            581            238
------------------------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations                                                   -               -             (1)
------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                 212               7            (46)
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year                                        61              54            100
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                        $    273        $     61       $      54
------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                $    612        $    631       $    588
                            income taxes (net of refunds                        $    177        $    219       $    127
</TABLE>

Noncash Activities
o    In April 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  million in common stock (See Note
     4E).
o    In  December  2003,  Progress  Telecommunications   Corporation  (PTC)  and
     Caronet,  Inc.,  both  indirectly  wholly-owned  subsidiaries  of  Progress
     Energy, and EPIK Communications, Inc., a wholly-owned subsidiary of Odyssey
     Telecorp,   Inc.,  contributed   substantially  all  of  their  assets  and
     transferred certain  liabilities to Progress Telecom,  LLC, a subsidiary of
     PTC (See Note 4A).

See Notes to Consolidated Financial Statements.

                                       77
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
                                                                         Unearned     Accumulated                  Total
                                             Common Stock     Unearned     ESOP          Other                     Common
(In millions except per share data)          Outstanding     Restricted   Common    Comprehensive    Retained      Stock
                                          Shares     Amount    Stock      Stock     Income (Loss)    Earnings     Equity
---------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2001                      206    $ 3,621      $ (13)    $ (127)        -          $ 1,943      $ 5,424
Net income                                                                                                542          542
FAS 133 transition adjustment (net of
    tax of $15)                                                                          (24)                          (24)
Change in net unrealized losses on cash
    flow hedges (net of tax of $13)                                                      (21)                          (21)
Reclassification adjustment for amounts
    included in net income (net of tax
    of $9)                                                                                14                            14
Foreign currency translation and other                                                    (1)                           (1)
                                                                                                                -----------
Comprehensive income                                                                                                   510
                                                                                                                -----------
Issuance of shares                             13        489                                                           489
Purchase of restricted stock                                         (8)                                                (8)
Restricted stock expense recognition                                  6                                                  6
Cancellation of restricted shares                         (1)         1                                                  -
Allocation of ESOP shares                                 12                    13                                      25
Dividends ($2.14 per share)                                                                              (442)        (442)
---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001                    219      4,121        (14)      (114)      (32)           2,043        6,004
Net income                                                                                                528          528
Change in net unrealized losses on cash
    flow hedges (net of tax of $18)                                                      (28)                          (28)
Reclassification adjustment for amounts
    included in net income (net of tax
    of $10)                                                                               16                            16
Foreign currency translation and other                                                    (2)                           (2)
Minimum pension liability adjustment
    (net of tax of $121)                                                                (192)                         (192)
                                                                                                                -----------
Comprehensive income                                                                                                   322
                                                                                                                -----------
Issuance of shares                             19        815                                                           815
Purchase of restricted stock                                        (16)                                               (16)
Restricted stock expense recognition                                  8                                                  8
Cancellation of restricted shares                         (1)         1                                                  -
Allocation of ESOP shares                                 16                    12                                      28
Dividends ($2.20 per share)                                                                              (484)        (484)
---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002                    238      4,951        (21)      (102)     (238)           2,087        6,677
Net income                                                                                                782          782
Change in net unrealized losses on cash
    flow hedges (net of tax of $7)                                                       (12)                          (12)
Reclassification adjustment for amounts
    included in net income (net of tax
    of ($11))                                                                             19                            19
Foreign currency translation and other                                                     4                             4
Minimum pension liability adjustment
      (net of tax of ($112))                                                             177                           177
                                                                                                                -----------
Comprehensive income                                                                                                   970
                                                                                                                -----------
Issuance of shares                              8        309                                                           309
Purchase of restricted stock                              (1)        (7)                                                (8)
Restricted stock expense recognition                                 10                                                 10
Cancellation of restricted shares                         (1)         1                                                  -
Allocation of ESOP shares                                 12                    13                                      25
Dividends ($2.26 per share)                                                                              (539)        (539)
---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003                    246    $ 5,270      $ (17)    $  (89)    $ (50)         $ 2,330      $ 7,444
===========================================================================================================================
</TABLE>

See Notes to Consolidated Financial Statements.

                                       78
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

(In millions except per share data)                 First           Second             Third        Fourth
                                                   Quarter          Quarter           Quarter       Quarter
------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues                                 $ 2,187          $ 2,050           $ 2,458       $ 2,048
Operating income                                       357              274               478           253
Income from continuing operations                      208              154               337           112
Income before cumulative effect of
     changes in accounting principles                  218              157               318           110
Net income                                             219              157               318            88
Common stock data:
Basic earnings per common share
     Income from continuing operations                0.89             0.65              1.41          0.47
     Income before cumulative effect of
         changes in accounting principles             0.94             0.67              1.33          0.46
     Net income                                       0.94             0.67              1.33          0.37
Diluted earnings per common share
     Income from continuing operations                0.89             0.65              1.40          0.47
     Income before cumulative effect of
         changes in accounting principles             0.93             0.66              1.33          0.46
     Net income                                       0.94             0.66              1.33          0.37
Dividends paid per common share                      0.560            0.560             0.560         0.560
Market price per share - High                        46.10            48.00             45.15         46.00
                         Low                         37.45            38.99             39.60         41.60
------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues                                 $ 1,813          $ 1,994           $ 2,316       $ 1,968
Operating income                                       244              306               201           259
Income from continuing operations                      124              122               157           149
Net income                                             133              121               152           122
Common stock data:
Basic earnings per common share
     Income from continuing operations                0.58             0.57              0.72          0.66
     Net income                                       0.62             0.56              0.71          0.55
Diluted earnings per common share
     Income from continuing operations                0.58             0.56              0.71          0.66
     Net income                                       0.62             0.56              0.70          0.55
Dividends paid per common share                      0.545            0.545             0.545         0.545
Market price per share - High                        50.86            52.70             51.97         44.82
                         Low                         43.01            47.91             36.54         32.84
</TABLE>

o    In the opinion of management,  all adjustments  necessary to fairly present
     amounts shown for interim periods have been made. Results of operations for
     an interim  period may not give a true  indication of results for the year.
     All amounts were  restated for  discontinued  operations  (See Note 3A) and
     2003 amounts  were  restated  for the  cessation  of reporting  results for
     portions of the Fuels'  segment  operations  one month in arrears (See Note
     1B).
o    Fourth  quarter  2003  includes  impairments  related to  Kentucky  May and
     Affordable  Housing  investment of $38 million ($24 million after-tax) (See
     Note 9).
o    Fourth  quarter 2003  includes a cumulative  effect for DIG Issue 20 of $38
     million ($23 million after-tax) (See Note 17).
o    Third quarter 2002 includes  impairment  and other charges  related to PTC,
     Caronet and  Interpath  Communications,  Inc. of $355 million ($225 million
     after-tax) (See Note 9).
o    Fourth quarter 2002 includes  estimated  impairment of assets held for sale
     of Railcar Ltd. of $59 million ($40 million after-tax) (See Note 3B).

See Notes to Consolidated Financial Statements.

                                       79
<PAGE>

PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   Organization and Summary of Significant Accounting Policies

     A. Organization

     Progress Energy, Inc. (Progress Energy or the Company) is a holding company
     headquartered in Raleigh,  North Carolina.  The Company is registered under
     the Public Utility Holding  Company Act of 1935 (PUHCA),  as amended and as
     such,  the  Company  and its  subsidiaries  are  subject to the  regulatory
     provisions  of PUHCA.  Effective  January 1, 2003,  three of the  Company's
     subsidiaries,   Carolina  Power  &  Light  Company  (CP&L),  Florida  Power
     Corporation  and Progress  Ventures,  Inc.,  began doing business under the
     assumed names  Progress  Energy  Carolinas,  Inc.  (PEC),  Progress  Energy
     Florida, Inc. (PEF) and Progress Energy Ventures, Inc. (PVI), respectively.
     The legal names of these entities have not changed.  The current  corporate
     and business unit structure remains unchanged.

     Through its  wholly-owned  subsidiaries,  PEC and PEF,  the  Company's  PEC
     Electric  and  PEF  segments  are  primarily  engaged  in  the  generation,
     transmission,  distribution  and sale of  electricity  in portions of North
     Carolina,  South Carolina and Florida.  The Progress Ventures business unit
     consists of the Fuels business  segment (Fuels) and Competitive  Commercial
     Operations  (CCO)  operating  segments.  The Fuels  segment is  involved in
     natural gas drilling and production,  coal terminal services,  coal mining,
     synthetic  fuel  production,  fuel  transportation  and  delivery.  The CCO
     segment includes  nonregulated  generation and energy marketing activities.
     Through  the Rail  Services  (Rail)  segment,  the  Company is  involved in
     nonregulated  railcar repair, rail parts  reconditioning and sales, railcar
     leasing and sales,  and scrap metal  recycling.  Through its other business
     units, the Company engages in other nonregulated business areas,  including
     telecommunications  and energy  management and related  services.  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

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

     Unconsolidated  investments  in  companies  over which the Company does not
     have control,  but has the ability to exercise influence over operating and
     financial policies (generally 20% - 50% ownership), are accounted for under
     the equity method of  accounting.  Certain  investments  in debt and equity
     securities that have readily  determinable market values, and for which the
     Company  does  not  have  control,  are  accounted  for at  fair  value  in
     accordance with SFAS No. 115,  "Accounting for Certain  Investments in Debt
     and Equity  Securities."  Other investments are stated principally at cost.
     These equity and cost  investments,  which total  approximately $57 million
     and $109 million at December 31, 2003 and 2002, respectively,  are included
     in miscellaneous other property and investments in the Consolidated Balance
     Sheets. The primary component of this balance is the Company's  investments
     in  affordable  housing of $29 million and $72 million at December 31, 2003
     and 2002,  respectively.  This  decrease  is  primarily  due to the sale of
     certain PEC  investments  in the third quarter of 2003. For a discussion of
     how  new  FASB   interpretations   will  affect  these  affordable  housing
     investments see Note 2.

     The results of operations of Rail are reported one month in arrears. During
     2003,  the  Company  ceased  recording   portions  of  the  Fuels'  segment
     operations  one month in arrears.  The net impact of this action  increased
     net income by $2 million for the year.

     Certain amounts for 2002 and 2001 have been  reclassified to conform to the
     2003 presentation.

                                       80
<PAGE>

     C. Significant Accounting Policies

     Use of Estimates and Assumptions
     In  preparing  consolidated  financial  statements  that conform with GAAP,
     management  must make  estimates and  assumptions  that affect the reported
     amounts of assets and  liabilities,  disclosure  of  contingent  assets and
     liabilities  at the  date  of the  consolidated  financial  statements  and
     amounts of revenues and expenses  reflected  during the  reporting  period.
     Actual results could differ from those estimates.

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

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

     Excise Taxes
     PEC and PEF collect from customers certain excise taxes levied by the state
     or local  government  upon the  customers.  PEC and PEF  account for excise
     taxes on a gross basis.  For the years ended  December  31, 2003,  2002 and
     2001,  gross  receipts  tax,  franchise  taxes  and other  excise  taxes of
     approximately  $217 million,  $211 million and $210 million,  respectively,
     are included in taxes other than on income in the accompanying Consolidated
     Statements  of Income.  These  approximate  amounts  are also  included  in
     utility revenues.

     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.  The exercise price at which options
     are granted by the Company  equals the market price at the grant date,  and
     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" (SFAS No. 148),  the  estimated  fair
     value of the  Company's  stock  options is  amortized  to expense  over the
     options' vesting period.  The following table illustrates the effect on net
     income and  earnings per share if the fair value method had been applied to
     all outstanding and unvested awards in each period:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions except per share data)                                2003        2002       2001
                                                                    ---------   ---------  ---------
     Net income, as reported                                          $  782      $  528     $  542
     Deduct:  Total stock option expense determined under fair
          value method for all awards, net of related tax effects         11           8          2
                                                                   ---------    --------   ---------
     Pro forma net income                                             $  771      $  520     $  540
                                                                    =========   =========  =========

     Earnings per share
       Basic - as reported                                            $ 3.30      $ 2.43     $ 2.65
       Basic - pro forma                                              $ 3.25      $ 2.40     $ 2.64
       Diluted - as reported                                          $ 3.28      $ 2.42     $ 2.64
       Diluted - pro forma                                            $ 3.24      $ 2.39     $ 2.63
</TABLE>

                                       81
<PAGE>

     Utility Plant
     Utility  plant in service  is stated at  historical  cost less  accumulated
     depreciation. The Company capitalizes all construction-related direct labor
     and  material  costs of units of property as well as indirect  construction
     costs.   The  cost  of  renewals  and  betterments  is  also   capitalized.
     Maintenance and repairs of property, and replacements and renewals of items
     determined  to be less than units of property,  are charged to  maintenance
     expense as  incurred.  The cost of units of  property  replaced or retired,
     less  salvage,  is  charged  to  accumulated   depreciation.   Removal  and
     decommissioning  costs were charged to regulatory  liabilities  in 2003 and
     cost of removal in 2002. The Company  follows the guidance in SFAS No. 143,
     "Accounting  for  Asset  Retirement  Obligations,"  to  account  for  legal
     obligations  associated with the retirement of certain tangible  long-lived
     assets.

     Depreciation and Amortization - Utility Plant
     For financial reporting purposes, substantially all depreciation of utility
     plant other than nuclear fuel is computed on the straight-line method based
     on the  estimated  remaining  useful  life of the  property,  adjusted  for
     estimated  salvage (See Note 5A). The North Carolina  Utilities  Commission
     (NCUC),  the Public Service  Commission of South  Carolina  (SCPSC) and the
     Florida  Public  Service  Commission  (FPSC)  can also  grant  approval  to
     accelerate or reduce  depreciation  and amortization of utility assets (See
     Note 7).

     Amortization  of nuclear fuel costs,  including  disposal costs  associated
     with  obligations  to  the  U.S.  Department  of  Energy  (DOE)  and  costs
     associated  with  obligations  to  the  DOE  for  the  decommissioning  and
     decontamination  of  enrichment  facilities,  is computed  primarily on the
     units-of-production  method and charged to fuel used in electric generation
     in the  accompanying  Consolidated  Statements of Income.  In the Company's
     retail  jurisdictions,  provisions  for nuclear  decommissioning  costs are
     approved by the NCUC, the SCPSC and the FPSC and are based on site-specific
     estimates that include the costs for removal of all  radioactive  and other
     structures at the site. In the wholesale jurisdictions,  the provisions for
     nuclear decommissioning costs are approved by the Federal Energy Regulatory
     Commission (FERC).

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

     Allowance for Doubtful Accounts
     The Company maintains an allowance for doubtful accounts receivable,  which
     totaled  approximately $28 million and $40 million at December 31, 2003 and
     2002,  respectively,   and  is  included  in  accounts  receivable  on  the
     Consolidated Balance Sheets.

     Inventory
     The Company accounts for inventory using the average-cost method.

     Regulatory Assets and Liabilities
     The Company's regulated operations are subject to SFAS No. 71, which allows
     a regulated  company to record  costs that have been or are  expected to be
     allowed in the ratemaking  process in a period different from the period in
     which the costs would be charged to expense by a  nonregulated  enterprise.
     Accordingly,  the Company records assets and  liabilities  that result from
     the regulated  ratemaking process that would not be recorded under GAAP for
     nonregulated  entities.  These regulatory assets and liabilities  represent
     expenses  deferred for future  recovery from customers or obligations to be
     refunded to customers  and are  primarily  classified  in the  accompanying
     Consolidated Balance Sheets as regulatory assets and regulatory liabilities
     (See Note 7A).

     Diversified Business Property
     Diversified   business   property  is  stated  at  cost  less   accumulated
     depreciation.  If an impairment  is recognized on an asset,  the fair value
     becomes  its new cost  basis.  The costs of renewals  and  betterments  are
     capitalized.  The cost of repairs and  maintenance is charged to expense as
     incurred.  Depreciation  is  computed  on a  straight-line  basis using the
     estimated useful lives disclosed in Note 5B. Depletion of mineral rights is
     provided on the  units-of-production  method  based upon the  estimates  of
     recoverable amounts of clean mineral.

     The  Company  uses the full cost  method to account for its natural gas and
     oil properties.  Under the full cost method,  substantially  all productive
     and  nonproductive  costs  incurred  in  connection  with the  acquisition,
     exploration   and   development   of  natural  gas  and  oil  reserves  are
     capitalized.  These  capitalized  costs  include the costs of all  unproved
     properties,  internal costs directly related to acquisition and exploration
     activities.  The amortization  base also includes the estimated future cost

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<PAGE>

     to develop  proved  reserves.  Except for costs of unproved  properties and
     major development  projects in progress,  all costs are amortized using the
     units-of-production method over the life of the Company's proved reserves.

     Goodwill and Intangible Assets
     Effective January 1, 2002, the Company adopted SFAS No. 142,  "Goodwill and
     Other Intangible Assets" (SFAS No. 142), and no longer amortizes  goodwill.
     Instead,  goodwill  is  subject  to  at  least  an  annual  assessment  for
     impairment by applying a two-step  fair-value-based  test.  This assessment
     could result in periodic impairment charges.  Prior to the adoption of SFAS
     No. 142, the Company  amortized  goodwill on a  straight-line  basis over a
     period not exceeding 40 years.  Intangible assets are being amortized based
     on the economic benefit of their respective lives.

     Unamortized Debt Premiums, Discounts and Expenses
     Long-term debt premiums,  discounts and issuance expenses for the utilities
     are  amortized  over the life of the related  debt using the  straight-line
     method. Any expenses or call premiums  associated with the reacquisition of
     debt  obligations by the utilities are amortized  over the applicable  life
     using the straight-line method consistent with ratemaking treatment.

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

     Derivatives
     Effective  January 1, 2001, the Company  adopted SFAS No. 133,  "Accounting
     for  Derivative  Instruments  and Hedging  Activities"  (SFAS No. 133),  as
     amended  by SFAS No.  138 and SFAS No.  149.  SFAS  No.  133,  as  amended,
     establishes accounting and reporting standards for derivative  instruments,
     including certain derivative  instruments embedded in other contracts,  and
     for hedging activities.  SFAS No. 133 requires that an entity recognize all
     derivatives as assets or liabilities in the balance sheet and measure those
     instruments  at  fair  value.   During  2003,  the  FASB   reconsidered  an
     interpretation  of  SFAS  No.  133.  See  Note  17 for  the  effect  of the
     interpretation  and  additional   information   regarding  risk  management
     activities and derivative transactions.

     Environmental
     The Company accrues environmental remediation liabilities when the criteria
     for SFAS No. 5, "Accounting for Contingencies" (SFAS No. 5), have been met.
     Environmental   expenditures   are  expensed  as  incurred  or  capitalized
     depending on their future economic benefit.  Expenditures that relate to an
     existing  condition  caused  by past  operations  and that  have no  future
     economic  benefits  are  expensed.   Accruals  for  estimated  losses  from
     environmental  remediation  obligations  generally are  recognized no later
     than  completion  of the  remedial  feasibility  study.  Such  accruals are
     adjusted as additional  information develops or circumstances change. Costs
     of future  expenditures for environmental  remediation  obligations are not
     discounted to their present value. Recoveries of environmental  remediation
     costs from  other  parties  are  recognized  when  their  receipt is deemed
     probable (See Note 21E).

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

                                       83
<PAGE>

     The Company reviews its investments to evaluate whether or not a decline in
     fair value below the carrying value is an other-than-temporary decline. The
     Company  considers  various factors,  such as the investee's cash position,
     earnings and revenue outlook,  liquidity and management's  ability to raise
     capital in determining whether the decline is other-than-temporary.  If the
     Company determines that an other-than-temporary decline exists in the value
     of  its  investments,  it is  the  Company's  policy  to  write-down  these
     investments  to fair  value.  See  Note 9 for a  discussion  of  impairment
     evaluations performed and charges taken.

     Under  the  full  cost  method  of  accounting  for  natural  gas  and  oil
     properties,  total  capitalized costs are limited to a ceiling based on the
     present  value of  discounted  (at 10%) future net revenues  using  current
     prices, plus the lower of cost or fair market value of unproved properties.
     If the ceiling (discounted  revenues) is not equal to or greater than total
     capitalized costs, the Company is required to write-down  capitalized costs
     to this level.  The Company  performs this ceiling test  calculation  every
     quarter. No write-downs were required in 2003, 2002 or 2001.

     Subsidiary Stock Transactions
     Gains  and  losses  realized  as a  result  of  common  stock  sales by the
     Company's  subsidiaries  are  recorded in the  Consolidated  Statements  of
     Income,  except for any  transactions  that must be  credited  directly  to
     equity in accordance  with the  provisions of SAB No. 51,  "Accounting  for
     Sales of Stock by a Subsidiary."

2.   New Accounting Standards

     SFAS  No.  150,   "Accounting  for  Certain   Financial   Instruments  with
     Characteristics of Both Liabilities and Equity"
     In May 2003, the Financial  Accounting  Standards  Board (FASB) issued SFAS
     No. 150, "Accounting for Certain Financial Instruments with Characteristics
     of Both  Liabilities  and Equity" (SFAS No. 150).  The adoption of SFAS No.
     150 did not have an impact on the Company's  financial  position or results
     of operations as of and for the periods ended December 31, 2003.

     EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans"
     In May 2003,  the Emerging  Issues Task Force (EITF)  reached  consensus in
     EITF Issue No. 03-04,  "Accounting for `Cash Balance'  Pension Plans" (EITF
     03-04),  to  specifically  address the  accounting for certain cash balance
     pension plans.  The consensus  reached in EITF 03-04 requires  certain cash
     balance  pension plans to be accounted for as defined  benefit  plans.  For
     cash balance plans described in EITF 03-04, 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 plan as a defined benefit plan;  however,  the Company was
     required  to adopt the  measurement  provisions  of EITF  03-04 at its cash
     balance plan's  measurement  date of December 31, 2003. Any  differences in
     the  measurement of the obligations as a result of applying EITF 03-04 were
     reported as a component of actuarial gain or loss.  The ongoing  effects of
     this  standard  are  dependent  on  other  factors  that  also  affect  the
     determination of actuarial gains and losses and the subsequent amortization
     of such  gains and  losses.  However,  the  adoption  of EITF  03-04 is not
     expected to have a material  effect on the Company's  results of operations
     or financial position.

     SFAS No. 149,  "Amendment of Statement 133 on  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. Interpretations and
     implementation  issues with regard to SFAS No. 149 continue to evolve.  The
     statement  had no  significant  impact  on  the  Company's  accounting  for
     contracts  entered into subsequent to the  statement's  effective date (See
     Note 17).  Future effects,  if any, on the Company's  results of operations
     and  financial  condition  will be  dependent  on the  specifics  of future
     contracts entered into with regard to guidance provided by the statement.

     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  and  determining   whether  such  entities  should  be
     consolidated.  FIN No. 46 requires an enterprise to  consolidate a variable
     interest  entity when the enterprise (a) absorbs a majority of the variable
     interest entity's expected losses,  (b) receives a majority of the entity's
     expected residual returns,  or both, as a result of ownership,  contractual
     or other financial interests in the entity.  Prior to the effective date of

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<PAGE>

     FIN No. 46, entities were generally  consolidated by an enterprise that had
     control through ownership of a majority voting interest in the entity.  FIN
     No. 46 originally applied immediately to variable interest entities created
     or  obtained  after  January 31,  2003.  During  2003,  the Company did not
     participate  in the creation of, or obtain a new variable  interest in, any
     variable  interest entity.  In December 2003, the FASB issued a revision to
     FIN No. 46 (FIN No. 46R), which modified certain requirements of FIN No. 46
     and allowed for the optional  deferral of the effective date of FIN No. 46R
     until March 31,  2004.  However,  entities  subject to FIN No. 46R that are
     deemed to be  special-purpose  entities  (as  defined in FIN No.  46R) must
     implement  either  FIN No. 46 or FIN No.  46R at  December  31,  2003.  The
     Company  elected  to apply FIN No.  46 to  special-purpose  entities  as of
     December  31, 2003.  Because the Company  expects  additional  transitional
     guidance   to  be  issued,   it  has  elected  to  apply  FIN  No.  46R  to
     non-special-purpose entities as of March 31, 2004.

     Prior to the  adoption  of FIN No. 46,  the  Company  consolidated  the FPC
     Capital  I  trust  (the  Trust),  which  holds  FPC-obligated   mandatorily
     redeemable preferred securities.  The Trust is a special-purpose  entity as
     defined in FIN No. 46R, and therefore the Company applied FIN No. 46 to the
     Trust at December 31, 2003. The Trust is a variable  interest  entity,  but
     the Company does not absorb a majority of the Trust's  expected  losses and
     therefore  is  not  its  primary   beneficiary.   Therefore,   the  Company
     deconsolidated  the  Trust  at  December  31,  2003.  This  deconsolidation
     resulted in  recording  an  additional  equity  investment  in the Trust of
     approximately $9 million,  an increase in outstanding debt of approximately
     $8  million  and a  gain  of  approximately  $1  million  relating  to  the
     cumulative effect of a change in accounting  principle.  See Note 12F for a
     discussion of the Company's guarantees with the Trust.

     The Company also has investments in 14 limited  partnerships  accounted for
     under the equity method for which it may be the primary beneficiary.  These
     partnerships  invest  in and  operate  low-income  housing  and  historical
     renovation  properties that qualify for federal and state tax credits.  The
     Company has not concluded  whether it is the primary  beneficiary  of these
     partnerships.  These  partnerships are partially funded with financing from
     third-party  lenders,  which is secured by the assets of the  partnerships.
     The creditors of the  partnerships do not have recourse to the Company.  At
     December  31,  2003,  the  maximum  exposure  to  loss as a  result  of the
     Company's  investments in these limited  partnerships was  approximately $9
     million.   The  Company   expects  to  complete  its  evaluation  of  these
     partnerships  under FIN No. 46R during  the first  quarter of 2004.  If the
     Company had  consolidated  these 14 entities at December 31, 2003, it would
     have  recorded an increase to both total  assets and total  liabilities  of
     approximately $40 million.

     The Company also has interests in several other variable  interest entities
     created  before  January 31, 2003, for which the Company is not the primary
     beneficiary. These arrangements include equity investments in approximately
     20 limited partnerships, limited liability corporations and venture capital
     funds and two building leases with special-purpose  entities. The aggregate
     maximum loss exposure at December 31, 2003 under these arrangements  totals
     approximately  $34  million.  The  creditors  of  these  variable  interest
     entities  do not have  recourse  to the  general  credit of the  Company in
     excess of the aggregate maximum loss exposure.

     In February 2004, the Company became aware that certain long-term  purchase
     power and tolling contracts may be considered  variable interests under FIN
     No.  46R.  The Company has  various  long-term  purchase  power and tolling
     contracts with other utilities and certain qualifying  facility plants. The
     Company   believes  the   counterparties   to  these   contracts   are  not
     special-purpose  entities  and,  therefore,  FIN No. 46R would not apply to
     these contracts until March 31, 2004. The Company has not yet completed its
     evaluation  of  these  contracts  to  determine  if the  Company  needs  to
     consolidate  these  counterparties  under FIN No. 46R and will  continue to
     monitor developing practice in this area.

3.   Divestitures

     A. NCNG Divestiture

     On September 30, 2003,  the Company  completed  the sale of 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. Net proceeds from the sale of NCNG of $443 million were used
     to  reduce  debt.  Based  on the net  proceeds,  the  Company  recorded  an
     after-tax loss of $12 million during 2003.

     The accompanying  consolidated  financial statements have been restated for
     all periods  presented for the  discontinued  operations  of NCNG.  The net
     income of these  operations is reported as  discontinued  operations in the
     Consolidated  Statements of Income.  Interest  expense of $10 million,  $16
     million and $15 million for the years ended  December  31,  2003,  2002 and
     2001, respectively,  has been allocated to discontinued operations based on
     the net assets of NCNG, assuming a uniform  debt-to-equity ratio across the
     Company's operations.  The Company ceased recording  depreciation effective

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<PAGE>

     October  1,  2002,  upon  classification  of  the  assets  as  discontinued
     operations. After-tax depreciation expense recorded by NCNG for each of the
     years ended  December  31,  2002 and 2001 was $9 million  and $10  million,
     respectively.  Results of discontinued  operations for years ended December
     31 were as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                                   2003        2002        2001
                                                               -----------------------------------
     Revenues                                                       $ 284       $ 300       $ 321
                                                               ===================================

     Earnings before income taxes                                   $   6       $   9       $   4
     Income tax expense                                                 2           4           3
                                                               -----------------------------------
     Net earnings from discontinued operations                          4           5           1
     Loss on disposal of discontinued operations,
            including applicable income tax expense of $1
            and $3, respectively                                     ( 12)        (29)          -
                                                               -----------------------------------
     Earnings (loss) from discontinued operations                   $  (8)      $ (24)      $   1
                                                               ===================================
</TABLE>

     The major  balance  sheet  classes  included in assets and  liabilities  of
     discontinued  operations in the Consolidated Balance Sheets at December 31,
     2002 are as follows:

     (in millions)
     Utility plant, net                                        $ 399
     Current assets                                               73
     Deferred debits and other assets                             18
                                                           ----------
          Assets of discontinued operations                    $ 490
                                                           ==========

     Current liabilities                                       $  76
     Deferred credits and other liabilities                       49
                                                           ----------
          Liabilities of discontinued operations               $ 125
                                                           ==========

     The sale of ENCNG resulted in net proceeds of $7 million and a pre-tax loss
     of $2  million,  which  is  included  in  other,  net on  the  accompanying
     Consolidated Statements of Income for the year ended December 31, 2003. The
     Company's equity  investment in ENCNG of $8 million at December 31, 2002 is
     included  in   miscellaneous   other   property  and   investments  in  the
     accompanying Consolidated Balance Sheets.

     B. Railcar Ltd. Divestiture

     In  December  2002,  the  Progress  Energy  Board of  Directors  adopted  a
     resolution approving the sale of Railcar Ltd., a subsidiary included in the
     Rail  Services  segment.  In  accordance  with SFAS No. 144,  an  estimated
     pre-tax impairment of $59 million on assets held for sale was recognized in
     December  2002 to  write-down  the assets to fair value less costs to sell.
     This impairment has been included in impairment of long-lived assets in the
     Consolidated Statements of Income (See Note 9A).

     The assets of Railcar  Ltd.  have been  grouped as assets held for sale and
     are included in other current assets on the Consolidated  Balance Sheets at
     December 31, 2003 and 2002. The assets were recorded at  approximately  $75
     million and $24 million at December 31, 2003 and 2002, respectively,  which
     reflects the Company's  estimates of the fair value expected to be realized
     from the sale of these assets less costs to sell. The primary  component of
     assets held for sale at December 31, 2003 was property and equipment of $74
     million. The primary component of assets held for sale at December 31, 2002
     was current assets of $22 million. The net increase in assets held for sale
     from December 31, 2002 to December 31, 2003 was primarily  attributable  to
     the  purchase of railcars in 2003 that were  subject to  off-balance  sheet
     obligations  at December 31, 2002. In addition to the assets held for sale,
     the Company is subject to certain  commitments  under operating leases (See
     Note 21C).

     In March 2003,  the Company  signed a letter of intent to sell the majority
     of Railcar Ltd.  assets to The Andersons,  Inc. In November 2003, the asset
     purchase agreement was signed, and the transaction closed in February 2004.
     Proceeds  from the sale were  approximately  $82  million.  The Company was
     relieved of the majority of the operating lease commitments when the assets
     were sold.

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<PAGE>

     C. Mesa Hydrocarbons, Inc. Divestiture

     In October 2003, the Company sold certain gas-producing properties owned by
     Mesa  Hydrocarbons,  LLC,  a  wholly-owned  subsidiary  of  Progress  Fuels
     Corporation  (Progress Fuels),  which is included in the Fuels segment. Net
     proceeds were  approximately $97 million.  Because the Company utilizes the
     full cost method of accounting for its oil and gas operations,  the pre-tax
     gain of  approximately  $18  million was applied to reduce the basis of the
     Company's other U.S. oil and gas investments and will prospectively  result
     in a reduction of the  amortization  rate applied to those  investments  as
     production occurs.

     D. Inland Marine Transportation Divestiture

     During  2001,  the  Company   completed  the  sale  of  its  Inland  Marine
     Transportation  business  operated by MEMCO Barge Line,  Inc.,  and related
     investments to AEP Resources,  Inc., a wholly-owned  subsidiary of American
     Electric  Power,  for a sales price of $270  million.  Of the $270  million
     purchase price,  $230 million was used to pay early  termination of certain
     off-balance  sheet  arrangements  for  assets  leased by the  business.  In
     connection   with  the  sale,  the  Company   entered  into   environmental
     indemnification  provisions covering both known and unknown sites (See Note
     21E). The Company  adjusted the FPC purchase price  allocation to reflect a
     $15  million  net  realizable  value of the  Inland  Marine  Transportation
     business.

     E. Required Divestiture

     The U.S.  Securities and Exchange Commission (SEC) original order approving
     the FPC merger  required the Company to divest of Rail Services and certain
     immaterial,  nonregulated investments of FPC by November 30, 2003. Although
     the Company has been actively  marketing these  investments,  an acceptable
     divestiture opportunity was not found by that date. Therefore,  the Company
     sought and in October 2003 was granted  approval of a three-year  extension
     from the SEC until 2006.

4.   Acquisitions and Business Combinations

     A. Progress Telecommunications Corporation

     In  December  2003,  Progress  Telecommunications   Corporation  (PTC)  and
     Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy,
     and EPIK Communications,  Inc. (EPIK), a wholly-owned subsidiary of Odyssey
     Telecorp, Inc. (Odyssey), contributed substantially all of their assets and
     transferred  certain  liabilities  to Progress  Telecom,  LLC (PTC LLC),  a
     subsidiary  of PTC.  Subsequently,  the  stock  of  Caronet  was sold to an
     affiliate  of  Odyssey  for  $2  million  in  cash  and  Caronet  became  a
     wholly-owned  subsidiary  of  Odyssey.  Following  consummation  of all the
     transactions described above, PTC holds a 55% ownership interest in, and is
     the parent of PTC LLC.  Odyssey holds a combined 45% ownership  interest in
     PTC LLC through EPIK and  Caronet.  The accounts of PTC LLC are included in
     the Company's Consolidated Financial Statements since the transaction date.
     The minority interest is included in other liabilities and deferred credits
     in the Consolidated Balance Sheets.

     The transaction was accounted for as a partial  acquisition of EPIK through
     the issuance of the stock of a consolidated  subsidiary.  The contributions
     of PTC's and Caronet's net assets were recorded at their carrying values of
     approximately  $31  million.   EPIK's  contribution  was  recorded  at  its
     estimated  fair value of $22 million  using the  purchase  method,  and was
     initially allocated as follows: property and equipment - $27 million; other
     current  assets  - $9  million;  current  liabilities  - $21  million;  and
     goodwill - $7 million.  The goodwill was  assigned to the  Company's  Other
     business segment and will not be deductible for tax purposes.  The purchase
     price allocation is a preliminary estimate, based on available information,
     internal  estimates  and  certain   assumptions   management  believes  are
     reasonable.  Accordingly,  the  purchase  price  allocation  is  subject to
     finalization  in 2004  pending  the  completion  of internal  and  external
     appraisals  of  assets  acquired.  No gain or loss  was  recognized  on the
     transaction. The pro forma results of operations reflecting the acquisition
     would not be materially  different than the reported  results of operations
     for the years ended December 31, 2002 or 2001.

                                       87
<PAGE>

     B. Acquisition of Natural Gas Reserves

     During 2003, Progress Fuels entered into several  independent  transactions
     to acquire  approximately  200  natural  gas-producing  wells  with  proven
     reserves  of  approximately  190  billion  cubic feet  (Bcf) from  Republic
     Energy, Inc. and three other privately-owned  companies,  all headquartered
     in Texas.  The total  cash  purchase  price for the  transactions  was $168
     million.

     C. Wholesale Energy Contract Acquisition

     In May 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 Electric Membership Corporation  (Jackson),  located in
     Jefferson,  Georgia. The agreement calls for a $188 million cash payment to
     Williams  Energy  Marketing  and Trading in exchange for  assignment of the
     Jackson supply agreement.  The $188 million cash payment was recorded as an
     intangible  asset and is being amortized  based on the economic  benefit of
     the contract (See Note 8). The power supply  agreement  terminates in 2015,
     with a first refusal right 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.  PVI
     expects to supplement the acquired  resources with its own intermediate and
     peaking  assets in  Georgia  to serve  Jackson's  forecasted  1,100 MW peak
     demand in 2005 growing to a forecasted 1,700 MW demand by 2015.

     D. Generation Acquisition

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

     In the final allocation, the aggregate cash purchase price of approximately
     $348 million was allocated to diversified  business  property,  intangibles
     and goodwill for $250  million,  $33 million and $64 million,  respectively
     (See Note 8). Of the acquired  intangible  assets, $33 million was assigned
     to tolling and power sale agreements with LG&E Energy  Marketing,  Inc. for
     each project and is being amortized through December 31, 2004. Goodwill was
     assigned to the CCO segment and will be deductible for tax purposes.

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

     E. Westchester Acquisition

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

     The aggregate  purchase price of  approximately  $153 million  consisted of
     cash  consideration  of  approximately  $22 million and the issuance of 2.5
     million shares of Progress Energy common stock then valued at approximately
     $129  million.  The purchase  price  included  approximately  $2 million of
     direct transaction costs. The final purchase price was allocated to oil and
     gas properties,  intangible  assets,  diversified  business  property,  net
     working  capital  and  deferred  tax  liabilities  for  approximately  $152
     million, $9 million, $32 million, $5 million and $45 million, respectively.
     The $9 million  intangible  assets recorded  relates to customer  contracts
     acquired  as part of the  acquisition  and are being  amortized  over their
     respective lives (See Note 8).

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

                                       88
<PAGE>

5.   Property, Plant and Equipment

     A. Utility Plant

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

     (in millions)                                    2003            2002
                                               -------------     -----------

     Production plant  (7-33 years)                 $ 12,039        $ 11,063
     Transmission plant  (30-75 years)                 2,167           2,104
     Distribution plant  (12-50 years)                 6,432           6,073
     General plant and other (8-75 years)              1,037             917
                                               -------------     -----------
     Utility plant in service                       $ 21,675        $ 20,157
                                               =============     ===========

     Generally,  electric utility plant at PEC and PEF, other than nuclear fuel,
     is  pledged  as  collateral  for the first  mortgage  bonds of PEC and PEF,
     respectively.

     Allowance  for  funds  used  during  construction  (AFUDC)  represents  the
     estimated  debt and equity costs of capital funds  necessary to finance the
     construction  of new regulated  assets.  As  prescribed  in the  regulatory
     uniform systems of accounts, AFUDC is charged to the cost of the plant. The
     equity funds  portion of AFUDC is credited to other income and the borrowed
     funds  portion is  credited  to interest  charges.  Regulatory  authorities
     consider AFUDC an appropriate  charge for inclusion in the rates charged to
     customers  by the  utilities  over the service  life of the  property.  The
     composite AFUDC rate for PEC's electric  utility plant was 4.0% in 2003 and
     6.2% in 2002 and 2001. The composite AFUDC rate for PEF's electric  utility
     plant was 7.8% in 2003, 2002 and 2001.

     Depreciation   provisions  on  utility  plant,  as  a  percent  of  average
     depreciable  property other than nuclear fuel,  were 2.5%, 2.6% and 2.8% in
     2003, 2002 and 2001,  respectively.  The depreciation provisions related to
     utility  plant were $517  million,  $488  million and $530 million in 2003,
     2002 and 2001,  respectively.  In  addition to utility  plant  depreciation
     provisions,   depreciation   and   amortization   expense   also   includes
     decommissioning   cost  provisions,   asset  retirement   obligation  (ARO)
     accretion, cost of removal provisions (See Note 5D) and regulatory approved
     expenses (See Note 7).

     PEC  filed a new  depreciation  study in 2004  that  provides  support  for
     reducing  depreciation  expense  on an annual  basis by  approximately  $45
     million. The reduction is primarily  attributable to assumption changes for
     nuclear  generation,  offset by increases for distribution  assets. The new
     rates are primarily effective January 1, 2004.

     Amortization of nuclear fuel costs,  for the years ended December 31, 2003,
     2002  and  2001  were  $143   million,   $141  million  and  $130  million,
     respectively.

     B. Diversified Business Property

     The  balances of  diversified  business  property at December 31 are listed
     below, with a range of depreciable lives for each:

                                       89
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                                       2003               2002
                                                                   ---------------   ----------------

     Equipment (3 - 25 years)                                         $   246            $   299
     Nonregulated generation plant and equipment (3 - 40 years)         1,299                549
     Land and mineral rights                                               93                 90
     Buildings and plants (5 - 40 years)                                  153                153
     Oil and gas properties (units-of-production)                         412                265
     Telecommunications equipment (5 - 20 years)                           63                 43
     Rail equipment (3 - 20 years)                                        125                 48
     Marine equipment (3 - 35 years)                                       83                 80
     Computers, office equipment and software (3 - 10 years)               36                 33
     Construction work in progress                                         49                644
     Accumulated depreciation                                            (401)              (320)
                                                                   ---------------   ----------------

     Diversified business property, net                               $ 2,158            $ 1,884
                                                                   ===============   ================
</TABLE>

     The Company's nonregulated  businesses capitalize interest costs under SFAS
     No. 34, "Capitalizing  Interest Costs." During the years ended December 31,
     2003 and 2002,  respectively,  the Company  capitalized $20 million and $38
     million of its interest expense of $652 million and $679 million related to
     the expansion of its nonregulated  generation portfolio at PVI. Capitalized
     interest  is  included  in  diversified  business  property,   net  on  the
     Consolidated Balance Sheets.  Diversified business depreciation expense was
     $120 million,  $85 million and $61 million for December 31, 2003,  2002 and
     2001, respectively.

     C. Joint Ownership of Generating Facilities

     PEC and PEF hold ownership  interests in certain  jointly owned  generating
     facilities.  Each is entitled to shares of the  generating  capability  and
     output of each unit equal to their  respective  ownership  interests.  Each
     also  pays its  ownership  share of  additional  construction  costs,  fuel
     inventory  purchases  and  operating  expenses.  PEC's and  PEF's  share of
     expenses for the jointly owned  facilities  is included in the  appropriate
     expense  category.  The  co-owner of  Intercession  City Unit P11 (P11) has
     exclusive  rights  to the  output  of the unit  during  the  months of June
     through September.  PEF has that right for the remainder of the year. PEC's
     and PEF's ownership  interests in the jointly owned  generating  facilities
     are listed below with related information at December 31, ($ in millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

-----------------------------------------------------------------------------------------------------------------
2003
-----------------------------------------------------------------------------------------------------------------
                                                      Company                                    Construction
                                                     Ownership        Plant       Accumulated       Work in
    Subsidiary                 Facility               Interest     Investment     Depreciation     Progress
-----------------------------------------------------------------------------------------------------------------

PEC                Mayo Plant                          83.83%       $   464        $   242            $ 50
PEC                Harris Plant                        83.83%         3,248          1,370               7
PEC                Brunswick Plant                     81.67%         1,611            884              21
PEC                Roxboro Unit  4                     87.06%           323            139               1
PEF                Crystal River Unit 3                91.78%         1,069            432              49
PEF                Intercession City Unit P11          66.67%            22              6               6
-----------------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------------
2002
-----------------------------------------------------------------------------------------------------------------
                                                      Company                                    Construction
                                                     Ownership        Plant       Accumulated       Work in
    Subsidiary                 Facility               Interest     Investment     Depreciation     Progress
-----------------------------------------------------------------------------------------------------------------

PEC                Mayo Plant                          83.83%       $   464        $   232            $ 14
PEC                Harris Plant                        83.83%         3,160          1,331               6
PEC                Brunswick Plant                     81.67%         1,477            811              26
PEC                Roxboro Unit  4                     87.06%           316            134               8
PEF                Crystal River Unit 3                91.78%           777            375              28
PEF                Intercession City Unit P11          66.67%            22              5               4
</TABLE>

     In the tables above, plant investment and accumulated  depreciation are not
     reduced  by the  regulatory  disallowances  related to the  Shearon  Harris
     Nuclear Plant (Harris Plant).

                                       90
<PAGE>

     D. Decommissioning, Dismantlement and Cost of Removal Provisions

     Decommissioning  cost  provisions,  which are included in depreciation  and
     amortization  expense,  were $31  million,  $31  million and $39 million in
     2003, 2002 and 2001,  respectively.  The PEF rate case settlement  required
     PEF to suspend  accruals on its  reserves for nuclear  decommissioning  and
     fossil  dismantlement  through December 31, 2005 (See Note 7D).  Management
     believes  that  decommissioning  costs that have been and will be recovered
     through rates by PEC and PEF will be sufficient to provide for the costs of
     decommissioning.

     PEF's provision for fossil plant dismantlement was previously suspended per
     a 1997 FPSC settlement  agreement,  but resumed  mid-2001.  The 2001 annual
     provision,  approved by the FPSC,  was $9  million.  The accrual for fossil
     dismantlement reserves was suspended again in 2002 by the Florida rate case
     settlement (See Note 7D).

     Cost  of  removal  provisions,  which  are  included  in  depreciation  and
     amortization  expense,  were $158 million, $149 million and $143 million in
     2003,  2002 and 2001,  respectively.  These  amounts  represent the expense
     recognized for the disposal or removal of utility  assets.  The FASB issued
     SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143),
     that changed the accounting for the decommissioning, dismantlement and cost
     of removal provisions (See Note 5F).

     E. Insurance

     PEC and PEF are members of Nuclear Electric Insurance Limited (NEIL), which
     provides primary and excess  insurance  coverage against property damage to
     members' nuclear  generating  facilities.  Under the primary program,  each
     company  is insured  for $500  million  at each of its  respective  nuclear
     plants.   In   addition   to   primary   coverage,   NEIL   also   provides
     decontamination,  premature  decommissioning  and excess property insurance
     with limits of $2.0 billion on the  Brunswick and Harris  Plants,  and $1.1
     billion on the Robinson and Crystal River Unit No. 3 (CR3) Plants.

     Insurance coverage against incremental costs of replacement power resulting
     from  prolonged  accidental  outages  at nuclear  generating  units is also
     provided  through  membership  in  NEIL.  Both  PEC  and  PEF  are  insured
     thereunder,  following a twelve-week deductible period, for 52 weeks in the
     amount of $3 million  per week at the  Brunswick  and Harris  Plants,  $2.5
     million per week at the Robinson Plant and $4.5 million per week at the CR3
     Plant.  An additional 110 weeks of coverage is provided at 80% of the above
     weekly amounts. For the current policy period, the companies are subject to
     retrospective  premium  assessments of up to approximately $27 million with
     respect  to  the  primary  coverage,   $31  million  with  respect  to  the
     decontamination,  decommissioning  and excess  property  coverage,  and $19
     million for the incremental  replacement power costs coverage, in the event
     covered losses at insured facilities exceed premiums, reserves, reinsurance
     and other NEIL  resources.  Pursuant to  regulations  of the United  States
     Nuclear  Regulatory   Commission  (NRC),  each  company's  property  damage
     insurance  policies  provide  that all  proceeds  from  such  insurance  be
     applied,  first, to place the plant in a safe and stable condition after an
     accident and, second, to decontaminate, before any proceeds can be used for
     decommissioning,  plant repair or restoration.  Each company is responsible
     to the extent losses may exceed limits of the coverage described above.

     Both  PEC  and PEF are  insured  against  public  liability  for a  nuclear
     incident up to $10.9 billion per occurrence.  Under the current  provisions
     of the Price Anderson Act, which limits  liability for accidents at nuclear
     power plants,  each company,  as an owner of nuclear units, can be assessed
     for a portion of any third-party  liability claims arising from an accident
     at any commercial  nuclear power plant in the United  States.  In the event
     that public  liability  claims from an insured nuclear incident exceed $300
     million  (currently  available through commercial  insurers),  each company
     would be subject to pro rata  assessments  of up to $101  million  for each
     reactor owned per  occurrence.  Payment of such  assessments  would be made
     over time as necessary to limit the payment in any one year to no more than
     $10 million per reactor owned. Congress is expected to approve revisions to
     the Price Anderson Act during 2004 that could include  increased limits and
     assessments  per reactor owned.  The final outcome of this matter cannot be
     predicted at this time.

     Under the NEIL policies,  if there were multiple terrorism losses occurring
     within one year, NEIL would make available one industry  aggregate limit of
     $3.2  billion,  along  with  any  amounts  it  recovers  from  reinsurance,
     government  indemnity or other sources up to the limits for each  claimant.
     If  terrorism  losses  occurred  beyond the one-year  period,  a new set of
     limits and resources would apply. For nuclear  liability claims arising out
     of terrorist acts, the primary level available through commercial  insurers
     is now subject to an industry  aggregate limit of $300 million.  The second

                                       91
<PAGE>

     level of coverage  obtained  through the assessments  discussed above would
     continue  to apply to losses  exceeding  $300  million  and  would  provide
     coverage in excess of any  diminished  primary  limits due to the terrorist
     acts aggregate.

     PEC and PEF self-insure their  transmission and distribution  lines against
     loss due to storm  damage  and other  natural  disasters.  PEF  accrues  $6
     million  annually to a storm damage reserve  pursuant to a regulatory order
     and may defer losses in excess of the reserve (See Note 7A).

     F. Asset Retirement Obligations

     SFAS No. 143 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  AROs totaling  $1,183
     million for nuclear  decommissioning  of irradiated  plants 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 million,  which were previously  recorded in cost of removal.
     The  related  asset  retirement  costs,  net of  accumulated  depreciation,
     recorded upon adoption totaled $368 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. A  regulatory
     asset  was  recorded  related  to  PEC  in  the  amount  of  $271  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  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.

     At  December  31,  2003,  the asset  retirement  costs  related  to nuclear
     decommissioning  of  irradiated  plant,  net of  accumulated  depreciation,
     totaled  $354  million  for  regulated  operations.   The  ongoing  expense
     differences  between SFAS No. 143 and  regulatory  cost  recovery are being
     deferred to the regulatory asset and regulatory liability.

     Funds set aside in the Company's  nuclear  decommissioning  trust funds for
     the nuclear decommissioning  liability totaled $938 million at December 31,
     2003 and $797  million at December 31, 2002.  Net  unrealized  gains on the
     nuclear decommissioning trust funds were included in regulatory liabilities
     in 2003 and cost of removal in 2002.

     Upon  adoption of SFAS No. 143, the Company also recorded AROs totaling $10
     million for  synthetic  fuel  operations  of PVI and coal mine  operations,
     synthetic fuel operations and gas production of Progress Fuels. The Company
     used an expected  cash flow  approach to measure  these  obligations.  This
     amount includes  accruals  recorded prior to adoption  totaling $5 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 million for nonregulated operations.  The
     cumulative  effect  of  initial  adoption  of  this  statement  related  to
     nonregulated  operations  was $1 million of income,  which is  included  in
     cumulative  effect of change in  accounting  principles,  net of tax on the
     Consolidated Statements of Income for the year ended December 31, 2003.

     The AROs for synthetic  fuel  operations  of PVI and coal mine  operations,
     synthetic fuel  operations and gas production of Progress Fuels totaled $20
     million at December 31, 2003. The related asset  retirement  costs,  net of
     accumulated depreciation, totaled $7 million for nonregulated operations at
     December  31,  2003.  The  following  table  shows the changes to the asset
     retirement  obligations during the year ended December 31, 2003.  Additions
     relate  primarily  to  additional  reclamation  obligations  at  coal  mine
     operations of Progress Fuels.

                                       92
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                              Regulated          Nonregulated
                                                              --------------       ------------
     Asset retirement obligations as of January 1, 2003             $ 1,183            $ 10
     Additions                                                            -              11
     Accretion expense                                                   68               1
     Deductions                                                           -              (2)
                                                              --------------       ------------
     Asset retirement obligations as of  December 31, 2003          $ 1,251            $ 20
                                                              ==============       ============
</TABLE>

     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 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   previously   recognized   removal,   decommissioning   and
     dismantlement   costs  as  a  component  of  accumulated   depreciation  in
     accordance  with  regulatory  treatment.  At December 31, 2003,  such costs
     totaling  $2,169  million were  included in regulatory  liabilities  on the
     Consolidated Balance Sheets and consist of removal costs of $1,897 million,
     removal  costs  for  non-irradiated  areas at  nuclear  facilities  of $129
     million  and  amounts  previously  collected  for  dismantlement  of fossil
     generation  plants of $143  million.  At  December  31,  2002,  such  costs
     totaling   $2,940   million  were  included  in  cost  of  removal  on  the
     Consolidated Balance Sheets and consist of removal costs of $1,790 million,
     decommissioning  costs for both the irradiated and non-irradiated  areas at
     nuclear facilities of $1,008 million and amounts  previously  collected for
     dismantlement  of  fossil  generation  plants  of $142  million.  With  the
     adoption of SFAS No. 143 in 2003,  removal costs related to the  irradiated
     areas at nuclear facilities are reported as asset retirement obligations on
     the 2003 Consolidated Balance Sheet.

     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  initially  granted the  deferral of the
     January 1, 2003  cumulative  adjustment.  During the third quarter of 2003,
     the NCUC issued an order  allowing the  deferral of the ongoing  effects of
     SFAS No.  143. In April 2003,  the SCPSC  approved a joint  request by PEC,
     Duke Energy  Corporation 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.  Therefore,
     SFAS No. 143 had no impact on the income of PEC for the year ended December
     31, 2003.

     In January  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.  A
     final  order was  issued  in the  third  quarter  of 2003.  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.

6.   Inventory

     At December 31, inventory was comprised of:

     (in millions)                     2003              2002
                                  --------------     -------------

     Fuel                             $ 250             $ 313
     Rail equipment and parts           132               155
     Materials and supplies             386               363
     Other                               40                44
                                  --------------     -------------
     Total inventory                  $ 808             $ 875
                                  ==============     =============

                                       93
<PAGE>

7.   Regulatory Matters

     A. Regulatory Assets and Liabilities

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

     At December 31, the balances of  regulatory  assets  (liabilities)  were as
     follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                                            2003               2002
                                                                 -----------------    ---------------

Deferred fuel cost                                                  $     317              $ 184
                                                                 -----------------    ---------------

Deferred impact of ARO  (Note 5F)                                         291                  -
Income taxes recoverable through future rates (Note 14)                   136                155
Deferred purchased power contract termination costs (Note 7B)               -                 47
Loss on reacquired debt (Note 1C)                                          55                 33
Deferred DOE enrichment facilities-related costs (Note 1C)                 24                 31
Storm deferral (Note 7B)                                                   21                  -
Other postretirement benefits (Note 16B)                                    9                 11
Other                                                                      76                 70
                                                                 -----------------    ---------------
     Total long-term regulatory assets                                    612                347
                                                                 -----------------    ---------------

Non-ARO cost of removal (Note 5F)                                      (2,169)                  -
Deferred impact of ARO (Note 5F)                                         (212)                  -
Net nuclear decommissioning trust unrealized gains  (Note 5F)            (204)                  -
Defined benefit retirement plan (Note 16B)                               (211)               (51)
Storm reserve (Note 5E)                                                   (41)               (36)
Clean air compliance (Note 7B)                                            (74)                  -
Other                                                                     (27)               (33)
                                                                 -----------------    ---------------
     Total long-term regulatory liabilities                            (2,938)              (120)
                                                                 -----------------    ---------------
         Net regulatory assets(liabilities)                         $  (2,009)             $ 411
                                                                 =================    ===============
</TABLE>

     Except for portions of deferred fuel,  all regulatory  assets earn a return
     or the cash has not yet been expended,  in which case the assets are offset
     by liabilities  that do not incur a carrying  cost. The Company  expects to
     fully  recover  these assets and refund the  liabilities  through  customer
     rates under current regulatory practice.

     B. Retail Rate Matters

     The NCUC and SCPSC have approved  proposals to accelerate  cost recovery of
     PEC's nuclear  generating  assets beginning January 1, 2000, and continuing
     through 2009.  The aggregate  minimum and maximum  amounts of cost recovery
     are $530 million and $750 million, respectively.  Accelerated cost recovery
     of these assets  resulted in no additional  expense in 2003 and  additional
     depreciation  expense of approximately  $53 million and $75 million in 2002
     and 2001,  respectively.  Total accelerated  depreciation  recorded through
     December 31, 2003 was $403 million.

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

     In conjunction with the acquisition of NCNG in 1999, 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.

                                       94
<PAGE>

     The NC Clean  Air Act of June 2002 (the  Clean  Air  Act),  requires  state
     utilities to reduce  emissions of nitrogen  oxide (NOx) and sulfur  dioxide
     (SO2)  from  coal-fired  plants.  The NCUC has  allowed  the  utilities  to
     amortize  and recover the costs  associated  with  meeting the new emission
     standards  over  a  seven-year   period  beginning  January  1,  2003.  PEC
     recognized  $74  million  of  clean  air  amortization  during  2003.  This
     legislation  freezes  PEC's base rates in North  Carolina  for five  years,
     subject to certain conditions (See Note 21E).

     In  conjunction  with the FPC  merger,  PEC reached a  settlement  with the
     Public  Staff of the NCUC in which it  agreed  to  provide  credits  to its
     non-real  time pricing  customers in the amounts of $3 million in 2002,  $5
     million in 2003 and $6 million in both 2004 and 2005.

     At December 31, 2000, PEF, with the approval of the FPSC, had established a
     regulatory liability to defer $63 million of revenues. In 2001, PEF applied
     the deferred  revenues,  plus accrued  interest,  to reduce its  regulatory
     asset related to deferred  purchased power termination  costs. In addition,
     PEF recorded accelerated amortization of $34 million to further offset this
     regulatory  asset  during  2001.  During  2003,  PEF fully  amortized  this
     regulatory asset.

     In February  2003, PEF petitioned the FPSC to increase its fuel factors due
     to continuing  increases in oil and natural gas commodity  prices. In March
     2003, the FPSC approved PEF's petition.  New rates also became effective in
     March 2003.

     In September  2003, PEF asked the FPSC to approve a cost  adjustment in its
     annual fuel  filing,  primarily  related to rising  costs of fuel that will
     increase retail customer bills beginning  January 1, 2004. The total amount
     of the fuel  adjustment  requested  above current levels was  approximately
     $322 million.  In November  2003,  the FPSC approved  PEF's request and new
     rates became effective January 2004.

     PEC   obtained   SCPSC  and  NCUC   approval  of  fuel  factors  in  annual
     fuel-adjustment  proceedings.  The SCPSC  approved  PEC's petition to leave
     billing rates  unchanged from the prior year by order issued in March 2003.
     The NCUC  approved an increase of $20 million by order  issued in September
     2003.

     In October  2003,  PEC made a filing  with the NCUC to seek  permission  to
     defer expenses  incurred from Hurricane Isabel and the February 2003 winter
     storms.  As a result of rising storm costs and the frequency of major storm
     damage,  PEC asked the NCUC to allow PEC to create a  deferred  account  in
     which PEC  would  place  expenses  incurred  as a result of named  tropical
     storms,  hurricanes and  significant  winter storms.  In December 2003, the
     NCUC  approved  PEC's  request to defer the costs and amortize  them over a
     period of five years  beginning in the month the storm occurs.  PEC charged
     approximately  $24 million in 2003 from  Hurricane  Isabel and from current
     year ice storms to the deferred account,  of which $3 million was amortized
     during 2003.

     PEC retains funds internally to meet  decommissioning  liability.  The NCUC
     order  issued  February  2004  found that by January 1, 2008 PEC must begin
     transitioning  these  amounts to external  funds.  The  transition  of $131
     million must be  completed  by December 31, 2017,  and at least 10% must be
     transitioned  each year. PEC has exclusively  utilized external funding for
     its decommissioning liability since 1994.

     C. Regional Transmission Organizations and Standard Market Design

     In  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 (ISOs). 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.  PEC and PEF,  as  subsidiaries  of  Progress  Energy,  filed
     comments in November  2002 and  supplemental  comments in January  2003. In
     April  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.  The FERC has not yet issued a final rule on SMD
     NOPR. 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. It is unknown what impact the future  proceedings
     will have on the Company's earnings, revenues or prices.

                                       95
<PAGE>

     The  Company  has $33 million  and $4 million  invested  in  GridSouth  and
     GridFlorida,  respectively,  at December  31,  2003.  Given the  regulatory
     uncertainty of the ultimate timing,  structure and operations of GridSouth,
     GridFlorida or an alternate combined  transmission  structure,  the Company
     cannot  predict the effect on future  consolidated  results of  operations,
     cash  flows or  financial  condition.  Furthermore,  the SMD NOPR  presents
     several  uncertainties,  including  what  percentage of the  investments in
     GridSouth  and  GridFlorida  will  be  recovered,  how the  elimination  of
     transmission charges, as proposed in the SMD NOPR, will impact the Company,
     and what amount of capital  expenditures  will be necessary to create a new
     wholesale market.

     D. PEF Rate Case Settlement

     The FPSC initiated a rate  proceeding in 2001  regarding  PEF's future base
     rates.  In March  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 in  April  2002.  The
     Agreement  is generally  effective  from May 2002  through  December  2005;
     provided, however, that if PEF's base rate earnings fall below a 10% return
     on equity, PEF may petition the FPSC to amend its base rates.

     The Agreement  provides  that PEF will reduce its retail  revenues from the
     sale of electricity by an annual amount of $125 million. The Agreement also
     provides that PEF will operate under a Revenue Sharing  Incentive Plan (the
     Plan) through  2005,  and  thereafter  until  terminated by the FPSC,  that
     establishes annual revenue caps and sharing  thresholds.  The Plan provides
     that retail base rate  revenues  between  the  sharing  thresholds  and the
     retail base rate revenue caps will be divided into two shares - a 1/3 share
     to be  received  by PEF's  shareholders,  and a 2/3 share to be refunded to
     PEF's retail customers; provided, however, that for the year 2002 only, the
     refund to  customers  was limited to 67.1% of the 2/3 customer  share.  The
     retail base rate revenue sharing  threshold  amounts for 2003 and 2002 were
     $1,333  million and $1,296  million,  respectively,  and will  increase $37
     million each year  thereafter.  The Plan also provides that all retail base
     rate revenues above the retail base rate revenue caps  established for each
     year will be refunded to retail customers on an annual basis. For 2002, the
     refund to customers  was limited to 67.1% of the retail base rate  revenues
     that  exceeded  the 2002 cap. The retail base revenue cap for 2003 and 2002
     was $1,393 million and $1,356 million,  respectively, and will increase $37
     million  each year  thereafter.  Any amounts  above the retail base revenue
     caps will be refunded 100% to customers.  At December 31, 2003, $17 million
     has  been  accrued  and  will be  refunded  to  customers  by  March  2004.
     Approximately  $5 million was originally  returned in March 2003 related to
     2002  revenue  sharing.  However,  in  February  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  be
     approximately  $23  million.  In July  2003,  the FPSC  ruled that PEF must
     provide an additional  $18 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 refunded
     this amount by October 2003.

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

     PEF will suspend accruals on its reserves for nuclear  decommissioning  and
     fossil dismantlement through December 2005. Additionally, for each calendar
     year  during  the  term of the  Agreement,  PEF will  record a $63  million
     depreciation  expense  reduction,  and may, at its option,  record up to an
     equal annual amount as an offsetting  accelerated  depreciation expense. In
     addition,  PEF  is  authorized,   at  its  discretion,  to  accelerate  the
     amortization of certain  regulatory  assets over the term of the Agreement.
     In  2003,  PEF  recorded  $16  million  of  accelerated  amortization  of a
     regulatory  liability  related  to a  settled  tax  matter.  There  was  no
     accelerated  depreciation  or  amortization  expense  recorded for the year
     ended December 31, 2002.

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

                                       96
<PAGE>

     The Agreement  also provided  that, PEF was required to refund to customers
     $35 million of revenues PEF collected during the interim period since March
     2001.  This one-time  retroactive  revenue refund was recorded in the first
     quarter of 2002 and was  returned  to retail  customers  during  2002.  Any
     additional  refunds  under the  Agreement  are  recorded  when they  become
     probable.

8.   Goodwill and Other Intangible Assets

     Effective  January 2002,  the Company  adopted SFAS No. 142. As required by
     SFAS  No.  142,  the  results  for the  prior  year  periods  have not been
     restated.  A  reconciliation  of net  income  as if SFAS  No.  142 had been
     adopted  is  presented  below for the year ended  December  31,  2001.  The
     goodwill  amortization  used  in the  reconciliation  includes  $6  million
     related to NCNG, which is included in discontinued operations.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                          Basic earnings per    Diluted earnings per
     (in millions, except per share data)   Net income      common share           common share
                                            ----------    ------------------    --------------------
     Reported                                 $ 542            $ 2.65                $2.64
     Goodwill amortization                       96              0.47                 0.47
                                            ----------    ------------------    --------------------
     Adjusted                                 $ 638            $ 3.12                $3.11
                                            ==========    ==================    ====================
</TABLE>


     The changes in the carrying amount of goodwill for the years ended December
     31, 2002 and 2003, by reportable segment, are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                             PEC Electric   PEF       CCO      Other    Total
                                               --------------------------------------------------
     Balance as of January 1, 2002                $ 1,922   $ 1,733     $  -     $  35  $ 3,690
     Acquisitions (Note 4D)                             -         -       64         -       64
     Divestitures                                       -         -        -        (2)      (2)
     Discontinued operations (Note 3A)                  -         -        -       (33)     (33)
                                               --------------------------------------------------
     Balance as of December 31, 2002              $ 1,922   $ 1,733     $ 64     $   -  $ 3,719
     Acquisitions (Note 4A)                             -         -        -         7        7
                                               --------------------------------------------------
     Balance as of December 31, 2003              $ 1,922   $ 1,733     $ 64     $   7  $ 3,726
                                               ==================================================
</TABLE>

     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,
     which  indicated no impairment.  The first annual  impairment  test for the
     Other segment will be performed in 2004, since the goodwill was acquired in
     2003.

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

                                               2003                                2002
                                  -------------------------------    -------------------------------
     (in millions)                Gross Carrying     Accumulated     Gross Carrying     Accumulated
                                      Amount         Amortization        Amount        Amortization
                                  -------------------------------    -------------------------------
     Synthetic fuel intangibles       $ 140             $ (64)            $ 140            $ (45)
     Power agreements acquired          221               (20)               33               (6)
     Other                               62               (12)               41               (8)
                                  -------------------------------    -------------------------------
     Total                            $ 423             $ (96)            $ 214            $ (59)
                                  ===============================    ===============================
</TABLE>

     All of the Company's  intangibles  are subject to  amortization.  Synthetic
     fuel intangibles represent intangibles for synthetic fuel technology. These
     intangibles  are  being  amortized  on  a  straight-line  basis  until  the
     expiration  of tax credits  under  Section 29 of the Internal  Revenue Code
     (Section  29) in December  2007 (See Note 14). In May 2003,  PVI acquired a
     long-term full-requirements power supply agreement at fixed prices for $188
     million.  The intangible related to this power agreement is being amortized
     based on the economic  benefits of the  contract  (See Note 4C). As part of
     the  acquisition  of  generating  assets from LG&E Energy Corp. in February
     2002, power agreements of $33 million were recorded and are amortized based
     on the economic  benefits of the contracts  through  December  2004,  which
     approximates  straight-line  (See Note 4D). Other intangibles are primarily
     acquired  customer  contracts  and permits  that are  amortized  over their
     respective  lives. Of the increase in other intangible  assets,  $9 million
     relates  to  customer   contracts  acquired  as  part  of  the  Westchester
     acquisition,  which was  identified as an intangible in the final  purchase
     price allocation (See Note 4E).

                                       97
<PAGE>

     Amortization  expense  recorded  on  intangible  assets for the years ended
     December  31,  2003,  2002 and 2001 was,  in  millions,  $37,  $33 and $22,
     respectively.  The estimated  annual  amortization  expense for  intangible
     assets for 2004 through 2008, in millions,  is approximately $42, $35, $36,
     $36 and $17, respectively.

9.   Impairments of Long-Lived Assets and Investments

     Effective January 1, 2002, the Company adopted SFAS No. 144, which provides
     guidance for the  accounting  and  reporting of  impairment  or disposal of
     long-lived assets. The statement  supersedes SFAS No. 121,  "Accounting for
     the  Impairment  of  Long-Lived  Assets  and for  Long-Lived  Assets  to be
     Disposed  Of." In  2003,  2002  and  2001,  the  Company  recorded  pre-tax
     long-lived   asset  and  investment   impairments   and  other  charges  of
     approximately $38 million, $414 million and $209 million, respectively.

     A. Long-Lived Assets

     Due to the reduction in coal production the Company evaluated  Kentucky May
     Coal Mine's  long-lived  assets in 2003. Fair value was determined based on
     discounted  cash flows.  As a result of this review,  the Company  recorded
     asset  impairments  of $17  million  on a pre-tax  basis  during the fourth
     quarter of 2003.

     An estimated  impairment of assets held for sale of $59 million is included
     in the 2002 amount, which relates to Railcar Ltd. (See Note 3B).

     Due to  the  decline  of  the  telecommunications  industry  and  continued
     operating  losses,  the Company  initiated an independent  valuation  study
     during 2002 to assess the  recoverability  of the long-lived  assets of PTC
     and  Caronet.  Based  on  this  assessment,   the  Company  recorded  asset
     impairments  of $305  million on a pre-tax  basis and other  charges of $25
     million on a pre-tax basis  primarily  related to inventory  adjustments in
     the third  quarter  of 2002.  This  write-down  constitutes  a  significant
     reduction in the book value of these long-lived assets.

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

     Due to historical  losses at Strategic  Resource  Solutions Corp. (SRS) and
     the  decline in the market  value for  technology  companies,  the  Company
     evaluated the long-lived  assets of SRS in 2001.  Fair value was determined
     based on  discounted  cash flows.  As a result of this review,  the Company
     recorded  asset  impairments of $43 million and other charges of $2 million
     on a pre-tax basis during the fourth quarter of 2001.

     B. Investments

     The Company  continually  reviews its  investments  to determine  whether a
     decline in fair value  below the cost  basis is other  than  temporary.  In
     2003, PEC's affordable  housing investment (AHI) portfolio was reviewed and
     deemed  to  be  impaired  based  on  various  factors  including  continued
     operating  losses of the AHI portfolio and  management  performance  issues
     arising at certain  properties within the AHI portfolio.  As a result,  PEC
     recorded an  impairment of $18 million on a pre-tax basis during the fourth
     quarter of 2003.  PEC also  recorded an impairment of $3 million for a cost
     investment.

     In 2001, the Company obtained a valuation study to assess its investment in
     Interpath  Communications  Inc.  (Interpath) based on current valuations in
     the technology  sector. As a result, the Company recorded an impairment for
     other-than-temporary  declines  in the  fair  value  of its  investment  in
     Interpath.  Investment  impairments  were also recorded  related to certain
     investments  of SRS.  Investment  write-downs  totaled  $164  million  on a
     pre-tax basis for the year ended December 31, 2001. In May 2002,  Interpath
     merged with a third party. As a result,  the Company reviewed the Interpath
     investment  for  impairment  and  wrote  off the  remaining  amount  of its
     cost-basis  investment in Interpath,  recording a pre-tax impairment of $25
     million in the third  quarter of 2002. In the fourth  quarter of 2002,  the
     Company sold its remaining interest in Interpath for a nominal amount.

                                       98
<PAGE>

10.  Equity

     A. Common Stock

     In November  2002,  the Company  issued 14.7 million shares of common stock
     for net cash proceeds of approximately  $600 million,  which were primarily
     used to retire  commercial  paper.  In April 2002,  the Company  issued 2.5
     million shares of common stock,  valued at approximately  $129 million,  in
     conjunction with the purchase of Westchester (See Note 4E). In August 2001,
     the  Company  issued  12.6  million  shares  of  common  stock for net cash
     proceeds of $489 million,  which were primarily  used to retire  commercial
     paper.

     At December 31, 2003,  the Company had  approximately  53 million shares of
     common stock  authorized by the Board of Directors  that remained  unissued
     and reserved,  primarily to satisfy the requirements of the Company's stock
     plans. In 2002, the Board of Directors  authorized meeting the requirements
     of the Progress  Energy  401(k)  Savings and Stock  Ownership  Plan and the
     Investor Plus Stock Purchase Plan with original issue shares. Prior to that
     authorization,  the Company met the  requirements of these stock plans with
     issued and  outstanding  shares held by the Trustee of the Progress  Energy
     401(k) Savings and Stock Ownership Plan  (previously  known as the Progress
     Energy, Inc. Stock  Purchase-Savings Plan) or with open market purchases of
     common stock shares,  as appropriate.  During 2003 and 2002,  respectively,
     the Company issued approximately 8 million and 2 million shares under these
     plans for net proceeds of approximately  $309 million and $86 million.  The
     Company  continues to meet the  requirements  of the restricted  stock plan
     with issued and outstanding shares.

     There are various provisions  limiting the use of retained earnings for the
     payment of dividends  under  certain  circumstances.  At December 31, 2003,
     there were no significant restrictions on the use of retained earnings.

     B. Stock-Based Compensation

     Employee Stock Ownership Plan

     The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
     Plan (401(k)) for which  substantially  all full-time  non-bargaining  unit
     employees  and  certain  part-time  non-bargaining  unit  employees  within
     participating subsidiaries are eligible.  Participating subsidiaries within
     the  Company as of  January  1, 2003 were PEC,  PEF,  PTC,  Progress  Fuels
     (Corporate) and Progress  Energy Service  Company.  Effective  December 19,
     2003 (the PTC LLP/EPIK  merger  date),  PTC no longer  participates  in the
     401(k) plan.  The 401(k),  which has Company  matching and  incentive  goal
     features,  encourages systematic savings by employees and provides a method
     of  acquiring  Company  common  stock and other  diverse  investments.  The
     401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that
     can enter into acquisition loans to acquire Company common stock to satisfy
     401(k)  common  share  needs.  Qualification  as an ESOP did not change the
     level of benefits  received by  employees  under the 401(k).  Common  stock
     acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in
     a suspense account.  The common stock is released from the suspense account
     and made  available  for  allocation  to  participants  as the ESOP loan is
     repaid.  Such  allocations  are used to  partially  meet common stock needs
     related to Company matching and incentive  contributions  and/or reinvested
     dividends.  All or a portion of the dividends paid on ESOP suspense  shares
     and on ESOP  shares  allocated  to  participants  may be used to repay ESOP
     acquisition  loans.  To the extent used to repay such loans,  the dividends
     are  deductible  for income tax  purposes.  Also,  beginning  in 2002,  the
     dividends   paid  on  ESOP  shares  which  are  either  paid   directly  to
     participants or used to purchase additional shares which are then allocated
     to participants are fully deductible for income tax purposes.

     There were 4.0 million and 4.6 million ESOP suspense shares at December 31,
     2003 and 2002,  respectively,  with a fair value of $183  million  and $200
     million,  respectively.  ESOP shares allocated to plan participants totaled
     13.1 million and 13.6 million in December 31, 2003 and 2002,  respectively.
     The  Company's  matching and  incentive  goal  compensation  cost under the
     401(k) is  determined  based on matching  percentages  and  incentive  goal
     attainment as defined in the plan. Such  compensation  cost is allocated to
     participants' accounts in the form of Company common stock, with the number
     of shares  determined  by dividing  compensation  cost by the common  stock
     market value at the time of allocation.  The Company currently meets common
     stock share needs with open market purchases, with shares released from the
     ESOP  suspense  account and with newly issued  shares.  Costs for incentive
     goal  compensation are accrued during the fiscal year and typically paid in
     shares in the following  year;  while costs for the matching  component are
     typically met with shares in the same year incurred. Matching and incentive
     cost which were met and will be met with shares  released from the suspense
     account totaled  approximately $20 million, $20 million and $18 million for
     the years ended  December  31,  2003,  2002 and 2001,  respectively.  Total

                                       99
<PAGE>

     matching and incentive cost totaled  approximately $35 million, $30 million
     and $29 million  for the years  ended  December  31,  2003,  2002 and 2001,
     respectively,  including 2001 amounts  incurred under the previous  Florida
     Progress  Corporation  (Florida Progress) Plan. The Company has a long-term
     note  receivable  from the 401(k) Trustee related to the purchase of common
     stock from the Company in 1989. The balance of the note receivable from the
     401(k)  Trustee is included in the  determination  of unearned  ESOP common
     stock,  which reduces  common stock equity.  ESOP shares that have not been
     committed  to be  released to  participants'  accounts  are not  considered
     outstanding for the  determination  of earnings per common share.  Interest
     income on the note receivable and dividends on unallocated  ESOP shares are
     not recognized for financial statement purposes.

     Stock Option Agreements

     Pursuant  to the  Company's  1997  Equity  Incentive  Plan and 2002  Equity
     Incentive  Plan,  amended and restated as of July 10, 2002, the Company may
     grant options to purchase shares of common stock to directors, officers and
     eligible employees for up to 5 million and 15 million shares, respectively.
     Generally,  options  granted to employees vest one-third per year with 100%
     vesting at the end of year three while  options  granted to directors  vest
     100% at the end of one year.  The options expire ten years from the date of
     grant.  All option  grants have an exercise  price equal to the fair market
     value of the Company's common stock on the grant date. 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. The exercise price at which options are granted by the Company equals
     the market price at grant date and accordingly, no compensation expense has
     been recognized for any options granted during 2003, 2002 and 2001.

     The pro forma  information  presented  in Note 1  regarding  net income and
     earnings  per share is  required  by SFAS No.  148.  Under this  statement,
     compensation  cost is measured at the grant date based on the fair value of
     the award and is recognized over the vesting period.  The pro forma amounts
     presented in Note 1 have been  determined  as if the Company had  accounted
     for its employee stock options under SFAS No. 123. The fair value for these
     options was  estimated  at the date of grant using a  Black-Scholes  option
     pricing model with the following weighted-average assumptions:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                               2003         2002        2001
                                                               ------------------------------
     Risk-free interest rate                                    4.25%       4.14%       4.83%
     Dividend yield                                             4.75%       5.20%       5.21%
     Volatility factor                                         22.28%      24.98%      26.47%
     Weighted-average expected life of the options (in years)    10          10          10
</TABLE>

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

     The  options  outstanding  at  December  31,  2003,  2002  and  2001  had a
     weighted-average  remaining  contractual life of 8.70, 9.32 and 9.75 years,
     respectively, and had exercise prices that ranged from $40.41 to $51.85. At
     December  31,  2003,  92 thousand  options  have been  exercised,  while no
     options have expired. The tabular information for the option activity is as
     follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                     2003                     2002                     2001
                                          -----------------------------------------------------------------------------
                                                       Weighted-                Weighted-                Weighted-
                                                       Average                  Average                  Average
                                          Number of    Exercise    Number of    Exercise   Number of     Exercise
(option quantities in millions)            Options      Price       Options      Price      Options       Price
--------------------------------------------------------------------------------------------------------------------
Options outstanding, January 1               5.2       $ 42.84        2.3       $ 43.49        -
Granted                                      3.0       $ 44.70        2.9       $ 42.34       2.4        $ 43.49
Forfeited                                   (0.1)      $ 43.64         -        $ 43.71      (0.1)       $ 43.49
Canceled                                    (0.1)      $ 43.62         -           -           -            -
Exercised                                     -        $ 43.00         -           -           -            -
Options outstanding, December 31             8.0       $ 43.54        5.2       $ 42.84       2.3        $ 43.49
Options exercisable, December 31
   with a remaining contractual life of
    8.75 years                               2.4       $ 43.09        0.8       $ 43.49        -            -
Weighted-average grant date fair value
   of options granted during the year                  $  7.16                  $  6.83                  $  8.05
</TABLE>

                                      100
<PAGE>

     Other Stock-Based Compensation Plans

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

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

     The RSA program  allows the Company to grant  shares of  restricted  common
     stock to officers and key employees of the Company.  The restricted  shares
     generally vest on a graded vesting  schedule over a minimum of three years.
     Compensation  expense,  which is based on the fair value of common stock at
     the grant date, is recognized  over the  applicable  vesting  period,  with
     corresponding  increases in common stock equity. The weighted-average price
     of  restricted  shares at the grant date was  $39.53,  $44.27 and $41.86 in
     2003, 2002 and 2001,  respectively.  Compensation expense is reduced by any
     forfeitures.  Restricted  shares are not included as shares  outstanding in
     the basic  earnings  per share  calculation  until the shares are no longer
     forfeitable. Changes in restricted stock shares outstanding were:

                             2003       2002         2001
                          ---------   ---------    ---------

     Beginning balance     950,180     674,511      653,344
     Granted               180,200     365,920      113,651
     Vested               (151,677)    (75,200)     (70,762)
     Forfeited             (33,820)    (15,051)     (21,722)
                          ---------   ---------    ---------
     Ending balance        944,883     950,180      674,511
                          =========   =========    =========

     The total amount expensed for other stock-based  compensation plans was $27
     million, $17 million and $14 million in 2003, 2002 and 2001, respectively.

     C. Earnings Per Common Share

     Basic earnings per common share is based on the weighted-average  number of
     common shares  outstanding.  Diluted earnings per share includes the effect
     of the  non-vested  portion of  restricted  stock  awards and the effect of
     stock options outstanding.

     A  reconciliation   of  the   weighted-average   number  of  common  shares
     outstanding for basic and dilutive purposes is as follows:

     (in millions)                                 2003        2002        2001
                                                --------   ---------    --------
     Weighted-average common shares - basic       237.2       217.2       204.7
     Restricted stock awards                        1.0          .8          .6
     Stock options                                    -          .2           -
                                                --------   ---------    --------
     Weighted-average shares - fully diluted      238.2       218.2       205.3
                                                ========   =========    ========

                                      101
<PAGE>

     There  are no  adjustments  to net  income  or to  income  from  continuing
     operations between the calculations of basic and fully diluted earnings per
     common  share.  ESOP shares that have not been  committed to be released to
     participants' accounts are not considered outstanding for the determination
     of earnings per common share. The  weighted-average of these shares totaled
     4.1 million,  4.8 million and 5.4 million for the years ended  December 31,
     2003, 2002 and 2001,  respectively.  There were 5.3 million and 92 thousand
     stock  options  outstanding  at December  31, 2003 and 2002,  respectively,
     which  were not  included  in the  weighted-average  number of  shares  for
     computing  the  fully   diluted   earnings  per  share  because  they  were
     antidilutive.

     D. Accumulated Other Comprehensive Loss

     Components of accumulated other comprehensive loss are as follows:

     (in millions)                                     2003          2002
                                                   -----------   -----------
     Loss on cash flow hedges                        $ (35)        $ (42)
     Minimum pension liability adjustments             (15)         (192)
     Foreign currency translation and other              -           (4)
                                                   -----------   -----------
     Total accumulated other comprehensive loss      $ (50)        $(238)
                                                   ===========   ===========

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

     All of the Company's preferred stock was issued by its subsidiaries and was
     not  subject  to  mandatory  redemption.  Preferred  stock  outstanding  at
     December 31, 2003 and 2002 consisted of the following:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions, except share data and par value)
     Progress Energy Carolinas, Inc.
     Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
        20,000,000 shares, cumulative, $100 par value Serial Preferred Stock:
        $5.00 Preferred -  236,997  shares outstanding (redemption price $110.00)          $ 24
        $4.20 Serial Preferred - 100,000 shares outstanding  (redemption price $102.00)      10
        $5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00)       25
                                                                                          -------
                                                                                           $ 59
                                                                                          -------
     Progress Energy Florida, Inc.
     Authorized - 4,000,000 shares, cumulative, $100 par value Preferred Stock;
       5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000
       shares, $100 par value Preference Stock $100 par value Preferred Stock:
        4.00% - 39,980 shares outstanding (redemption price $104.25)                       $  4
        4.40% - 75,000 shares outstanding (redemption price $102.00)                          8
        4.58% - 99,990 shares outstanding (redemption price $101.00)                         10
        4.60% - 39,997 shares outstanding (redemption price $103.25)                          4
        4.75% - 80,000 shares outstanding (redemption price $102.00)                          8
                                                                                          -------
                                                                                           $  34
                                                                                          -------
      Total Preferred Stock of Subsidiaries                                                $  93
                                                                                          =======
</TABLE>


                                      102
<PAGE>

12.  Debt and Credit Facilities

     A. Debt and Credit

     At December 31, the  Company's  long-term  debt  consisted of the following
     (maturities and weighted-average interest rates at December 31, 2003):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                                                 2003              2002
                                                                         ---------------    --------------
Progress Energy, Inc.
Senior unsecured notes, maturing 2004-2031                       6.86%       $ 4,800          $ 4,800
Unamortized fair value hedge gain, net                                            19               34
Unamortized premium and discount, net                                            (27)             (31)
                                                                         ---------------    --------------
                                                                               4,792            4,803
                                                                         ---------------    --------------
Progress Energy Carolinas, Inc.
First mortgage bonds, maturing 2004-2033                         6.42%         1,900            1,550
Pollution control obligations, maturing 2010-2024                1.69%           708              708
Unsecured notes, maturing 2012                                   6.50%           500              500
Medium-term notes, maturing 2008                                 6.65%           300              300
Miscellaneous notes                                                                -                6
Unamortized premium and discount, net                                            (22)             (16)
                                                                         ---------------    --------------
                                                                               3,386            3,048
                                                                         ---------------    --------------
Progress Energy Florida, Inc.
First mortgage bonds, maturing 2004-2033                         5.60%         1,330              810
Pollution control obligations, maturing 2018-2027                1.04%           241              241
Medium-term notes, maturing 2004-2028                            6.75%           379              417
Unamortized premium and discount, net                                             (3)              (7)
                                                                         ---------------    --------------
                                                                               1,947            1,461
                                                                         ---------------    --------------
Florida Progress Funding Corporation (See Note 12F)
Debt to affiliated trust, maturing 2039                          7.10%           309                -
Mandatorily redeemable preferred securities, maturing 2039                         -              300
Unamortized premium and discount, net                                            (39)             (39)
                                                                         ---------------    --------------
                                                                                 270              261
                                                                         ---------------    --------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2004-2008                            6.78%           165              223
Miscellaneous notes                                                                1                1
                                                                         ---------------    --------------
                                                                                 166              224
                                                                         ---------------    --------------
Progress Genco Ventures, LLC
Variable rate project financing, maturing 2007                  3.04%            241              225
                                                                         ---------------    --------------
Current portion of long-term debt                                               (868)            (275)
                                                                         ---------------    --------------
        Total long-term debt                                                 $ 9,934          $ 9,747
                                                                         ===============    ==============
</TABLE>

     At December 31, 2003 and 2002, the Company had $4 million and $695 million,
     respectively,  of outstanding  commercial  paper and other  short-term debt
     classified as short-term obligations.  The weighted-average  interest rates
     of such short-term obligations at December 31, 2003 and 2002 were 2.25% and
     1.67%, respectively.

     At December 31, 2003,  the Company had committed  lines of credit which are
     used to support its  commercial  paper  borrowings  and had no  outstanding
     loans.  The Company is required to pay minimal  annual  commitment  fees to
     maintain  its  credit  facilities.   The  following  table  summarizes  the
     Company's credit facilities:

                                      103
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)
      Company                              Description                         Total
     ----------------------------------------------------------------------------------

     Progress Energy, Inc.                 364-Day (expiring 11/10/04)       $   250
     Progress Energy, Inc.                 3-Year (expiring 11/13/04)            450
     Progress Energy Carolinas, Inc.       364-Day (expiring 7/29/04)            165
     Progress Energy Carolinas, Inc.       3-Year (expiring 7/31/05)             285
     Progress Energy Florida, Inc.         364-Day (expiring 3/31/04)            200
     Progress Energy Florida, Inc.         3-Year (expiring 4/1/06)              200
                                                                           ------------
     Total credit facilities                                                 $ 1,550
                                                                           ============
</TABLE>

     Progress  Energy  and  PEF  each  have an  uncommitted  bank  bid  facility
     authorizing them to borrow and reborrow,  and have loans outstanding at any
     time,  up to $300 million and $100  million,  respectively.  These bank bid
     facilities were not drawn at December 31, 2003.

     The combined  aggregate  maturities of long-term debt for 2004 through 2008
     are approximately $868 million,  $348 million,  $908 million,  $915 million
     and $827 million, respectively.

     B. Covenants and Default Provisions

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

     All of the  credit  facilities  and the  Genco's  bank  facility  include a
     defined  maximum total debt to total capital  ratio.  At December 31, 2003,
     the maximum and calculated ratios for these four companies, pursuant to the
     terms of the agreements, are as follows:

     Company                           Maximum Ratio    Actual Ratio (a)
     --------------------------------------------------------------------
     Progress Energy, Inc.                  68%             61.5%
     Progress Energy Carolinas, Inc.        65%             51.4%
     Progress Energy Florida, Inc.          65%             51.5%
     Progress Genco Ventures, LLC           40%             24.6%

     (a)  Indebtedness  as  defined  by the  bank  agreements  includes  certain
          letters  of  credit  and  guarantees  which  are not  recorded  on the
          Consolidated Balance Sheets.

     Progress Energy's 364-day credit facility and both PEF's 364-day and 3-year
     credit  facilities  have a financial  covenant for interest  coverage.  The
     covenants  require  Progress  Energy's and PEF's Earnings before  interest,
     taxes, and depreciation and amortization to interest expense ratio to be at
     least 2.5 to 1 and 3 to 1,  respectively.  For the year ended  December 31,
     2003,  the  ratios  were 3.74 to 1 and 9.22 to 1 for the  Company  and PEF,
     respectively.  Genco's  bank  facility  requires  a minimum  1.25 to 1 debt
     service coverage ratio. For the year ended December 31, 2003,  Genco's debt
     service coverage was 6.35 to 1.

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

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

                                      104
<PAGE>

     Additionally,  certain  of  Progress  Energy's  long-term  debt  indentures
     contain cross-default  provisions for defaults of indebtedness in excess of
     $25 million;  these provisions only apply to other  obligations of Progress
     Energy,   not  its   subsidiaries.   In  the  event  that  these  indenture
     cross-default  provisions are triggered,  the debt holders could accelerate
     payment  of  approximately   $4,800  million  in  long-term  debt.  Certain
     agreements underlying the Company's  indebtedness also limit its ability to
     incur  additional  liens or engage in certain  types of sale and  leaseback
     transactions.

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

     PEC's mortgage indenture provides that, as long as any first mortgage bonds
     are outstanding,  cash dividends and  distributions on its common stock and
     purchases  of its  common  stock are  restricted  to  aggregate  net income
     available for PEC since December 31, 1948, plus $3 million, less the amount
     of all preferred  stock dividends and  distributions,  and all common stock
     purchases,  since  December 31, 1948.  At December 31, 2003,  none of PEC's
     retained earnings were restricted.

     In addition, PEC's Articles of Incorporation provide that cash dividends on
     common stock shall be limited to 75% of net income  available for dividends
     if common stock equity falls below 25% of total capitalization,  and to 50%
     if common stock equity falls below 20%. At December 31, 2003,  PEC's common
     stock equity was approximately 50.7% of total capitalization.

     PEF's mortgage  indenture  provides that it will not pay any cash dividends
     upon its common stock, or make any other  distribution to the stockholders,
     except a payment or  distribution  out of net income of PEF  subsequent  to
     December 31, 1943. At December 31, 2003,  none of PEF's  retained  earnings
     were restricted.

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

     PEF's Articles of Incorporation  also provide that cash dividends on common
     stock  shall be limited to 75% of net income  available  for  dividends  if
     common stock equity falls below 25% of total capitalization,  and to 50% if
     common stock  equity  falls below 20%. On December  31, 2003,  PEF's common
     stock equity was approximately 52.5% of total capitalization.

     Genco is  required  to hedge 75% of the amount  outstanding  under its bank
     facility through September 2005 and 50% thereafter, pursuant to the term of
     the agreement for expansion of its nonregulated  generation  portfolio.  At
     December  31,  2003,  Genco  held  interest  rate cash flow  hedges  with a
     notional  amount of $195  million  and a total  fair  value of $11  million
     liability position related to this covenant.  See additional  discussion of
     interest rate cash flow hedges in Note 17.

     C. Secured Obligations

     PEC's and  PEF's  first  mortgage  bonds are  secured  by their  respective
     mortgage   indentures.   Each   mortgage   constitutes   a  first  lien  on
     substantially  all of the  fixed  properties  of  the  respective  company,
     subject to certain  permitted  encumbrances  and exceptions.  Each mortgage
     also constitutes a lien on subsequently  acquired property. At December 31,
     2003,  PEC and PEF had a total of  approximately  $4,179  million  of first
     mortgage bonds  outstanding,  including those related to pollution  control
     obligations. Each mortgage allows the issuance of additional mortgage bonds
     upon the satisfaction of certain conditions.

     Genco obtained a bank facility to be used  exclusively for expansion of its
     nonregulated  generation  portfolio.  Borrowings  under this  facility  are
     secured by the assets in the generation  portfolio.  The facility is for up
     to $260 million, of which $241 million had been drawn at December 31, 2003.
     Borrowings   under  the  facility  are  restricted   for  the   operations,
     construction,  repayments and other related  charges of the credit facility
     for the  development  projects.  Cash held and restricted to operations was
     $24 million and $21  million at December  31, 2003 and 2002,  respectively,
     and is included  in other  current  assets.  Cash held and  restricted  for
     long-term  purposes was $9 million and $37 million at December 31, 2003 and
     2002, respectively,  and is included in other assets and deferred debits on
     the Consolidated Balance Sheets.

                                      105
<PAGE>

     D. Guarantees of Subsidiary Debt

     FPC has guaranteed the outstanding debt obligations for PCH, a wholly-owned
     subsidiary of Florida Progress. At December 31, 2003 and 2002, PCH had $165
     million and $223 million,  respectively;  in medium-term  notes outstanding
     which are  recorded  on the  Company's  accompanying  Consolidated  Balance
     Sheets.

     E. Hedging Activities

     Progress  Energy uses  interest  rate  derivatives  to adjust the fixed and
     variable rate  components of its debt portfolio and to hedge cash flow risk
     related  to  commercial  paper  and to fixed  rate debt to be issued in the
     future.  See  discussion  of  risk  management  activities  and  derivative
     transactions at Note 17.

     F.   FPC-Obligated   Mandatorily  Redeemable  Preferred  Securities  of  an
          Unconsolidated 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%. Prior to the adoption of FIN No.
     46,  the  Company   consolidated  the  Trust,  which  holds  the  Preferred
     Securities.  The  Trust is a  special-purpose  entity,  and  therefore  the
     Company  applied FIN No. 46 to the Trust at December 31, 2003 (See Note 2).
     The adoption of FIN No. 46 required the Company to deconsolidate  the Trust
     at December 31, 2003.

     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 Florida  Progress  Funding  Corporation  (Funding  Corp.) its
     7.10% Junior Subordinated  Deferrable  Interest Notes (subordinated  notes)
     due 2039, for a principal amount of $309 million.  The  subordinated  notes
     and the Notes  Guarantee  (as  discussed  below) are the sole assets of the
     Trust.  Funding Corp.'s  proceeds from the sale of the  subordinated  notes
     were advanced to Progress Capital and used for general  corporate  purposes
     including the repayment of a portion of certain outstanding short-term bank
     loans and commercial paper.

     FPC has fully and  unconditionally  guaranteed  the  obligations of Funding
     Corp. under the subordinated notes (the Notes Guarantee).  In addition, FPC
     has guaranteed the payment of all distributions related to the $300 million
     Preferred  Securities  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.

     Prior to December  2003,  these  Preferred  Securities  were  classified as
     long-term  debt  on  the  Company's   Consolidated  Balance  Sheets.  After
     deconsolidation of the Trust at December 31, 2003, FPC's subordinated notes
     payable to the Trust are  classified  as  affiliate  long-term  debt on the
     Company's December 31, 2003 Consolidated Balance Sheet.

13.  Fair Value of Financial Instruments

     The  carrying   amounts  of  cash  and  cash   equivalents  and  short-term
     obligations  approximate  fair value due to the short  maturities  of these
     instruments.  At December 31, 2003 and 2002,  investments in  company-owned
     life  insurance  and other benefit plan assets,  with  carrying  amounts of
     approximately $162 million and $150 million,  respectively, are included in
     miscellaneous other property and investments and approximate fair value due
     to the short maturity of the instruments.  Other  instruments are presented
     at fair value in accordance with GAAP. The carrying amount of the Company's
     long-term  debt,  including  current  maturities,  was $10,802  million and
     $10,022 million at December 31, 2003 and 2002, respectively.  The estimated
     fair value of this debt, as obtained from quoted market prices for the same
     or similar issues,  was $11,917 million and $10,974 million at December 31,
     2003 and 2002, respectively.

                                      106
<PAGE>

     External trust funds have been established to fund certain costs of nuclear
     decommissioning  (See Note 5D). These nuclear  decommissioning  trust funds
     are invested in stocks, bonds and cash equivalents. Nuclear decommissioning
     trust funds are  presented on the  Consolidated  Balance  Sheets at amounts
     that  approximate  fair value.  Fair value is obtained  from quoted  market
     prices for the same or similar investments.

14.  Income Taxes

     Deferred income taxes are provided for temporary  differences  between book
     and tax bases of assets and liabilities.  Investment tax credits related to
     regulated  operations  are  amortized  over the service life of the related
     property.  To the extent that the  establishment  of deferred  income taxes
     under SFAS No. 109,  "Accounting  for Income  Taxes" is different  from the
     recovery  of taxes  by PEC and PEF  through  the  ratemaking  process,  the
     differences  are deferred  pursuant to SFAS No. 71. A  regulatory  asset or
     liability  has been  recognized  for the impact of tax expenses or benefits
     that are  recovered  or  refunded  in  different  periods by the  utilities
     pursuant to rate orders.

     Accumulated deferred income tax (assets) liabilities at December 31 are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                                 2003         2002
                                                               -----------   ------------

     Accumulated depreciation and property cost differences      $ 1,524       $ 1,624
     Deferred costs, net                                             (49)          (73)
     Federal income tax credit carry forward                        (682)         (472)
     Minimum pension liability adjustment                             (9)         (117)
     Miscellaneous other temporary differences, net                 (153)         (111)
     Valuation allowance                                              42            47
                                                               -----------   ------------
     Net accumulated deferred income tax liability               $   673       $   898
                                                               ===========   ============
</TABLE>

     Total  deferred  income tax  liabilities  were  $2,427  million  and $2,430
     million at December 31, 2003 and 2002, respectively.  Total deferred income
     tax assets were $1,754  million and $1,532 million at December 31, 2003 and
     2002,  respectively.  At December  31,  2003 and 2002,  the Company had net
     noncurrent  deferred tax  liabilities of $737 million and $858 million.  At
     December 31, 2003, the Company had a net current  deferred tax asset of $64
     million  which is included on the  Consolidated  Balance  Sheets  under the
     caption  prepayments  and other current  assets.  At December 31, 2002, the
     Company had a net current  deferred tax  liability of $40 million  which is
     included on the Consolidated Balance Sheets under the caption other current
     liabilities.

     The federal  income tax credit carry  forward at December 31, 2003 consists
     of $659  million  of  alternative  minimum  tax credit  with an  indefinite
     carry-forward  period and $23  million of general  business  credit  with a
     carry-forward period that will begin to expire in 2020.

     The Company established  additional valuation allowances of $5 million, $12
     million and $24 million during 2003,  2002 and 2001,  respectively,  due to
     the uncertainty of realizing certain future state tax benefits. The overall
     decrease  in the 2003  valuation  allowance  balance is largely  due to the
     Company's sale of its wholly-owned subsidiary Caronet. The Company believes
     it is more  likely  than not that the  results  of future  operations  will
     generate  sufficient  taxable  income to allow for the  utilization  of the
     remaining deferred tax assets.

                                      107
<PAGE>

     Reconciliations of the Company's effective income tax rate to the statutory
     federal income tax rate are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                        2003              2002               2001
                                                     ------------     -------------      -------------

     Effective income tax rate                           (15.5)%         (40.0)%           (40.0)%
     State income taxes, net of federal benefit           (3.3)           (8.2)             (7.7)
     AFUDC amortization                                   (2.0)           (5.2)             (5.0)
     Federal tax credits                                  50.3            78.0              94.5
     Goodwill amortization and write-offs                   -               -              (11.4)
     Investment tax credit amortization                    2.3             4.7               5.9
     ESOP dividend deduction                               2.1             3.8               1.9
     Interpath investment impairment                        -               -               (2.1)
     Other differences, net                                1.1             1.9              (1.1)
                                                     ------------     -------------      -------------

     Statutory federal income tax rate                    35.0%           35.0%             35.0%
                                                     ============     =============      =============
</TABLE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     Income  tax  expense  (benefit)  applicable  to  continuing  operations  is
     comprised of:

     (in millions)                                  2003            2002           2001
                                               -------------    -------------   ------------

     Current   -  federal                         $  129           $ 195         $  184
                  state                               54              67             52
     Deferred  -  federal                           (255)           (379)          (357)
                  state                              (21)            (23)           (10)
     Investment tax credit                           (16)            (18)           (23)
                                               -------------    ------------    ------------
          Total income tax expense (benefit)      $ (109)         $ (158)        $ (154)
                                               =============    ============    ============
</TABLE>

     The Company, through its subsidiaries, is a majority owner in five entities
     and a  minority  owner in one  entity  that owns  facilities  that  produce
     synthetic  fuel as defined  under the Internal  Revenue  Code  (Code).  The
     production and sale of the synthetic fuel from these  facilities  qualifies
     for tax credits under  Section 29 if certain  requirements  are  satisfied,
     including a requirement  that the synthetic fuel differs  significantly  in
     chemical  composition from the coal used to produce such synthetic fuel and
     that the fuel was  produced  from a  facility  that was  placed in  service
     before July 1, 1998. Total Section 29 credits  generated to date (including
     FPC prior to its  acquisition  by the  Company)  are  approximately  $1,243
     million.  All entities have received private letter rulings (PLRs) from the
     Internal  Revenue  Service  (IRS)  with  respect  to their  synthetic  fuel
     operations.  The PLRs do not limit the  production on which  synthetic fuel
     credits may be claimed.  Should the tax credits be denied on future audits,
     and the Company fails to prevail  through the IRS or legal  process,  there
     could be a significant  tax liability owed for previously  taken Section 29
     credits, with a significant impact on earnings and cash flows.

     One of the  Company's  synthetic  fuel  entities,  Colona  Synfuel  Limited
     Partnership,  L.L.L.P.  (Colona), is being audited by the IRS. The audit of
     Colona was expected.  The Company is audited regularly in the normal course
     of  business  as  are  most  similarly  situated  companies.   The  Company
     (including FPC prior to its  acquisition by the Company) has been allocated
     approximately  $317 million in tax credits to date from this synthetic fuel
     entity.

     In September 2002, all of Progress Energy's  majority-owned  synthetic fuel
     entities,  including  Colona,  were  accepted  into  the  IRS's  Pre-Filing
     Agreement  (PFA) program.  The PFA program allows  taxpayers to voluntarily
     accelerate  the IRS exam  process in order to seek  resolution  of specific
     issues.  Either the Company or the IRS can withdraw from the program at any
     time,  and issues not resolved  through the program may proceed to the next
     level of the IRS exam process. While the ultimate outcome is uncertain, the
     Company believes that  participation in the PFA program will likely shorten
     the tax exam process.

     In June 2003,  the Company was informed that IRS field  auditors had 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.

                                      108
<PAGE>

     In October 2003,  the National  Office of the IRS informed the Company that
     it had rejected the IRS field auditors'  challenges  regarding  whether the
     synthetic fuel produced at the Company's  Colona facility was the result of
     a significant  chemical change.  The National Office had concluded that the
     experts, engaged by Colona who test the synthetic fuel for chemical change,
     use reasonable scientific methods to reach their conclusions.  Accordingly,
     the  National  Office will not take any adverse  action on the PLR that has
     been issued for the Colona facility.

     Although  this  ruling  applies  only to the Colona  facility,  the Company
     believes that the National Office's  reasoning would be equally  applicable
     to the other Progress Energy  facilities.  The Company 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
     other facilities.

     In February 2004,  subsidiaries of the Company  finalized  execution of the
     Colona Closing Agreement with the Internal Revenue Service concerning their
     Colona synthetic fuel  facilities.  The Colona Closing  Agreement  provided
     that the Colona  facilities  were  placed in service  before  July 1, 1998,
     which  is one of the  qualification  requirements  for  tax  credits  under
     Section 29. The Colona  Closing  Agreement  further  provides that the fuel
     produced  by the  Colona  facilities  in 2001  is a  "qualified  fuel"  for
     purposes of the Section 29 tax credits.  This action  concludes the IRS PFA
     program with respect to Colona.

     Although the  execution of the Colona  Closing  Agreement is a  significant
     event, the audits of the Company's facilities are not yet completed and the
     PFA process  continues with respect to the four  synthetic fuel  facilities
     owned by other affiliates of Progress Energy and FPC. Currently,  the focus
     of that process is to determine that the facilities  were placed in service
     before July 1, 1998. In management's opinion,  Progress Energy is complying
     with all the  necessary  requirements  to be  allowed  such  credits  under
     Section 29, although it cannot provide  certainty,  that it will prevail if
     challenged  by the IRS on credits  taken.  Accordingly,  the Company has no
     current plans to alter its synthetic fuel  production  schedule as a result
     of these matters.

     In October  2003,  the  United  States  Senate  Permanent  Subcommittee  on
     Investigations began a general investigation  concerning synthetic fuel tax
     credits  claimed  under  Section 29. The  investigation  is  examining  the
     utilization  of the  credits,  the  nature  of the  technologies  and fuels
     created,  the use of the synthetic fuel and other aspects of Section 29 and
     is not specific to the Company's synthetic fuel operations. Progress Energy
     is providing information in connection with this investigation. The Company
     cannot predict the outcome of this matter.

15.  Contingent Value Obligations

     In connection  with the  acquisition of FPC during 2000, the Company issued
     98.6 million contingent value obligations  (CVOs).  Each CVO represents the
     right to  receive  contingent  payments  based on the  performance  of four
     synthetic fuel facilities purchased by subsidiaries of FPC in October 1999.
     The payments,  if any,  would be based on the net after-tax  cash flows the
     facilities generate.  The CVO liability is adjusted to reflect market price
     fluctuations.  The liability,  included in other  liabilities  and deferred
     credits,  at December  31, 2003 and 2002,  was $23 million and $14 million,
     respectively.

16.  Benefit Plans

     A. Postretirement Benefits

     The Company and some of its subsidiaries  have a  non-contributory  defined
     benefit   retirement   (pension)  plan  for   substantially  all  full-time
     employees. The Company also has supplementary defined benefit pension plans
     that provide  benefits to  higher-level  employees.  In addition to pension
     benefits,  the Company and some of its  subsidiaries  provide  contributory
     other  postretirement  benefits (OPEB),  including  certain health care and
     life insurance benefits, for retired employees who meet specified criteria.
     The Company uses a measurement date of December 31 for its pension and OPEB
     plans.

                                      109
<PAGE>

     The components of net periodic benefit cost for the years ended December 31
     are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                               Pension Benefits           Other Postretirement Benefits
                                                     ---------------------------------    -----------------------------
(in millions)                                           2003         2002        2001        2003     2002     2001
                                                     ---------------------------------    ---------------------------
Service cost                                         $      52   $     45    $     31      $    15   $   13   $   13
Interest cost                                              108        106          96           33       32       28
Expected return on plan assets                            (144)      (161)       (169)          (4)      (5)      (5)
Amortization of actuarial (gain) loss                       25          2          (5)           5        1        -
Other amortization, net                                      -          -          (1)           4        4        5
                                                     ---------------------------------    ---------------------------
Net periodic cost/(benefit)                          $      41   $     (8)   $    (48)     $    53   $   45   $   41
Additional cost/(benefit) recognition (Note 16B)           (18)        (7)        (16)           2        2        4
                                                     ---------------------------------    ---------------------------
Net periodic cost/(benefit) recognized               $      23   $    (15)   $    (64)     $    55   $   47   $   45
                                                     =================================    ===========================
</TABLE>

     In addition to the net periodic cost and benefit  reflected  above, in 2003
     the Company  recorded  curtailment  and settlement  effects  related to the
     disposition of NCNG, which are reflected in income/(loss) from discontinued
     operations in the Consolidated Statements of Income. These effects included
     a  pension-related  loss  of $13  million  and an  OPEB-related  gain of $1
     million.

     Prior  service costs and benefits are  amortized on a  straight-line  basis
     over the average remaining service period of active participants. Actuarial
     gains and losses in excess of 10% of the greater of the  projected  benefit
     obligation or the  market-related  value of assets are  amortized  over the
     average remaining service period of active participants.

     To determine the market-related  value of assets, the Company uses a 5-year
     averaging method for a portion of its pension assets and fair value for the
     remaining  portion.  The Company has historically used the 5-year averaging
     method. When the Company acquired Florida Progress in 2000, it retained the
     Florida Progress  historical use of fair value to determine  market-related
     value for Florida Progress pension assets.

     Reconciliations  of the changes in the plans' benefit  obligations  and the
     plans' funded status are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                       Other Postretirement
                                                             Pension Benefits                Benefits
                                                        ------------------------    -------------------------
    (in millions)                                           2003        2002            2003         2002
                                                        ------------------------    -------------------------
    Projected benefit obligation at January 1           $    1,694   $    1,391     $       514  $       401
    Service cost                                                52           45              15           13
    Interest cost                                              108          106              33           32
    Disposition of NCNG                                        (39)           -             (13)           -
    Benefit payments                                           (94)         (91)            (24)         (24)
    Actuarial loss (gain)                                      (66)         243              30           92
                                                           ---------   ----------      ---------    ----------
    Obligation at December 31                                1,655        1,694             555          514
    Fair value of plan assets at December 31                 1,631        1,364              65           52
                                                          ---------   ----------      ----------   ----------

    Funded status                                              (24)        (330)           (490)        (462)
    Unrecognized transition obligation                           -            1              25           30
    Unrecognized prior service cost                              4            5               7            7
    Unrecognized net actuarial (gain) loss                     388          742             123          108
    Minimum pension liability adjustment                       (23)        (497)              -            -
                                                        -----------   ----------      ----------   ----------
    Prepaid (accrued) cost at December 31, net          $      345   $      (79)      $    (335)  $     (317)
        (Note 16B)                                      ========================      =======================
</TABLE>


                                      110
<PAGE>

     The net  prepaid  pension  cost of $345  million at  December  31,  2003 is
     recognized in the  Consolidated  Balance Sheets as prepaid  pension cost of
     $462 million and accrued benefit cost of $117 million, which is included in
     other liabilities and deferred credits. The net accrued pension cost of $79
     million at December  31, 2002 is  recognized  in the  Consolidated  Balance
     Sheets as prepaid  pension cost of $60 million and accrued  benefit cost of
     $139 million,  of which $130 million is included in other  liabilities  and
     deferred  credits and $9 million is included in liabilities of discontinued
     operations.  The defined  benefit  pension plans with  accumulated  benefit
     obligations  in excess of plan  assets had  projected  benefit  obligations
     totaling  $125  million and $1.51  billion at  December  31, 2003 and 2002,
     respectively. Those plans had accumulated benefit obligations totaling $117
     million and $1.35 billion December 31, 2003 and 2002, respectively, no plan
     assets at  December  31,  2003 and plan assets  totaling  $1.22  billion at
     December 31, 2002.  The total  accumulated  benefit  obligation for pension
     plans was $1.61  billion and $1.49  billion at December  31, 2003 and 2002,
     respectively.  The accrued OPEB cost is included in other  liabilities  and
     deferred credits in the Consolidated Balance Sheets.

     A minimum  pension  liability  adjustment  of $23  million,  related to the
     supplementary  defined benefit pension plans,  was recorded at December 31,
     2003.  This  adjustment  is offset  by a  corresponding  pre-tax  amount in
     accumulated other  comprehensive  loss, a component of common stock equity.
     Due to a  combination  of  decreases in the fair value of plan assets and a
     decrease in the  discount  rate used to measure the pension  obligation,  a
     minimum  pension  liability  adjustment  of $497  million  was  recorded at
     December 31, 2002.  This  adjustment  resulted in a charge of $5 million to
     intangible  assets,  included in other  assets and  deferred  debits in the
     accompanying  Consolidated  Balance  Sheets,  a $178  million  charge  to a
     pension-related regulatory liability (See Note 16B) and a pre-tax charge of
     $313 million to accumulated other comprehensive loss, a component of common
     stock equity.

     Reconciliations of the fair value of plan assets are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                             Other Postretirement
                                                    Pension Benefits                Benefits
                                               ------------------------     ----------------------
    (in millions)                                 2003        2002             2003       2002
                                               ------------------------     ----------------------
    Fair value of plan assets January 1          $ 1,364     $ 1,678            $ 52       $ 56
    Actual return on plan assets                     391        (228)             12         (5)
    Disposition of NCNG                              (35)          -               -          -
    Benefit payments                                 (94)        (91)            (24)       (24)
    Employer contributions                             5           5              25         25
                                               ------------------------     ----------------------
    Fair value of plan assets at December 31     $ 1,631     $ 1,364            $ 65       $ 52
                                               ========================     ======================
</TABLE>

     In the table  above,  substantially  all employer  contributions  represent
     benefit payments made directly from Company assets.  The remaining benefits
     payments  were made directly  from plan assets.  The OPEB benefit  payments
     represent the net Company cost after participant contributions. Participant
     contributions represent approximately 20% of gross benefit payments.

     The asset  allocation  for the Company's  plans at the end of 2003 and 2002
     and the target allocation for the plans, by asset category, are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                          Pension Benefits                     Other Postretirement Benefits
                             ------------------------------------------  --------------------------------------------
                                Target        Percentage of Plan Assets    Target        Percentage of Plan Assets at
                             Allocations             at Year End         Allocations               Year End
                             -----------    -------------------------    -----------     ----------------------------
Asset Category                   2004            2003          2002         2004            2003           2002
                             -----------    ----------    ----------     -----------     -----------    ------------
  Equity - domestic               50%             49%           47%          35%             35%            32%
  Equity - international          15%             22%           20%          10%             16%            14%
  Debt - domestic                 15%             11%           15%          45%             37%            41%
  Debt - international            10%             11%           10%           5%              7%             7%
  Other                           10%              7%            8%           5%              5%             6%
                             -----------    ----------    ----------     -----------     -----------    ------------
  Total                          100%            100%          100%         100%            100%           100%
                             ===========    ==========    ==========     ===========     ===========    ============
</TABLE>


                                      111
<PAGE>

     The Company sets target  allocations  among asset  classes to provide broad
     diversification  to protect against large  investment  losses and excessive
     volatility,  while  recognizing the importance of offsetting the impacts of
     benefit  cost  escalation.   In  addition,  the  Company  employs  external
     investment  managers who have  complementary  investment  philosophies  and
     approaches. Tactical shifts (plus or minus 5%) in asset allocation from the
     target  allocations  are made based on the  near-term  view of the risk and
     return tradeoffs of the asset classes.

     In 2004, the Company expects to make $24 million of required  contributions
     directly  to  pension   plan   assets  and  $1  million  of   discretionary
     contributions  directly  to the OPEB  plan  assets.  The  expected  benefit
     payments  for the pension  benefit  plan for 2004 through 2008 and in total
     for 2009-2013, in millions, are approximately $93, $96, $99, $104, $108 and
     $608,  respectively.  The expected  benefit  payments for the OPEB plan for
     2004  through  2008  and  in  total  for   2009-2013,   in  millions,   are
     approximately $22, $24, $26, $28, $30 and $180, respectively.  The expected
     benefit  payments  include benefit  payments  directly from plan assets and
     benefit payments directly from Company assets.  The benefit payment amounts
     reflect the net cost to the Company after any participant contributions.

     The  following  weighted-average  actuarial  assumptions  were  used in the
     calculation of the year-end obligation:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                            Pension Benefits       Other Postretirement Benefits
                                                          --------------------     -----------------------------
                                                             2003       2002            2003          2002
                                                          ---------- ---------     -----------------------------
Discount rate                                                6.30%     6.60%            6.30%         6.60%
Rate of increase in future compensation
  Bargaining                                                 3.50%     3.50%               -             -
  Non-bargaining                                                 -     4.00%               -             -
  Supplementary plans                                        5.00%     4.00%
Initial medical cost trend rate for pre-Medicare benefits        -         -            7.25%         7.50%
Initial medical cost trend rate for post-Medicare benefits       -         -            7.25%         7.50%
Ultimate medical cost trend rate                                 -         -            5.25%         5.25%
Year ultimate medical cost trend rate is achieved                -         -             2009          2009
</TABLE>

     The Company's  primary defined benefit  retirement plan for  non-bargaining
     employees  is a "cash  balance"  pension  plan as defined in EITF Issue No.
     03-4. Therefore,  effective December 31, 2003, the Company began to use the
     traditional  unit  credit  method for  purposes  of  measuring  the benefit
     obligation of this plan and will use that method to measure  future benefit
     costs.  Under the  traditional  unit  credit  method,  no  assumptions  are
     included about future changes in compensation  and the accumulated  benefit
     obligation and projected benefit obligation are the same.

     The  following  weighted-average  actuarial  assumptions  were  used in the
     calculation of the net periodic cost:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                               Pension Benefits           Other Postretirement Benefits
                                                          ----------------------------    -------------------------------
                                                            2003      2002      2001        2003      2002         2001
                                                          ----------------------------    -------------------------------
Discount rate                                               6.60%     7.50%     7.50%      6.60%     7.50%          7.50%
Rate of increase in future compensation
  Bargaining                                                3.50%     3.50%     3.50%          -         -              -
  Non-bargaining and supplementary                          4.00%     4.00%     4.00%          -         -              -
Expected long-term rate of return on plan assets            9.25%     9.25%     9.25%      8.45%     8.20%          8.70%
Initial medical cost trend rate for pre-Medicare benefits       -         -         -      7.50%     7.50%    7.2% - 7.5%
Initial medical cost trend rate for post-Medicare benefits      -         -         -      7.50%     7.50%    6.2% - 7.5%
Ultimate medical cost trend rate                                -         -         -      5.25%     5.00%    5.0% - 5.3%
Year ultimate medical cost trend rate is achieved               -         -         -       2009      2008      2005-2009
</TABLE>

     The expected  long-term  rates of return on plan assets were  determined by
     considering  long-term  historical  returns  for the  plans  and  long-term
     projected  returns  based on the plans'  target asset  allocation.  For all
     pension plan assets and a substantial  portion of OPEB plans assets,  those
     benchmarks  support an expected  long-term  rate of return between 9.5% and
     10.0%.  The Company has chosen to use an expected  long-term  rate of 9.25%
     due to the uncertainties of future returns.

                                      112
<PAGE>

     The medical  cost trend rates were assumed to decrease  gradually  from the
     initial rates to the ultimate rates.  Assuming a 1% increase in the medical
     cost trend rates, the aggregate of the service and interest cost components
     of the net periodic  OPEB cost for 2003 would  increase by $3 million,  and
     the OPEB  obligation at December 31, 2003,  would  increase by $38 million.
     Assuming a 1% decrease in the medical  cost trend rates,  the  aggregate of
     the service and interest cost  components of the net periodic OPEB cost for
     2003 would  decrease by $2 million and the OPEB  obligation at December 31,
     2003, would decrease by $33 million.

     In  December  2003,  the  Medicare   Prescription  Drug,   Improvement  and
     Modernization Act of 2003 (the Act) was signed into law. In accordance with
     guidance  issued by the FASB in FASB Staff Position FAS 106-1,  the Company
     has  elected  to  defer  accounting  for  the  effects  of the  Act  due to
     uncertainties  regarding the effects of the  implementation  of the Act and
     the  accounting  for  certain  provisions  of  the  Act.  Therefore,   OPEB
     information  presented  above  and in the  financial  statements  does  not
     reflect  the effects of the Act.  When  specific  authoritative  accounting
     guidance is issued,  it could  require plan  sponsors to change  previously
     reported  information.  The Company is in the early stages of reviewing the
     Act and determining its potential effects on the Company.

     B. FPC Acquisition

     During 2000,  the Company  completed the  acquisition of FPC. FPC's pension
     and OPEB  liabilities,  assets and net periodic  costs are reflected in the
     above  information as  appropriate.  Certain of FPC's  non-bargaining  unit
     benefit  plans were merged with those of the Company  effective  January 1,
     2002.

     PEF  continues to recover  qualified  plan pension  costs and OPEB costs in
     rates as if the acquisition had not occurred. Accordingly, a portion of the
     accrued  OPEB  cost  reflected  in  the  table  above  has a  corresponding
     regulatory  asset at December 31, 2003 and 2002 (See Note 7A). In addition,
     a portion of the prepaid  pension  cost  reflected in the table above has a
     corresponding  regulatory  liability  (See Note 7A).  Pursuant  to its rate
     treatment,   PEF  recognized   additional   periodic  pension  credits  and
     additional  periodic  OPEB costs,  as indicated  in the net  periodic  cost
     information above.

17.  Risk Management Activities and Derivatives Transactions

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

     A. Commodity Contracts - General

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

     During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related
     to the pricing of contracts that include broad market indices (e.g.,  CPI).
     In particular,  that guidance  discussed  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).  The FASB issued final superseding guidance
     (DIG Issue C20) on this issue  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 required a special transition adjustment as
     of October 1, 2003.

     PEC determined that it had one existing "normal" contract that was affected
     by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
     a pre-tax fair value loss transition adjustment of $38 million ($23 million
     after-tax)  in  the  fourth  quarter  of  2003,  which  was  reported  as a
     cumulative effect of a change in accounting principle. The subject contract
     meets  the DIG  Issue  C20  criteria  for  normal  purchase  or  sale  and,
     therefore,  was designated as a normal  purchase as of October 1, 2003. The
     liability  of $38  million  associated  with the fair  value  loss is being
     amortized to earnings over the term of the related contract.

                                      113
<PAGE>

     B. Commodity Derivatives - Cash Flow Hedges

     The Company held natural gas cash flow hedging  instruments at December 31,
     2003 and 2002.  The objective for holding these  instruments is to manage a
     portion of the market risk  associated  with  fluctuations  in the price of
     natural gas for the Company's  forecasted  sales. At December 31, 2003, the
     Company is  hedging  exposures  to the price  variability  of  natural  gas
     through December 2005.

     The total fair value of these instruments at December 31, 2003 and 2002 was
     a $12 million  and a $10  million  liability  position,  respectively.  The
     ineffective  portion of commodity cash flow hedges was not material in 2003
     and 2002. At December 31, 2003, $7 million of after-tax  deferred losses in
     accumulated   other   comprehensive   income   (OCI)  are  expected  to  be
     reclassified   to  earnings  during  the  next  12  months  as  the  hedged
     transactions occur. Due to the volatility of the commodities  markets,  the
     value  in OCI is  subject  to  change  prior to its  reclassification  into
     earnings.

     C. Commodity Derivatives - Economic Hedges and Trading

     Nonhedging  derivatives,  primarily  electricity and natural gas contracts,
     are entered into for trading  purposes and for economic  hedging  purposes.
     While  management  believes  the  economic  hedges  mitigate  exposures  to
     fluctuations in commodity  prices,  these instruments are not designated as
     hedges for accounting  purposes and are monitored  consistent  with trading
     positions.  The Company  manages open positions  with strict  policies that
     limit its exposure to market risk and require daily reporting to management
     of potential financial exposures. Gains and losses from such contracts were
     not  material  during  2003,  2002 or 2001,  and the  Company  did not have
     material  outstanding  positions in such  contracts at December 31, 2003 or
     2002.

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

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

     The Company uses cash flow hedging  strategies to hedge  variable  interest
     rates on long-term and  short-term  debt and to hedge  interest  rates with
     regard to future fixed-rate debt issuances.  At December 31, 2003 and 2002,
     the Company held  interest rate cash flow hedges,  with a varying  notional
     amount and  maximum of $195  million,  related to variable  rate  long-term
     debt.  At December 31, 2003,  the Company also held interest rate cash flow
     hedges, with a total notional amount of $400 million,  related to projected
     outstanding balances of commercial paper. At December 31, 2002, the Company
     also held an interest rate cash flow hedge,  with a notional  amount of $35
     million,  related to the  issuance of  fixed-rate  debt in early 2003.  The
     total fair value of these  hedges at  December  31,  2003 and 2002 was a $6
     million and a $13 million liability position, respectively. At December 31,
     2003, $7 million of after-tax  deferred losses in OCI, including amounts in
     OCI  related to  terminated  hedges,  are  expected to be  reclassified  to
     earnings during the next 12 months as the hedged  interest  payments occur.
     Due to the  volatility  of interest  rates,  the value in OCI is subject to
     change prior to its reclassification into earnings.

     The Company uses fair value  hedging  strategies  to manage its exposure to
     fixed interest  rates on long-term  debt. At December 31, 2003, the Company
     had open  interest rate fair value hedges with  notional  amounts  totaling
     $850 million and a total fair value of $4 million  liability  position.  At
     December 31,  2002,  the Company had open  interest  rate fair value hedges
     with  notional  amounts  totaling $350 million and a total fair value of $5
     million asset position.  In addition, at December 31, 2003, the Company had
     $23 million of net hedging gains  related to terminated  interest rate fair
     value hedges,  which is reflected in long-term debt and is being  amortized
     over periods ending in 2006 through 2008  coinciding with the maturities of
     the related debt instruments.

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

                                      114
<PAGE>

18.  Related Party Transactions

     Progress  Fuels  sells  coal  to PEF  for an  insignificant  profit.  These
     intercompany   revenues  are  eliminated  in  consolidation;   however,  in
     accordance  with SFAS No. 71,  profits on  intercompany  sales to regulated
     affiliates  are not  eliminated  if the sales price is  reasonable  and the
     future  recovery  of the sales  price  through  the  ratemaking  process is
     probable. The profits for all the years presented were not significant.

     The Company sold NCNG to Piedmont  Natural Gas  Company,  Inc. on September
     30,  2003 (See Note 3A).  Prior to  disposition,  NCNG sold  natural gas to
     affiliates.  During the years ended December 31, 2003, 2002 and 2001, sales
     of natural gas to affiliates  amounted to $11 million,  $20 million and $19
     million,   respectively.   These  revenues  are  included  in  discontinued
     operations on the Consolidated Statements of Income.

     The Company has an outstanding  note due to a related trust.  The principal
     outstanding  on this note was $309  million at December  31, 2003 (See Note
     12A and F).

19.  Financial Information by Business Segment

     The Company  currently  provides  services  through the following  business
     segments: PEC Electric,  PEF, Fuels, CCO, Rail Services and 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.

     PEC Electric and PEF are primarily engaged in the generation, transmission,
     distribution  and sale of electric  energy in  portions of North  Carolina,
     South Carolina and Florida.  These  electric  operations are subject to the
     rules and regulations of the FERC, the NCUC, the SCPSC and the FPSC.  These
     electric   operations  also  distribute  and  sell   electricity  to  other
     utilities, primarily on the east coast of the United States.

     Fuels  operations,  which are located  throughout  the United  States,  are
     involved in natural gas drilling and  production,  coal terminal  services,
     coal mining, synthetic fuel production, fuel transportation and delivery.

     CCO's  operations,  which are located in the  southeastern  United  States,
     include   nonregulated   electric   generation   operations  and  marketing
     activities.

     Rail Services' operations include railcar repair, rail parts reconditioning
     and sales,  railcar  leasing  and sales and scrap  metal  recycling.  These
     activities  include  maintenance and  reconditioning  of salvageable  scrap
     components of railcars,  locomotive  repair and  right-of-way  maintenance.
     Rail  Services'  operations  are located in the United  States,  Canada and
     Mexico.

     The Other segment,  whose operations are in the United States,  is composed
     of other  nonregulated  business  areas  including  telecommunications  and
     energy service operations and other  nonregulated  subsidiaries that do not
     separately meet the disclosure  requirements of SFAS No. 131,  "Disclosures
     about Segments of an Enterprise and Related Information."  Included in this
     segment's  2002 losses are asset  impairments  and certain other  after-tax
     charges related to the  telecommunications  operations of $225 million, the
     2001 results include asset  impairments and other after-tax charges of $153
     million.

     In addition to these reportable  operating segments,  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 (which referred to Fuels and CCO  collectively).  This activity is
     now included in the regulated  utilities  results only.  The  operations of
     NCNG,  previously  reported  in the Other  segment,  were  reclassified  to
     discontinued  operations and therefore are not included in the results from
     continuing   operations  during  the  periods  reported.   For  comparative
     purposes,  the results  have been  restated to align with the new  business
     segment structure.  The profit or loss of the identified  segments plus the
     loss of Corporate  represents  the Company's  total income from  continuing
     operations.

                                      115
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

--------------------------------------------------------------------------------------------------------------
(in millions)                  PEC                                     Rail
                             Electric      PEF     Fuels     CCO     Services(a)    Other    Corporate  Totals
--------------------------------------------------------------------------------------------------------------
Year ended
     December 31, 2003
Revenues
    Unaffiliated              $ 3,589    $ 3,152  $   928   $   170    $  846    $   58     $      -   $ 8,743
    Intersegment                    -          -      346         -         1        15         (362)        -
--------------------------------------------------------------------------------------------------------------
      Total revenues            3,589      3,152    1,274       170       847        73         (362)    8,743
--------------------------------------------------------------------------------------------------------------
Depreciation and
   amortization                   562        307       80        42        20         6           23     1,040
Total interest charges,           194         91       23         4        29        (1)         285       625
    net
Impairment of long-lived
    assets and investments         11          -       17         -         -        10            -        38
Income tax (benefit) (b)          240        147    (415)         8         2        (4)         (87)     (109)
Segment profit (loss)             515        295      235        20        (1)      (17)        (236)      811
Total assets                   10,854      7,306    1,170     1,747       586       304        4,235    26,202
Capital and investment
    expenditures                  470        548      310       360       103        12           22     1,825
--------------------------------------------------------------------------------------------------------------
Year ended
   December 31, 2002
Revenues
    Unaffiliated              $ 3,539    $ 3,062  $   607   $    92    $  714    $   77     $      -   $ 8,091
    Intersegment                    -          -      329         -         5        14         (348)        -
--------------------------------------------------------------------------------------------------------------
      Total revenues            3,539      3,062      936        92       719        91         (348)    8,091
--------------------------------------------------------------------------------------------------------------
Depreciation and
     amortization                 524        295       47        20        20        15           17       938
Total interest charges, net       212        106       24       (12)       33        (5)         275       633
Impairment of
long-lived
     assets and investments         -          -        -         -        59       330            -       389
Income tax (benefit) (b)          237        163    (373)        16       (16)     (129)         (56)     (158)
Segment profit (loss)             513        323      176        27       (42)     (243)        (202)      552
Total assets                   10,139      6,678      934     1,452       529       318        3,668    23,718
Capital and investment
    expenditures                  624        550      172       682         8        53           20     2,109
--------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------
Year ended
   December 31, 2001
Revenues
    Unaffiliated              $ 3,344    $ 3,213  $   559   $    16    $  890    $  107     $      -   $ 8,129
    Intersegment                    -          -      299         -         1        13         (313)        -
--------------------------------------------------------------------------------------------------------------
      Total revenues            3,344      3,213      858        16       891       120         (313)    8,129
--------------------------------------------------------------------------------------------------------------
Depreciation and
   amortization                   522        453       34         4        36        18           83     1,150
Total interest charges, net       241        113       24         -        41        (7)         261       673
Impairment of long-lived
    assets and investments          -          -        -         -         -       207                    207
Income tax (benefit)              264        183     (424)        3        (6)      (57)        (117)     (154)
Segment profit (loss)             468        309      199         4       (12)     (162)        (265)      541
Capital and investment
    expenditures                  824        353       70       195        13        72            -     1,527
--------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts for the year ended December 31, 2001 reflect  cumulative  operating
     results of Rail Services since the acquisition date of November 30, 2000.
(b)  Amounts  for 2003 and 2002  include  income tax benefit  reallocation  from
     holding company to profitable subsidiaries according to an SEC order.

20.  Other Income and Other Expense

     Other  income and expense  includes  interest  income,  gain on the sale of
     investments,  impairment of investments  and other income and expense items
     as  discussed  below.  The  components  of  other,  net  as  shown  on  the
     Consolidated  Statements of Income for the years ended  December 31, are as
     follows:

                                      116
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                                  2003      2002     2001
                                                               ----      ----     ----
Other income
Net financial trading loss                                    $  (2)    $  (2)   $  (1)
Net energy brokered for resale                                    2         2        3
Nonregulated energy and delivery services income                 22        29       29
Contingent value obligation unrealized gain (Note 15)             -        28        -
Investment gains                                                  9        30        3
Income from equity investments                                    9         9        7
AFUDC equity                                                     14         9        9
Other                                                            26        16        5
                                                          -----------------------------
    Total other income                                        $  80     $ 121    $  55
                                                          -----------------------------

Other expense
Nonregulated energy and delivery services expenses               20        29       35
Donations                                                        15        21       23
Investment losses                                                27        18        4
Contingent value obligation unrealized loss (Note 15)             9         -        1
Loss from minority interest                                       3         -        3
Other                                                            31        26       23
                                                          -----------------------------
   Total other expense                                        $ 105     $  94    $  89
                                                          -----------------------------

Other, net                                                    $ (25)    $  27    $ (34)
                                                          =============================
</TABLE>

     Net financial trading loss represents nonasset-backed trades of electricity
     and gas. Nonregulated energy and delivery services include power protection
     services and mass market programs (surge protection, appliance services and
     area light sales) and delivery,  transmission and substation work for other
     utilities.

21.  Commitments and Contingencies

     A. Purchase Obligations

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

     (in millions)
     Contractual Cash Obligations         2004      2005     2006     2007      2008 Thereafter
     -------------------------------------------------------------------------------------------
     Fuel                              $ 1,245   $   628    $ 459    $ 271     $ 151    $ 1,012
     Purchased power                       427       439      450      459       431      4,711
     Construction obligations              112        49        -        -         -          -
     Other purchase obligations             28        11       18       11        16        124
                                     -----------------------------------------------------------
     Total                             $ 1,812   $ 1,127    $ 927    $ 741     $ 598    $ 5,847
                                     ===========================================================
</TABLE>

     Fuel and Purchased Power

     FPC, PEC and PVI have entered into various  long-term  contracts  for coal,
     gas and oil. Payments under these  commitments were $1,207 million,  $1,359
     million and $1,257 million for 2003, 2002 and 2001, respectively. Estimated
     annual payments for firm  commitments of fuel purchases and  transportation
     costs under these contracts are approximately $1,245 million, $628 million,
     $459  million,  $271  million  and  $151  million  for 2004  through  2008,
     respectively, with approximately $1,012 million payable thereafter.

     Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
     between PEC and the North Carolina  Eastern  Municipal  Power Agency (Power
     Agency),  PEC is  obligated  to  purchase a  percentage  of Power  Agency's
     ownership  capacity of, and energy from, the Harris Plant. In 1993, PEC and
     Power Agency  entered into an  agreement to  restructure  portions of their
     contracts  covering  power  supplies and  interests in jointly owned units.
     Under the terms of the 1993 agreement, PEC increased the amount of capacity
     and energy purchased from Power Agency's  ownership  interest in the Harris
     Plant,  and the buyback  period was extended six years  through  2007.  The
     estimated  minimum  annual  payments  for these  purchases,  which  reflect
     capacity  costs,  total   approximately  $36  million.   These  contractual

                                      117
<PAGE>

     purchases  totaled $36 million,  $36 million and $33 million for 2003, 2002
     and 2001,  respectively.  In 1987,  the NCUC  ordered  PEC to  reflect  the
     recovery of the capacity  portion of these costs on a levelized  basis over
     the original 15-year buyback period,  thereby deferring for future recovery
     the difference  between such costs and amounts  collected through rates. At
     December 31, 2002, PEC had deferred  purchased  capacity  costs,  including
     carrying costs accrued on the deferred balances of $17 million. At December
     31, 2003, all previously deferred costs have been expensed.

     PEC has a  long-term  agreement  for the  purchase  of  power  and  related
     transmission  services from Indiana Michigan Power Company's  Rockport Unit
     No. 2  (Rockport).  The  agreement  provides  for the purchase of 250 MW of
     capacity  through 2009 with minimum annual  payments of  approximately  $42
     million,  representing  capital-related  capacity  costs.  Total  purchases
     (including   energy  and  transmission  use  charges)  under  the  Rockport
     agreement  amounted to $66  million,  $59 million and $63 million for 2003,
     2002 and 2001, respectively.

     Effective June 1, 2001, PEC executed a long-term agreement for the purchase
     of power from Skygen Energy LLC's Broad River facility  (Broad River).  The
     agreement  provides  for the purchase of  approximately  500 MW of capacity
     through 2021 with an original minimum annual payment of  approximately  $16
     million, primarily representing  capital-related capacity costs. A separate
     long-term agreement for additional power from Broad River commenced June 1,
     2002. This agreement provided for the additional  purchase of approximately
     300 MW of capacity  through 2022 with an original minimum annual payment of
     approximately  $16 million  representing  capital-related  capacity  costs.
     Total purchases under the Broad River  agreements  amounted to $37 million,
     $38 million and $21 million in 2003, 2002 and 2001, respectively.

     PEF has long-term  contracts for  approximately  474 MW of purchased  power
     with other  utilities,  including a contract with The Southern  Company for
     approximately  414 MW of purchased  power  annually  through 2010.  PEF can
     lower these  purchases to  approximately  200 MW annually with a three-year
     notice.  Total  purchases,  for  both  energy  and  capacity,  under  these
     agreements  amounted to $141  million,  $159  million and $112  million for
     2003,  2002  and  2001,  respectively.  Total  capacity  payments  were $57
     million, $51 million and $54 million for 2003, 2002 and 2001, respectively.
     Minimum  purchases  under  these  contracts,  representing  capital-related
     capacity costs, are approximately $60 million annually through 2009 and $30
     million annually for 2010.

     Both  PEC and PEF have  ongoing  purchased  power  contracts  with  certain
     cogenerators  (qualifying  facilities)  with expiration  dates ranging from
     2004 to  2025.  These  purchased  power  contracts  generally  provide  for
     capacity and energy  payments.  Energy  payments for the PEF  contracts are
     based on actual power taken under these  contracts.  Capacity  payments are
     subject  to  the  qualifying  facilities  (QFs)  meeting  certain  contract
     performance  obligations.   PEF's  total  capacity  purchases  under  these
     contracts amounted to $241 million, $232 million and $226 million for 2003,
     2002 and 2001,  respectively.  Minimum  expected future  capacity  payments
     under these contracts at December 31, 2003 are $257 million,  $269 million,
     $280  million,  $289  million  and  $297  million  for 2004  through  2008,
     respectively,    and   $4,147   million   thereafter.   PEC   has   various
     pay-for-performance contracts with QFs for approximately 400 MW of capacity
     expiring at various  times  through  2009.  Payments for both  capacity and
     energy are  contingent  upon the QFs'  ability to generate.  Payments  made
     under these  contracts were $118 million in 2003,  $145 million in 2002 and
     2001.

     Construction Obligations

     The  Company  has   purchase   obligations   related  to  various   capital
     construction  projects.  Total  payments  under these  contracts  were $202
     million,   $164   million  and  $24  million  for  2003,   2002  and  2001,
     respectively. Future obligations under these contracts are $112 million and
     $49 million for 2004 and 2005, respectively.

     Other Purchase Obligations

     The  Company  has  entered  into  various  other  contractual   obligations
     primarily  related to service  contracts for operational  services  entered
     into by the PESC,  a PVI parts and  services  contract,  and a PEF  service
     agreement  related to the Hines Complex.  Payments  under these  agreements
     were $17  million,  $15 million  and $15  million for 2003,  2002 and 2001,
     respectively. Future obligations under these contracts are $28 million, $11
     million,  $18 million,  $11 million and $16 million for 2004 through  2008,
     respectively, and $124 million thereafter.

                                      118
<PAGE>

     On December 31, 2002, PEC and PVI entered into a contractual  commitment to
     purchase  at least $13 million  and $4  million,  respectively,  of capital
     parts by December 31, 2010.  At December  31, 2003,  no capital  parts have
     been purchased under this contract.

     B. Other Commitments

     The Company has certain future  commitments  related to four synthetic fuel
     facilities purchased that provide for contingent payments (royalties) of up
     to $11 million on  synthetic  fuel sales from each plant  annually  through
     2007. The related  agreements  were amended in December 2001 to require the
     payment of minimum annual  royalties of  approximately  $7 million for each
     plant through 2007. As a result of the  amendment,  the Company  recorded a
     liability  (included  in other  liabilities  and  deferred  credits  on the
     Consolidated Balance Sheets) and a deferred asset (included in other assets
     and  deferred  debits  in  the  Consolidated   Balance  Sheets),   each  of
     approximately  $94 million and $114  million at December 31, 2003 and 2002,
     respectively, representing the minimum amounts due through 2008, discounted
     at 6.05%.  At  December  31, 2003 and 2002,  the  portions of the asset and
     liability  recorded that were classified as current were  approximately $24
     million.  The  deferred  asset will be  amortized  to expense  each year as
     synthetic  fuel sales are made.  The maximum  amounts  payable  under these
     agreements  remain  unchanged.  Actual amounts paid under these  agreements
     were  approximately $2 million in 2003, $51 million in 2002 and $46 million
     in 2001.  Future expected  minimum royalty payments are  approximately  $26
     million for 2004 through 2007 and $7 million for 2008. The large decline in
     amount paid from 2002 to 2003 is due to the Company's  right in the related
     agreements  and their  amendments  that allow the  Company to escrow  those
     payments if certain  conditions in the  agreements are met. The Company has
     exercised  that right and retained 2003 royalty  payments of  approximately
     $48 million pending the  establishment  of the necessary  escrow  accounts.
     Once established, those funds will be placed into escrow.

     C. Leases

     The Company leases office buildings, computer equipment, vehicles, railcars
     and other property and equipment  with various terms and expiration  dates.
     Some rental payments for  transportation  equipment include minimum rentals
     plus contingent rentals based on mileage.  These contingent rentals are not
     significant.  Rent expense under operating leases totaled $55 million,  $57
     million and $63 million for 2003, 2002 and 2001, respectively.

     Assets recorded under capital leases at December 31 consist of:

     (in millions)                          2003           2002
                                        -----------    -----------
     Buildings                             $  30          $  28
     Equipment and other                       3              3
     Less:  Accumulated amortization         (10)           (10)
                                        -----------    -----------
                                           $  23          $  21
                                        ===========    ===========

     Equipment and other  capital lease assets were written down in  conjunction
     with the  impairments  of PTC and Caronet  during the third quarter of 2002
     (See Note 9A).

     Minimum annual rental payments,  excluding executory costs such as property
     taxes, insurance and maintenance,  under long-term  noncancelable leases at
     December 31, 2003 are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                      Capital Leases     Operating Leases
                                                        --------------     ----------------
     2004                                                    $   4            $  38
     2005                                                        4               33
     2006                                                        4               27
     2007                                                        4               22
     2008                                                        3               19
     Thereafter                                                 31              168
                                                        --------------
                                                                           ----------------
                                                             $  50            $ 307
                                                                           ================
     Less amount representing imputed interest                 (20)
                                                        --------------
     Present value of net minimum lease payments
              under capital leases                           $  30
                                                        ==============
</TABLE>


                                      119
<PAGE>

     The Company is also a lessor of land,  buildings,  railcars and other types
     of  properties  it owns  under  operating  leases  with  various  terms and
     expiration  dates. The leased buildings and railcars are depreciated  under
     the same terms as other  buildings  and  railcars  included in  diversified
     business  property.  In 2003, PEC entered into a new operating  lease for a
     building,  which minimum  annual rental  payments are included in the table
     above, and for 2004 through 2008 are approximately $1 million,  $4 million,
     $4  million,  $4 million  and $4  million,  respectively,  with $96 million
     thereafter.  Minimum rentals receivable under noncancelable leases for 2004
     through  2008 are  approximately  $4 million,  $4 million,  $7 million,  $8
     million  and  $14  million,  respectively,   with  $51  million  receivable
     thereafter.  These rental receivable totals exclude all leases attributable
     to Railcar Ltd.  which was sold during the first  quarter of 2004 (See Note
     3B).

     PEC  and  PEF  are  lessors  of  electric  poles,  streetlights  and  other
     facilities.  Rents  received  are  contingent  upon usage and  totaled  $87
     million, $81 million and $78 million for 2003, 2002 and 2001, respectively.

     D. Guarantees

     As a part of normal  business,  Progress  Energy and  certain  subsidiaries
     enter into various agreements providing financial or performance assurances
     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
     subsidiaries on a stand-alone basis,  thereby facilitating the extension of
     sufficient  credit to  accomplish  the  subsidiaries'  intended  commercial
     purposes.  At December 31, 2003, management does not believe conditions are
     likely for  significant  performance  under the  guarantees of  performance
     issued by or on behalf of affiliates discussed herein.

     Guarantees  at December 31,  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 issued on behalf of affiliates
          Guarantees supporting nonregulated portfolio and energy marketing
               activities issued by Progress Energy                              $   332
          Guarantees supporting nuclear decommissioning                              276
          Guarantee supporting power supply agreements                               307
          Standby letters of credit                                                   11
          Surety bonds                                                               117
          Other guarantees                                                             1
     Guarantees issued on behalf of third parties
          Other guarantees                                                            13
                                                                               ---------
        Total                                                                    $ 1,057
                                                                               =========
</TABLE>

     Guarantees   Supporting   Nonregulated   Portfolio  and  Energy   Marketing
     Activities

     Progress  Energy has issued  approximately  $332 million of  guarantees  on
     behalf of Progress  Ventures (the business unit) and its  subsidiaries  for
     obligations  under  tolling  agreements,   transmission   agreements,   gas
     agreements,   construction  agreements,  fuel  procurement  agreements  and
     trading  operations.  Approximately  $103 million of these  guarantees were
     issued during the year to support energy marketing activities. The majority
     of the marketing  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
     current business levels at December 31, 2003, if the Company's ratings were
     to decline below investment  grade, the Company  estimates that it may have
     to deposit cash or provide  letters of credit or other cash  collateral  of
     approximately  $56 million for the benefit of the Company's  counterparties
     to support ongoing operations within a 90-day period.

     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
     guarantees from Progress Energy in the amount of $276 million.

                                      120
<PAGE>

     Guarantees 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 $280 million. In the event
     that Progress Energy's credit ratings fall below investment grade, Progress
     Energy may be required to provide additional security for this guarantee in
     form and amount (not to exceed $280 million) acceptable to Jackson.  During
     the third  quarter of 2003,  PVI  entered  into an  agreement  with  Morgan
     Stanley  Capital  Group Inc. to fulfill  Morgan  Stanley's  obligations  to
     schedule  resources and supply energy to Oglethorpe  Power  Corporation  of
     Georgia   through  March  31,  2005.  The  Company  issued  a  payment  and
     performance  guarantee  to  Morgan  Stanley  related  to the  power  supply
     agreement.  In the event that Progress  Energy's  credit ratings fall below
     investment  grade,  Progress  Energy  estimates that it may have to deposit
     cash or provide letters of credit or other cash collateral of approximately
     $27 million for the benefit of Morgan Stanley at December 31, 2003.

     Standby Letters of Credit

     The  Company  has  issued  $11  million  of  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  December  31,  2003,  the  Company  had $117  million  in surety  bonds
     purchased  primarily for purposes such as providing  workers'  compensation
     coverage,   obtaining   licenses,   permits,   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 of approximately $14 million.
     Included in the $14 million are $13 million of guarantees  issued on behalf
     of third parties of which $3 million is related to  obligations  on leasing
     arrangements  and $10 million is in support of synthetic fuel operations at
     a third-party  plant.  The Company  estimates it will have to perform under
     the guarantees related to the leasing agreements and as such $3 million has
     been  accrued and is  reflected in the  accompanying  Consolidated  Balance
     Sheets.  The  remaining  $1  million  in  affiliate  guarantees  is related
     primarily  to prompt  performance  payments,  lease  obligations  and other
     payments subject to contingencies.

     E. Claims and uncertainties

     1.  The  Company  is  subject  to  federal,  state  and  local  regulations
     addressing hazardous and solid waste management,  air and water quality and
     other environmental matters.

     Hazardous and Solid Waste Management

     Various  organic  materials  associated with the production of manufactured
     gas,  generally  referred to as coal tar, are  regulated  under federal and
     state laws.  The  principal  regulatory  agency that is  responsible  for a
     specific former  manufactured gas plant (MGP) site depends largely upon the
     state in which the site is  located.  There are  several MGP sites to which
     both electric utilities have some connection. In this regard, both electric
     utilities   and  other   potentially   responsible   parties   (PRPs)   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

                                      121


<PAGE>

     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 nine  former MGP sites and other  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.   At  December  31,  2003,
     approximately  $9 million remains in this  centralized  fund with a related
     accrual of $9 million recorded for the associated expenses of environmental
     issues.  PEC  does not  believe  that it can  provide  an  estimate  of the
     reasonably  possible  total  remediation  costs  beyond  what is  currently
     accrued due to the fact that  investigations have not been completed at all
     sites.  This  accrual  has been  recorded  on an  undiscounted  basis.  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 PRPs.  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 any of these MGP
     sites.

     In September  2003, the Company sold NCNG to Piedmont  Natural Gas Company,
     Inc. As part of the sales agreement, the Company retained responsibility to
     remediate five former NCNG MGP sites, all of which also are associated with
     PEC, to state  standards  pursuant to an  Administrative  Order by consent.
     These sites are  anticipated to have  investigation  or  remediation  costs
     associated with them. NCNG had previously accrued  approximately $2 million
     for probable and  reasonably  estimable  remediation  costs at these sites.
     These accruals have been recorded on an undiscounted  basis. At the time of
     the sale,  the  liability  for  these  costs and the  related  accrual  was
     transferred  to PEC. PEC does not believe it can provide an estimate of the
     reasonably  possible  total  remediation  costs beyond the accrual  because
     investigations have not been completed at all sites. Therefore,  PEC cannot
     currently determine the total costs that may be incurred in connection with
     the investigation and/or remediation of all sites.

     PEF At December  31,  2003,  PEF has accrued $18 million for  probable  and
     estimable  costs related to various  environmental  sites. Of this accrual,
     $12 million is for costs  associated  with the  remediation of distribution
     transformers which are more fully discussed below. The remaining $6 million
     is related to two former MGP sites and other sites associated with PEF that
     have  required  or  are   anticipated  to  require   investigation   and/or
     remediation  costs. 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  accrued  approximately  $3  million  for  investigation  and
     remediation associated with distribution transformers and received approval
     from the FPSC for annual recovery of these  environmental costs through the
     Environmental  Cost Recovery Clause (ECRC).  In September 2003, PEF accrued
     an additional  $15 million for similar  environmental  costs as a result of
     increased  sites and estimated  costs per site.  PEF plans to seek approval
     from the FPSC to recover  these costs  through the ECRC.  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 PRPs.  Presently,  PEF cannot  determine the total
     costs that may be incurred in connection with the remediation of all 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 contractual liability to AEP Resources, Inc., associated
     with Inland Marine  Transportation,  is $4 million at December 31, 2003 and
     has accrued such amount. The previous accrual of $10 million was reduced in
     2003 based on a change in estimate.  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 not reasonably probable that additional costs, which cannot be currently
     estimated,  will be incurred related to the  environmental  indemnification
     provision beyond the amount accrued. The Company cannot predict the outcome
     of this matter.

                                      122
<PAGE>

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

     The Company is also currently in the process of assessing  potential  costs
     and exposures at other  environmentally  impaired sites. As the assessments
     are developed and analyzed,  the Company will accrue costs for the sites to
     the extent the costs are probable and can be reasonably estimated.

     Certain historical sites exist that are being addressed  voluntarily by PVI
     and  FPC.  An   immaterial   accrual  has  been   established   to  address
     investigation expenses related to these sites. The Company cannot determine
     the total  costs that may be  incurred  in  connection  with  these  sites.
     According to current information, these future costs are not expected to be
     material to the Company's financial condition or results of operations.

     Rail Services is voluntarily  addressing certain historical waste sites. An
     immaterial  accrual has been  established to address  estimable  costs. The
     Company cannot determine the total costs that may be incurred in connection
     with these sites. According to current information,  these future costs are
     not expected to be material to the Company's financial condition or results
     of operations.

     Air Quality

     There has been and may be further  proposed federal  legislation  requiring
     reductions in air emissions for NOx, SO2, 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.  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  by  these  unaffiliated
     utilities,  ranging from $1.0 billion to $1.4  billion.  A utility that was
     not subject to a civil  enforcement  action  settled its New Source  Review
     issues with the EPA for $300  million.  These  settlement  agreements  have
     generally  called for  expenditures  to be made over extended time periods,
     and some of the  companies  may seek  recovery of the related  cost through
     rate  adjustments  or similar  mechanisms.  The Company  cannot predict the
     outcome of this matter.

     In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
     addressing the regional  transport of ozone (NOx SIP Call).  The EPA's rule
     requires 23  jurisdictions,  including North  Carolina,  South Carolina and
     Georgia,  but not  Florida,  to further  reduce NOx  emissions  in order to
     attain preset state NOx emission  levels by May 31, 2004.  PEC is currently
     installing controls necessary to comply with the rule. Capital expenditures
     to  meet  these   measures  in  North  and  South   Carolina   could  reach
     approximately $370 million, which has not been adjusted for inflation.  The
     Company  has spent  approximately  $258  million  to date  related to these
     expenditures. Increased operation and maintenance costs relating to the NOx
     SIP Call are not  expected  to be  material  to the  Company's  results  of
     operations.   Further  controls  are  anticipated  as  electricity   demand
     increases. The Company cannot predict the outcome of this matter.

     In July 1997,  the EPA issued final  regulations  establishing a new 8-hour
     ozone standard.  In October 1999, the District of Columbia Circuit Court of
     Appeals  ruled  against  the EPA with regard to the  federal  8-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 8-hour ozone standard and is proceeding  with
     the   implementation   process.   North  Carolina  has  promulgated   final
     regulations,  which will  require  PEC to install  NOx  controls  under the
     state's  8-hour  standard.  The costs of those controls are included in the
     $370 million cost estimate above.  However,  further technical analysis and
     rulemaking  may result in a  requirement  for  additional  controls at some
     units. The Company cannot predict the outcome of this matter.

                                      123
<PAGE>

     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 NOx emissions by May 1, 2003. The final rule
     also includes a set of  regulations  that affect NOx 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.  In April  2002,  the EPA
     published a final rule  harmonizing  the dates for the Section 126 rule and
     the NOx SIP Call. The new compliance  date for all affected  sources is now
     May  31,  2004,  rather  than  May 1,  2003.  The EPA  has  approved  North
     Carolina's  NOx SIP Call rule and has indicated it will rescind the Section
     126 rule in a future rulemaking. The Company expects a favorable outcome of
     this matter.

     In June 2002,  legislation  was  enacted in North  Carolina  requiring  the
     state's  electric  utilities  to reduce the  emissions  of NOx and SO2 from
     coal-fired power plants.  Progress Energy expects its capital costs to meet
     these emission targets will be approximately  $813 million by 2013. PEC has
     expended  approximately $30 million of these capital costs through December
     31, 2003. 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 7 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 5-year
     rate freeze period. PEC has recognized $74 million in 2003. Pursuant to the
     law,  PEC entered  into an  agreement  with the state of North  Carolina to
     transfer to the state all future  emissions  allowances  it generates  from
     overcomplying  with the  federal  emission  limits  when  these  units  are
     completed.  The law also requires the state to undertake a study of mercury
     and carbon dioxide  emissions in North Carolina.  Operation and maintenance
     costs will increase due to the additional personnel,  materials and general
     maintenance  associated  with  the  equipment.  Operation  and  maintenance
     expenses are  recoverable  through base rates,  rather than as part of this
     program.   Progress   Energy   cannot   predict   the   future   regulatory
     interpretation, implementation or impact of this law.

     In 2004,  a bill was  introduced  in the  Florida  legislature  that  would
     require significant  reductions in NOx, SO2 and particulate  emissions from
     certain coal, natural gas and oil-fired  generating units owned or operated
     by  investor-owned  electric  utilities,  including  PEF.  The  NOx and SO2
     reductions  would be effective  beginning  with  calendar year 2010 and the
     particulate  reductions  would be effective  beginning  with  calendar year
     2012. Under the proposed legislation, the FPSC would be authorized to allow
     the  utilities  to  recover  the  costs of  compliance  with  the  emission
     reductions  over a period not greater  than seven years  beginning in 2005,
     but the  utilities'  rates may be frozen at 2004  levels  for at least five
     years of the  maximum  recovery  period.  The  Company  cannot  predict the
     outcome of this matter.

     In 1997,  the EPA's  Mercury  Study  Report and Utility  Report to Congress
     conveyed  that mercury is not a risk to the average  American and expressed
     uncertainty  about whether  reductions in mercury emissions from coal-fired
     power plants would reduce human exposure.  Nevertheless, the EPA determined
     in 2000 that regulation of mercury  emissions from coal-fired  power plants
     was  appropriate.  In 2003, the EPA proposed two alternative  control plans
     that would limit mercury emissions from coal-fired power plants. The first,
     a Maximum Achievable Control Technology (MACT) standard applicable to every
     coal-fired plant,  would require compliance in 2008. The second, a national
     mercury  cap and  trade  program,  would  require  limits  to be met in two
     phases,  2010 and 2018.  The mercury  rule is  expected to become  final in
     December  2004.  Achieving  compliance  with either  proposal could involve
     significant  capital  costs  which  could  be  material  to  the  Company's
     consolidated  financial  position  or results of  operations.  The  Company
     cannot predict the outcome of this matter.

     In  conjunction  with the proposed  mercury  rule,  the EPA proposed a MACT
     standard to regulate nickel  emissions from residual  oil-fired  units. The
     agency  estimates the proposal  will reduce  national  nickel  emissions to
     approximately  103 tons.  The rule is expected to become  final in December
     2004.

     In December 2003, the EPA released its proposed Interstate Air Quality Rule
     (commonly known as the Fine Particulate  Transport Rule and/or the Regional
     Transport Rule). The EPA's proposal  requires 28  jurisdictions,  including
     North Carolina, South Carolina,  Georgia and Florida, to further reduce NOx
     and SO2  emissions in order to attain  preset  state NOx and SO2  emissions
     levels (which have not yet been determined). The rule is expected to become
     final in 2004. The  installation  of controls  necessary to comply with the
     rule could involve significant capital costs.

                                      124
<PAGE>

     Water Quality

     As a result of the operation of certain control equipment needed to address
     the air quality  issues  outlined  above,  new  wastewater  streams will be
     generated at the applicable facilities. Integration of these new wastewater
     streams  into the existing  wastewater  treatment  processes  may result in
     permitting,  construction and treatment  challenges to PEC in the immediate
     and extended future.

     After  many  years  of  litigation  and  settlement  negotiations  the  EPA
     published  regulations in February 2004 for the  implementation  of Section
     316(b) of the Clean  Water  Act.  The  purpose of these  regulations  is to
     minimize  adverse  environmental  impacts  caused by cooling  water  intake
     structures  and  intake   systems.   Over  the  next  several  years  these
     regulations will impact the larger base load generation  facilities and may
     require the  facilities  to mitigate  the effects to aquatic  organisms  by
     constructing   intake   modifications  or  undertaking   other  restorative
     activities.  Substantial costs could be incurred by the facilities in order
     to comply with the new  regulation.  The Company cannot predict the outcome
     and impacts to the facilities at this time.

     The EPA has published for comment a draft  Environmental  Impact  Statement
     (EIS) for  surface  coal  mining  (sometimes  referred  to as  "mountaintop
     mining") and valley fills in the  Appalachian  coal region,  where Progress
     Fuels  currently  operates  a surface  mine and may  operate  others in the
     future.  The final EIS,  when  published,  may affect  regulations  for the
     permitting  of  mines  and  the  cost  of  compliance  with   environmental
     regulations. Regulatory changes for mining may also affect the cost of fuel
     for the PEC and PEF  coal-fueled  electric-generating  plants.  The Company
     cannot predict the outcome of this matter.

     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  the  Company's
     consolidated  financial  position or results of  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.

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

     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.

                                      125
<PAGE>

     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 the
     DOE.

     On January 14, 2004,  PEC and PEF filed a complaint  with the United States
     Court of Federal  Claims against the DOE claiming that the DOE breached the
     Standard  Contract for Disposal of Spent  Nuclear Fuel by failing to accept
     spent  nuclear fuel from various  Progress  Energy  facilities on or before
     January  31,  1998.  Damages due to DOE's  breach  will likely  exceed $100
     million.  Similar  suits  have  been  initiated  by over  two  dozen  other
     utilities.

     In July 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. On November
     5, 2003,  Congressional  negotiators  approved $580 million for fiscal year
     2004 for the Yucca  Mountain  project,  $123 million more than the previous
     year. PEC and PEF cannot predict the outcome of this matter.

     With certain modifications and additional approval by the NRC including the
     installation  of onsite  dry  storage  facilities  at  Robinson  (2005) and
     Brunswick  (2008),  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. PEF currently is storing spent nuclear fuel
     onsite in spent fuel  pools.  PEF is seeking  renewal  of the  current  CR3
     operating  license.  CR3 has sufficient  storage capacity in place for fuel
     consumed  through the end of the expiration of the current license in 2016.
     If PEF receives approval on its CR3 operating  license renewal,  additional
     dry storage may be necessary.

     3. 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.  SRS has  amended  its claims and  asserted  new claims
     against the District and other parties, including a former SRS employee and
     a former District employee.

     On March 13, 2003,  the City Attorney and the District  filed new claims 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 filing states that the City and
     the District  seek "more than $300 million in damages and  penalties."  PEC
     was added as a cross-defendant later in 2003.

     The Company,  SRS, Progress Energy Solutions,  Inc. and PEC all have denied
     the District's  allegations and  cross-claims.  Discovery is in progress in
     the matter.  The case has been  assigned  to a judge  under the  Sacramento
     County  superior  court's  case  management  rules,  and the  judge and the
     parties  have been  conferring  on  scheduling  and  processes to narrow or
     resolve issues, if possible,  and to get the case ready for trial. No trial
     date has  been  set.  SRS and the  Company  are  vigorously  defending  and
     litigating  all of these claims.  In November  2003,  PEC filed a motion to
     dismiss the plaintiffs' first amended complaint. The Company cannot predict
     the  outcome  of this  matter,  but  will  vigorously  defend  against  the
     allegations.

                                      126
<PAGE>

     4. On August 21,  2003,  PEC was served as a  co-defendant  in a  purported
     class action  lawsuit  styled as Collins v. Duke Energy  Corporation et al,
     Civil Action No.  03CP404050,  in South Carolina's  Circuit Court of Common
     Pleas  for  the  Fifth  Judicial  Circuit.  PEC is one  of  three  electric
     utilities operating in South Carolina named in the suit. The plaintiffs are
     seeking damages for the alleged improper use of electric easements but have
     not asserted a dollar amount for their damage claims. The complaint alleges
     that the licensing of  attachments on electric  utility  poles,  towers and
     other structures to nonutility third parties or telecommunication companies
     for other than the  electric  utilities'  internal  use along the  electric
     right-of-way constitutes a trespass.

     On  September  19,  2003,  PEC filed a motion to dismiss  all counts of the
     complaint on substantive  and procedural  grounds.  On October 6, 2003, the
     plaintiffs  filed a motion  to amend  their  complaint.  PEC  believes  the
     amended  complaint  asserts  the  same  factual  allegations  as are in the
     original  complaint and also seeks money damages and injunctive relief. The
     court has not yet held any  hearings or made any rulings in this case.  PEC
     cannot predict the outcome of this matter,  but  vigorously  defend against
     the allegations.

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

                                      127
<PAGE>

INDEPENDENT AUDITORS' REPORT


TO THE BOARD OF DIRECTORS  AND  SHAREHOLDERS  OF CAROLINA  POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:

We have audited the accompanying consolidated balance sheets of Carolina Power &
Light Company d/b/a Progress Energy Carolinas,  Inc. and its subsidiaries  (PEC)
at December 31, 2003 and 2002, and the related consolidated statements of income
and  comprehensive  income,  retained  earnings,  and cash flows for each of the
three years in the period ended December 31, 2003.  These  financial  statements
are the responsibility of PEC's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our opinion,  such consolidated  financial  statements present fairly, in all
material respects,  the financial position of PEC at December 31, 2003 and 2002,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2003, in conformity with accounting  principles
generally accepted in the United States of America.

As discussed in Notes 3F and 12A to the consolidated  financial  statements,  in
2003, the Company adopted  Statement of Financial  Accounting  Standards No. 143
and Derivative Implementation Group Issue C20.



/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004



                                      128
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME
                                                                       Years ended December 31
(In millions)                                                        2003        2002        2001
--------------------------------------------------------------------------------------------------
Operating Revenues
   Electric                                                       $ 3,589     $ 3,539     $ 3,344
   Diversified business                                                11          15          16
--------------------------------------------------------------------------------------------------
      Total Operating Revenues                                      3,600       3,554       3,360
--------------------------------------------------------------------------------------------------
Operating Expenses
   Fuel used in electric generation                                   825         752         638
   Purchased power                                                    296         347         354
   Operation and maintenance                                          782         802         711
   Depreciation and amortization                                      562         524         522
   Taxes other than on income                                         162         158         150
   Diversified business                                                 4          15          10
   Impairment of diversified business long-lived assets                 -         101           -
--------------------------------------------------------------------------------------------------
        Total Operating Expenses                                    2,631       2,699       2,385
--------------------------------------------------------------------------------------------------
Operating Income                                                      969         855         975
--------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                      6           7          14
   Impairment of investments                                          (21)        (25)       (157)
   Other, net                                                         (11)         13          (4)
--------------------------------------------------------------------------------------------------
        Total Other Expense                                           (26)         (5)       (147)
--------------------------------------------------------------------------------------------------
Interest Charges
   Interest charges                                                   196         217         257
   Allowance for borrowed funds used during construction               (2)         (5)        (16)
--------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                   194         212         241
--------------------------------------------------------------------------------------------------
Income before Income Tax and Cumulative Effect of Change in
  Accounting Principles                                               749         638         587
Income Tax Expense                                                    244         207         223
--------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Change in Accounting               505         431         364
  Principles
Cumulative Effect of Change in Accounting Principles, Net of Tax      (23)          -           -
--------------------------------------------------------------------------------------------------
Net Income                                                            482         431         364
Preferred Stock Dividend Requirement                                    3           3           3
--------------------------------------------------------------------------------------------------
Earnings for Common Stock                                         $   479     $   428     $   361
--------------------------------------------------------------------------------------------------

Comprehensive Income, Net of Tax:
   Net Income                                                     $   482     $   431     $   364
   SFAS No. 133 transition adjustment (net of tax)                      -           -          (1)
   Change in net unrealized losses on cash flow hedges (net of
       tax of ($1), $9 and $8, respectively)                            3         (14)        (12)
   Reclassification adjustment for amounts included in net
       income (net of tax of $0, $8 and $4, respectively)               1          11           6
   Minimum pension liability adjustment (net of tax of $(47)
       and $47, respectively)                                          72         (73)          -
--------------------------------------------------------------------------------------------------
Comprehensive Income                                              $   558     $   355     $   357
--------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

                                      129
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED BALANCE SHEETS
(In millions)                                                                   December 31
ASSETS                                                                     2003              2002
--------------------------------------------------------------------------------------------------
Utility Plant
  Utility plant in service                                             $ 13,331          $ 12,680
  Accumulated depreciation                                               (5,280)           (4,869)
--------------------------------------------------------------------------------------------------
        Utility plant in service, net                                     8,051             7,811
  Held for future use                                                         5                 7
  Construction work in progress                                             306               326
  Nuclear fuel, net of amortization                                         159               177
--------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                          8,521             8,321
--------------------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                                 238                18
  Accounts receivable                                                       265               301
  Unbilled accounts receivable                                              145               151
  Receivables from affiliated companies                                      27                37
  Notes receivable from affiliated companies                                  -                50
  Taxes receivable                                                           19                55
  Inventory                                                                 348               343
  Deferred fuel cost                                                        113               146
  Prepayments and other current assets                                       63                45
--------------------------------------------------------------------------------------------------
        Total Current Assets                                              1,218             1,146
--------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                                         477               206
  Nuclear decommissioning trust funds                                       505               423
  Miscellaneous other property and investments                              169               219
  Other assets and deferred debits                                          118                90
--------------------------------------------------------------------------------------------------
        Total Deferred Debits and Other Assets                            1,269               938
--------------------------------------------------------------------------------------------------
           Total Assets                                                $ 11,008          $ 10,405
--------------------------------------------------------------------------------------------------
Capitalization and Liabilities
--------------------------------------------------------------------------------------------------
Common Stock Equity
--------------------------------------------------------------------------------------------------
  Common stock without par value, authorized 200 million shares,
     160 million shares issued and outstanding at December 31          $  1,953          $  1,930
  Unearned ESOP common stock                                                (89)             (102)
  Accumulated other comprehensive loss                                       (7)              (83)
  Retained earnings                                                       1,380             1,344
--------------------------------------------------------------------------------------------------
        Total Common Stock Equity                                         3,237             3,089
  Preferred Stock - Not Subject to Mandatory Redemption                      59                59
  Long-Term Debt                                                          3,086             3,048
--------------------------------------------------------------------------------------------------
        Total Capitalization                                              6,382             6,196
--------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                         300                 -
  Accounts payable                                                          188               258
  Payables to affiliated companies                                          136                99
  Notes payable to affiliated companies                                      25                 -
  Interest accrued                                                           64                59
  Short-term obligations                                                      4               438
  Current portion of accumulated deferred income taxes                        -                66
  Other current liabilities                                                 166                92
--------------------------------------------------------------------------------------------------
        Total Current Liabilities                                           883             1,012
--------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Accumulated deferred income taxes                                       1,125             1,105
  Accumulated deferred investment tax credits                               148               159
  Regulatory liabilities                                                  1,175                 8
  Cost of removal                                                             -             1,488
  Asset retirement obligations                                              932                 -
  Other liabilities and deferred credits                                    363               437
--------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                      3,743             3,197
--------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 16)
--------------------------------------------------------------------------------------------------
            Total Capitalization and Liabilities                       $ 11,008          $ 10,405
--------------------------------------------------------------------------------------------------
</TABLE>

    See Notes to Consolidated Financial Statements.

                                      130
<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

                                                                                      Years ended December 31
(In millions)                                                                      2003         2002          2001
-------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                      $   482      $   431       $   364
Adjustments to reconcile net income to net cash provided by operating
activities:
   Impairment of long-lived assets and investments                                   21          126           157
   Depreciation and amortization                                                    660          631           616
   Cumulative effect of change in accounting principles                              23            -             -
   Deferred income taxes                                                            (68)         (82)         (150)
   Investment tax credit                                                            (10)         (12)          (15)
   Deferred fuel cost (credit)                                                       33          (15)          (12)
   Cash provided (used) by changes in operating assets and liabilities:
      Accounts receivable                                                            41          (21)          304
      Inventories                                                                     4           10          (140)
      Prepayments and other current assets                                           21          (15)           22
      Accounts payable                                                              (32)          20          (261)
      Other current liabilities                                                      56           (2)           53
      Other                                                                          27           32            47
-------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                1,258        1,103           985
-------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions                                                           (470)        (624)         (824)
Proceeds from sale of assets and investments                                         26          244             -
Diversified business property additions and acquisitions                             (1)         (12)          (13)
Nuclear fuel additions                                                              (66)         (81)          (73)
Net contributions to nuclear decommissioning trust                                  (31)         (31)          (31)
Other investing activities                                                            1          (17)          (32)
-------------------------------------------------------------------------------------------------------------------
         Net Cash Used in Investing Activities                                     (541)        (521)         (973)
-------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt                                            588          542           296
Net increase (decrease) in short-term obligations                                  (437)         177          (226)
Net change in intercompany notes                                                     74         (97)           188
Retirement of long-term debt                                                       (276)        (807)         (135)
Equity contribution from parent                                                       -            -           115
Dividends paid to parent                                                           (443)        (397)         (256)
Dividends paid on preferred stock                                                    (3)          (3)           (3)
-------------------------------------------------------------------------------------------------------------------
         Net Cash Used in Financing Activities                                     (497)        (585)          (21)
-------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                220           (3)           (9)
-------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year                                       18           21            30
-------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                        $   238      $    18       $    21
-------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                $   184      $   208       $   230
                            income taxes (net of refunds)                       $   296      $   319       $   395
</TABLE>

Noncash Investing and Financing Activities
o    In January 2001, PEC transferred certain assets, through a noncash dividend
     to Progress Energy in the amount of $18 million, to Progress Energy Service
     Company, LLC.

See  Notes to Consolidated Financial Statements.

                                      131
<PAGE>

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                Years ended December 31
(In millions)                                               2003         2002            2001
----------------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year                    $ 1,344      $ 1,313        $ 1,226
Net income                                                    482          431            364
Preferred stock dividends at stated rates                      (3)          (3)            (3)
Common stock dividends                                       (443)        (397)          (274)
----------------------------------------------------------------------------------------------
Retained Earnings at End of Year                          $ 1,380      $ 1,344        $ 1,313
----------------------------------------------------------------------------------------------


    CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

(In millions)                                First Quarter    Second Quarter     Third Quarter     Fourth Quarter
-----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues                              $ 929             $ 819          $ 1,012               $840
Operating income                                  256               184              294                235
Income before cumulative effect of
   change in accounting principles                135                89              158                123
Net income                                        135                89              158                100
-----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues                              $ 815             $ 838          $ 1,049              $ 852
Operating income                                  193               210              240                212
Net income                                         85               131               94                121
</TABLE>

o    In the opinion of management,  all adjustments  necessary to fairly present
     amounts shown for interim periods have been made. Results of operations for
     an interim period may not give a true indication of results for the year.
o    Fourth quarter 2003 includes  impairment of investments of $21 million ($13
     million after-tax) (See Note 6).
o    Fourth  quarter 2003 includes a cumulative  effect for DIG Issue C20 of $38
     million ($23 million after-tax) (See Note 12).
o    Third quarter 2002 includes impairment and other charges related to Caronet
     and Interpath Communications, Inc. of $133 million ($87 million, after-tax)
     (See Note 6).

See Notes to Consolidated Financial Statements.

                                      132
<PAGE>

CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   Organization and Summary of Significant Accounting Policies

     A. Organization

     Carolina  Power & Light  Company  (CP&L)  is a public  service  corporation
     primarily engaged in the generation, transmission, distribution and sale of
     electricity  in portions of North  Carolina and South  Carolina.  Effective
     January 1, 2003,  CP&L began doing business under the assumed name Progress
     Energy Carolinas, Inc (PEC). The legal name has not changed and there is no
     restructuring  of  any  kind  related  to  the  name  change.  Through  its
     wholly-owned subsidiaries, PEC is involved in several nonregulated business
     activities,  the  most  significant  of  which  was its  telecommunications
     operation.  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.

     In  December  2003,  Progress  Telecommunications   Corporation  (PTC)  and
     Caronet,  Inc.  (Caronet),  both  indirectly  wholly-owned  subsidiaries of
     Progress  Energy,  and EPIK  Communications,  Inc.  (EPIK),  a wholly-owned
     subsidiary of Odyssey Telecorp, Inc. (Odyssey),  contributed  substantially
     all of  their  assets  and  transferred  certain  liabilities  to  Progress
     Telecom,  LLC (PTC LLC), a subsidiary  of PTC.  Subsequently,  the stock of
     Caronet  was sold to an  affiliate  of  Odyssey  for $2 million in cash and
     Caronet became an indirect  wholly-owned  subsidiary of Odyssey. No gain or
     loss was recognized on this transaction.

     B. Basis of Presentation

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

     Unconsolidated  investments  in  companies  over  which  PEC  does not have
     control,  but has the  ability to exercise  influence  over  operating  and
     financial  policies  (generally,  20% - 50%  ownership),  are accounted for
     under the equity  method of  accounting.  Certain  investments  in debt and
     equity  securities that have readily  determinable  market values,  and for
     which  PEC  does not  have  control,  are  accounted  for at fair  value in
     accordance with SFAS No. 115  "Accounting  for Certain  Investments in Debt
     and Equity  Securities."  Other investments are stated principally at cost.
     These equity and cost  investments,  which total  approximately $35 million
     and $95 million at December 31, 2003 and 2002,  respectively,  are included
     as  miscellaneous  property and  investments  in the  Consolidated  Balance
     Sheets.  The primary  component  of this  balance is PEC's  investments  in
     affordable  housing of $21 million and $63 million at December 31, 2003 and
     2002,  respectively.  This decrease is primarily due to the sale of certain
     PEC  investments  in the third quarter of 2003. For a discussion of how new
     FASB  interpretations  will affect these affordable housing investments see
     Note 2.

     Certain amounts for 2002 and 2001 have been  reclassified to conform to the
     2003 presentation.

     C. Significant Accounting Policies

     Use of Estimates and Assumptions
     In  preparing  consolidated  financial  statements  that conform with GAAP,
     management  must make  estimates and  assumptions  that affect the reported
     amounts of assets and  liabilities,  disclosure  of  contingent  assets and
     liabilities  at the  date  of the  consolidated  financial  statements  and
     amounts of revenues and expenses  reflected  during the  reporting  period.
     Actual results could differ from those estimates.

                                      133
<PAGE>

     Revenue Recognition
     PEC  recognizes   electric  utility  revenue  as  service  is  rendered  to
     customers.  Operating  revenues include unbilled  electric utility revenues
     earned  when  service has been  delivered  but not billed by the end of the
     accounting  period.   Revenues  related  to  Caronet  for  the  design  and
     construction of wireless  infrastructure were recognized upon completion of
     services for each completed phase of design and construction.

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

     Excise Taxes
     PEC collects  from  customers  certain  excise taxes levied by the state or
     local  government  upon the  customer.  PEC  accounts for excise taxes on a
     gross basis.  For the years ended December 31, 2003,  2002 and 2001,  gross
     receipts  tax and other  excise taxes of  approximately  $81  million,  $79
     million and $77 million,  respectively, are included in taxes other than on
     income on the Consolidated  Statements of Income and Comprehensive  Income.
     These approximate amounts also are included in electric operating revenues.

     Income Taxes
     Progress Energy and its affiliates  file a consolidated  federal income tax
     return. The consolidated  income tax of Progress Energy is allocated to PEC
     in accordance with the Inter-company  Income Tax Allocation  Agreement (Tax
     Agreement).  The Tax  Agreement  provides  an  allocation  that  recognizes
     positive and negative  corporate taxable income. The Tax Agreement provides
     for an equitable method of apportioning the carry over of uncompensated tax
     benefits.  Progress Energy tax benefits not related to acquisition interest
     expense are  allocated to  profitable  subsidiaries,  beginning in 2002, in
     accordance with a PUHCA order.  Income taxes are provided as if PEC filed a
     separate return.

     Deferred income taxes have been provided for temporary  differences.  These
     occur when there are differences  between the book and tax carrying amounts
     of assets and  liabilities.  Investment  tax credits  related to  regulated
     operations  have been deferred and are being  amortized  over the estimated
     service life of the related properties (See Note 10).

     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.  The exercise price at which options
     are granted by the Company  equals the market price at the grant date,  and
     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" (SFAS No. 148),  the  estimated  fair
     value of the  Company's  stock  options is  amortized  to expense  over the
     options' vesting period.  The following table illustrates the effect on net
     income if the fair value  method had been  applied to all  outstanding  and
     unvested awards in each period.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                                    2003       2002      2001
                                                                    --------   --------  ---------
     Net income, as reported                                         $ 482      $ 431     $ 364
     Deduct:  Total stock option expense determined under fair
          value method for all awards, net of related tax effects        6          5         1
                                                                    --------   --------  ---------
     Pro forma net income                                            $ 476      $ 426     $ 363
                                                                    ========   ========  =========
</TABLE>

     Utility Plant
     Utility  plant in service  is stated at  historical  cost less  accumulated
     depreciation.  PEC  capitalizes all  construction-related  direct labor and
     material costs of units of property as well as indirect construction costs.
     The cost of renewals and betterments is also  capitalized.  Maintenance and
     repairs of property,  and  replacements and renewals of items determined to
     be less than  units of  property,  are  charged to  maintenance  expense as
     incurred.  The cost of units of property replaced or retired, less salvage,
     is charged to  accumulated  depreciation.  Removal or  disposal  costs were
     charged to regulatory  liabilities in 2003 and cost of removal in 2002. PEC
     follows  the  guidance in SFAS No. 143,  "Accounting  for Asset  Retirement
     Obligations,"  to  account  for  legal  obligations   associated  with  the
     retirement of certain tangible long-lived assets.

                                      134
<PAGE>

     Depreciation and Amortization - Utility Plant
     For financial reporting purposes, substantially all depreciation of utility
     plant other than nuclear fuel is computed on the straight-line method based
     on the  estimated  remaining  useful  life of the  property,  adjusted  for
     estimated  salvage (See Note 3A). The North Carolina  Utilities  Commission
     (NCUC) and the Public Service Commission of South Carolina (SCPSC) can also
     grant approval to accelerate or reduce  depreciation  and  amortization  of
     utility assets (See Note 5B).

     Amortization  of nuclear fuel costs,  including  disposal costs  associated
     with  obligations  to  the  U.S.  Department  of  Energy  (DOE)  and  costs
     associated  with  obligations  to  the  DOE  for  the  decommissioning  and
     decontamination  of  enrichment  facilities,  is computed  primarily on the
     units-of-production  method and charged to fuel used in electric generation
     in the  accompanying  Consolidated  Statements of Income and  Comprehensive
     Income.   In   PEC's   retail   jurisdictions,   provisions   for   nuclear
     decommissioning  costs are approved by the NCUC and the SCPSC and are based
     on  site-specific  estimates  that  include  the costs for  removal  of all
     radioactive   and  other   structures   at  the  site.   In  the  wholesale
     jurisdictions,   the  provisions  for  nuclear  decommissioning  costs  are
     approved by the Federal Energy Regulatory Commission (FERC).

     Cash and Cash Equivalents
     PEC considers  cash and cash  equivalents to include  unrestricted  cash on
     hand, cash in banks and temporary  investments purchased with a maturity of
     three months or less.

     Allowance for Doubtful Accounts
     PEC maintains an allowance for doubtful accounts receivable,  which totaled
     approximately  $13 million  and $11 million at December  31, 2003 and 2002,
     respectively,  and is included in accounts  receivable on the  Consolidated
     Balance Sheets.

     Inventory
     PEC accounts for inventory using the average-cost method.

     Regulatory Assets and Liabilities
     PEC's  regulated  operations  are  subject to SFAS No. 71,  which  allows a
     regulated  company  to record  costs that have been or are  expected  to be
     allowed in the ratemaking  process in a period different from the period in
     which the costs would be charged to expense by a  nonregulated  enterprise.
     Accordingly,  PEC  records  assets and  liabilities  that  result  from the
     regulated  ratemaking  process  that would not be  recorded  under GAAP for
     nonregulated  entities.  These regulatory assets and liabilities  represent
     expenses  deferred for future  recovery from customers or obligations to be
     refunded to customers  and are  primarily  classified  in the  accompanying
     Consolidated Balance Sheets as regulatory assets and regulatory liabilities
     (See Note 5A).

     Diversified Business Property
     Diversified   business   property  is  stated  at  cost  less   accumulated
     depreciation.  If an impairment  loss is  recognized on an asset,  the fair
     value becomes its new cost basis. The costs of renewals and betterments are
     capitalized.  The cost of repairs and  maintenance is charged to expense as
     incurred.  Depreciation  is  computed  on a  straight-line  basis using the
     estimated useful lives disclosed in Note 3B.

     Unamortized Debt Premiums, Discounts and Expenses
     Long-term  debt premiums,  discounts and issuance  expenses for the utility
     are  amortized  over the life of the related  debt using the  straight-line
     method. Any expenses or call premiums  associated with the reacquisition of
     debt  obligations  by the utility are amortized  over the remaining life of
     the original debt using the straight-line method consistent with ratemaking
     treatment.

     Derivatives
     Effective  January 1, 2001,  PEC  adopted  SFAS No.  133,  "Accounting  for
     Derivative  Instruments and Hedging  Activities" (SFAS No. 133), as amended
     by SFAS No. 138 and SFAS No. 149.  SFAS No.  133,  as amended,  establishes
     accounting and reporting  standards for derivative  instruments,  including
     certain derivative instruments embedded in other contracts, and for hedging
     activities.  SFAS No. 133 requires that an entity recognize all derivatives
     as assets or liabilities in the balance sheet and measure those instruments
     at fair value. During 2003, the FASB reconsidered an interpretation of SFAS
     No. 133. See Note 12 for the effect of the  interpretation  and  additional
     information   regarding   risk   management   activities   and   derivative
     transactions.

                                      135
<PAGE>

     Environmental
     The Company accrues environmental remediation liabilities when the criteria
     for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
     expenditures  are  expensed as incurred or  capitalized  depending on their
     future economic benefit.  Expenditures that relate to an existing condition
     caused by past  operations  and that have no future  economic  benefits are
     expensed.  Accruals for  estimated  losses from  environmental  remediation
     obligations  generally  are  recognized  no later  than  completion  of the
     remedial  feasibility  study.  Such  accruals  are  adjusted as  additional
     information develops or circumstances  change. Costs of future expenditures
     for  environmental  remediation  obligations  are not  discounted  to their
     present value.  Recoveries of  environmental  remediation  costs from other
     parties are  recognized  when their  receipt is deemed  probable  (See Note
     16D).

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

     PEC reviews its  investments  to evaluate  whether or not a decline in fair
     value below the  carrying  value is an  other-than-temporary  decline.  PEC
     considers various factors,  such as the investee's cash position,  earnings
     and revenue outlook, liquidity and management's ability to raise capital in
     determining whether the decline is other-than-temporary.  If PEC determines
     that  an   other-than-temporary   decline   exists  in  the  value  of  its
     investments,  it is PEC's policy to write-down  these  investments  to fair
     value. See Note 6 for a discussion of impairment  evaluations performed and
     charges taken.

     Subsidiary Stock Transactions
     Gains  and  losses  realized  as a result of  common  stock  sales by PEC's
     subsidiaries  are  recorded in the  Consolidated  Statements  of Income and
     Comprehensive  Income,  except for any  transactions  that must be credited
     directly  to  equity  in  accordance  with the  provisions  of SAB No.  51,
     "Accounting for Sales of Stock by a Subsidiary."

2.   New Accounting Standards

     SFAS  No.  150,   "Accounting  for  Certain   Financial   Instruments  with
     Characteristics  of Both Liabilities and Equity"
     In May 2003, the Financial  Accounting  Standards  Board (FASB) issued SFAS
     No. 150, "Accounting for Certain Financial Instruments with Characteristics
     of Both  Liabilities and Equity." The adoption of SFAS No. 150 did not have
     an impact on PEC's financial position or results of operations.

     EITF Issue No. 03-04,  "Accounting for `Cash Balance' Pension Plans"
     In May 2003,  the Emerging  Issues Task Force (EITF)  reached  consensus in
     EITF Issue No. 03-04,  "Accounting for `Cash Balance'  Pension Plans" (EITF
     03-04),  to  specifically  address the  accounting for certain cash balance
     pension plans.  The consensus  reached in EITF 03-04 requires  certain cash
     balance  pension plans to be accounted for as defined  benefit  plans.  For
     cash balance plans described in EITF 03-04, 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 plan as a defined benefit plan; however,  PEC was required to adopt
     the  measurement  provisions  of EITF  03-04  at its  cash  balance  plan's
     measurement  date of December 31, 2003. Any  differences in the measurement
     of the  obligations  as a result of applying  EITF 03-04 were reported as a
     component of actuarial gain or loss. The on-going  effects of this standard
     are  dependent  on other  factors  that also  affect the  determination  of
     actuarial  gains and losses and the subsequent  amortization  of such gains
     and losses.  However,  the adoption of EITF 03-04 is not expected to have a
     material effect on PEC's results of operations or financial position.

                                      136
<PAGE>

     SFAS No. 149,  "Amendment of Statement 133 on  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. Interpretations and
     implementation  issues with regard to SFAS No. 149 continue to evolve.  The
     statement  had no  significant  impact on PEC's  accounting  for  contracts
     entered into  subsequent to the  statement's  effective date (See Note 12).
     Future  effects,  if any,  on PEC's  results of  operations  and  financial
     condition  will be dependent on the specifics of future  contracts  entered
     into with regard to guidance provided by the statement.  In connection with
     the January 2003 FASB EITF meeting, the FASB was requested to reconsider an
     interpretation of SFAS No. 133 (See Note 12).

     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  and  determining   whether  such  entities  should  be
     consolidated.  FIN No. 46 requires an enterprise to  consolidate a variable
     interest  entity when the enterprise (a) absorbs a majority of the variable
     interest entity's expected losses,  (b) receives a majority of the entity's
     expected residual returns,  or both, as a result of ownership,  contractual
     or other financial interests in the entity.  Prior to the effective date of
     FIN No. 46, entities were generally  consolidated by an enterprise that had
     control through ownership of a majority voting interest in the entity.  FIN
     No. 46 originally applied immediately to variable interest entities created
     or obtained after January 31, 2003. During 2003, PEC did not participate in
     the  creation  of, or  obtain a new  variable  interest  in,  any  variable
     interest entity. In December 2003, the FASB issued a revision to FIN No. 46
     (FIN No.  46R),  which  modified  certain  requirements  of FIN No.  46 and
     allowed  for the  optional  deferral of the  effective  date of FIN No. 46R
     until March 31, 2004.  However,  entities  subject to FIN No. 46 or FIN No.
     46R that are deemed to be  special-purpose  entities (as defined in FIN No.
     46R) must implement  either FIN No. 46 or FIN No. 46R at December 31, 2003.
     PEC elected to apply FIN No. 46 to special purpose  entities as of December
     31,  2003.  Because  PEC  expects  additional  transitional  guidance to be
     issued, it has elected to apply FIN No. 46R to non-special-purpose entities
     as of March 31, 2004.

     PEC has  investments  in 14 limited  partnerships  accounted  for under the
     equity  method  for  which  it  may  be  the  primary  beneficiary.   These
     partnerships  invest  in and  operate  low-income  housing  and  historical
     renovation  properties that qualify for federal and state tax credits.  PEC
     has  not  concluded  whether  it  is  the  primary   beneficiary  of  these
     partnerships.  These  partnerships are partially funded with financing from
     third party  lenders,  which is secured by the assets of the  partnerships.
     The creditors of the  partnerships do not have recourse to PEC. At December
     31, 2003, the maximum exposure to loss as a result of PEC's  investments in
     these limited  partnerships  is  approximately  $9 million.  PEC expects to
     complete its evaluation of these  partnerships under FIN No. 46R during the
     first  quarter  of  2004.  If PEC had  consolidated  these 14  entities  at
     December 31, 2003,  it would have recorded an increase to both total assets
     and total liabilities of approximately $40 million.

     PEC also has interests in several other variable  interest entities created
     before January 31, 2003, for which it is not the primary beneficiary. These
     arrangements   include  equity  investments  in  approximately  14  limited
     partnerships, limited liability corporations and venture capital funds, and
     two building leases with  special-purpose  entities.  The aggregate maximum
     loss  exposure  at  December  31,  2003  under  these  arrangements  totals
     approximately  $23  million.  The  creditors  of  these  variable  interest
     entities do not have recourse to the general credit of PEC in excess of the
     aggregate maximum loss exposure.

     In February  2004, PEC became aware that certain  long-term  purchase power
     and tolling  contracts may be considered  variable  interests under FIN No.
     46R. PEC has various  long-term  purchase power and tolling  contracts with
     other utilities and certain  qualifying  facility plants.  PEC believes the
     counterparties  to these  contracts are not  special-purpose  entities and,
     therefore,  FIN No. 46R would not apply to these  contracts until March 31,
     2004.  PEC has not yet  completed  its  evaluation  of these  contracts  to
     determine if the Company needs to consolidate  these  counterparties  under
     FIN No. 46R and will continue to monitor developing practice in this area.

                                      137
<PAGE>

3.   Property, Plant and Equipment

     A. Utility Plant

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

     (in millions)                                   2003            2002
                                              ---------------    -------------

     Production plant  (7-33 years)               $  8,024         $  7,630
     Transmission plant  (30-75 years)               1,155            1,128
     Distribution plant  (12-50 years)               3,538            3,345
     General plant and other (8-75 years)              614              577
                                              ---------------    -------------
     Utility plant in service                     $ 13,331         $ 12,680
                                              ===============    =============

     Generally,  electric  utility plant,  other than nuclear fuel is pledged as
     collateral for the first mortgage bonds of PEC (See Note 8).

     Allowance  for  funds  used  during  construction  (AFUDC)  represents  the
     estimated  debt and equity costs of capital funds  necessary to finance the
     construction  of new regulated  assets.  As  prescribed  in the  regulatory
     uniform systems of accounts, AFUDC is charged to the cost of the plant. The
     equity funds  portion of AFUDC is credited to other income and the borrowed
     funds  portion is  credited  to interest  charges.  Regulatory  authorities
     consider AFUDC an appropriate  charge for inclusion in the rates charged to
     customers  by the  utilities  over the service  life of the  property.  The
     composite AFUDC rate for PEC's electric  utility plant was 4.0% in 2003 and
     6.2% in 2002 and 2001.

     Depreciation   provisions  on  utility  plant,  as  a  percent  of  average
     depreciable  property  other than nuclear fuel,  were 2.7% in 2003 and 2002
     and 2.5% in 2001. The depreciation provisions related to utility plant were
     $345  million,  $326  million  and $305  million  in 2003,  2002 and  2001,
     respectively.   In  addition  to  utility  plant  depreciation  provisions,
     depreciation and amortization  expense also includes  decommissioning  cost
     provisions,  asset retirement obligations (ARO) accretion,  cost of removal
     provisions (See Note 3D) and regulatory approved expenses (See Note 5).

     PEC  filed a new  depreciation  study in 2004  that  provides  support  for
     reducing  depreciation  expense  on an annual  basis by  approximately  $45
     million. The reduction is primarily  attributable to assumption changes for
     nuclear  generation,  offset by increases for distribution  assets. The new
     rates are primarily effective January 1, 2004.

     The  amortization  of nuclear  fuel costs for the years ended  December 31,
     2003,  2002 and 2001 were $112  million,  $109  million  and $101  million,
     respectively.

     B. Diversified Business Property

     Gross  diversified  business  property  was $8 million  and $10  million at
     December 31, 2003 and 2002,  respectively.  These amounts consist primarily
     of equipment which is being  depreciated  over periods ranging from 3 to 10
     years.  Accumulated  depreciation  was $1 million at December  31, 2003 and
     2002.  Diversified business depreciation expense was $1 million, $4 million
     and $6  million  in 2003,  2002 and  2001,  respectively.  Net  diversified
     business   property  is  included  in  miscellaneous   other  property  and
     investments on the Consolidated Balance Sheets.

     C. Joint Ownership of Generating Facilities

     PEC  holds  ownership   interests  in  certain  jointly  owned   generating
     facilities.  PEC is entitled  to shares of the  generating  capability  and
     output of each unit equal to their respective ownership interests. PEC also
     pays its ownership share of additional  construction  costs, fuel inventory
     purchases and operating  expenses.  PEC's share of expenses for the jointly
     owned  facilities is included in the appropriate  expense  category.  PEC's
     ownership  interest in the  jointly-owned  generating  facilities is listed
     below with related information at December 31 ($ in millions):

                                      138
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

---------------------------------------------------------------------------------------------------------
                           Company Ownership  Plant Investment     Accumulated       Construction
        Facility               Interest                           Depreciation     Work in Progress
---------------------------------------------------------------------------------------------------------
2003
---------------------------------------------------------------------------------------------------------
Mayo Plant                      83.83%            $  464             $   242            $  50
Harris Plant                    83.83%              3,248              1,370                7
Brunswick Plant                 81.67%              1,611                884               21
Roxboro Unit No. 4              87.06%                323                139                1

---------------------------------------------------------------------------------------------------------
2002
---------------------------------------------------------------------------------------------------------

Mayo Plant                      83.83%            $   464            $   232            $  14
Harris Plant                    83.83%              3,160              1,331                6
Brunswick Plant                 81.67%              1,477                811               26
Roxboro Unit No. 4              87.06%                316                134                8
</TABLE>

     In the tables above, plant investment and accumulated  depreciation are not
     reduced  by the  regulatory  disallowances  related to the  Shearon  Harris
     Nuclear Plant (Harris Plant).

     D. Decommissioning and Cost of Removal Provisions

     Decommissioning  cost  provisions,  which are included in depreciation  and
     amortization  expense,  were $31 million in 2003, 2002 and 2001. Management
     believes  that  the  decommissioning  costs  that  have  been  and  will be
     recovered  through  rates will be  sufficient  to provide  for the costs of
     decommissioning.

     PEC's cost of removal  provisions,  which are included in  deprecation  and
     amortization  expense,  were $86  million,  $81  million and $77 million in
     2003,  2002 and 2001,  respectively.  These  amounts  represent the expense
     recognized  for the  disposal  or removal of utility  assets.  The FASB has
     issued SFAS No. 143,  "Accounting for Asset Retirement  Obligations"  (SFAS
     No.  143),  that changed the  accounting  for  decommissioning  and cost of
     removal provisions (See Note 3F).

     E. Insurance

     PEC is a  member  of  Nuclear  Electric  Insurance  Limited  (NEIL),  which
     provides primary and excess  insurance  coverage against property damage to
     members' nuclear generating  facilities.  Under the primary program, PEC is
     insured  for $500  million at each of its  nuclear  plants.  In addition to
     primary   coverage,   NEIL   also   provides   decontamination,   premature
     decommissioning  and excess property  insurance with limits of $2.0 billion
     on the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.

     Insurance coverage against incremental costs of replacement power resulting
     from  prolonged  accidental  outages  at nuclear  generating  units is also
     provided through membership in NEIL. PEC is insured thereunder, following a
     twelve-week deductible period, for 52 weeks in the amount of $3 million per
     week at the  Brunswick  and Harris  Plants and $2.5 million per week at the
     Robinson  Plant.  An additional 110 weeks of coverage is provided at 80% of
     the above weekly amounts.  For the current policy period, PEC is subject to
     retrospective  premium  assessments of up to approximately $21 million with
     respect  to  the  primary  coverage,   $25  million  with  respect  to  the
     decontamination,  decommissioning  and excess  property  coverage,  and $14
     million for the incremental  replacement power costs coverage, in the event
     covered losses at insured facilities exceed premiums, reserves, reinsurance
     and other NEIL  resources.  Pursuant to  regulations  of the United  States
     Nuclear  Regulatory  Commission  (NRC),  PEC's  property  damage  insurance
     policies  provide that all proceeds from such insurance be applied,  first,
     to place the plant in a safe and stable  condition  after an accident  and,
     second,   to   decontaminate,   before  any   proceeds   can  be  used  for
     decommissioning,  plant repair or  restoration.  PEC is  responsible to the
     extent losses may exceed limits of the coverage described above.

                                      139
<PAGE>

     PEC is insured against public  liability for a nuclear incident up to $10.9
     billion per occurrence.  Under the current provisions of the Price Anderson
     Act, which limits liability for accidents at nuclear power plants,  PEC, as
     an owner of nuclear units, can be assessed for a portion of any third-party
     liability  claims arising from an accident at any commercial  nuclear power
     plant in the United States.  In the event that public liability claims from
     an insured  nuclear  incident  exceed  $300  million  (currently  available
     through commercial insurers),  PEC would be subject to pro rata assessments
     of up to $101 million for each  reactor  owned per  occurrence.  Payment of
     such assessments  would be made over time as necessary to limit the payment
     in any one year to no more than $10 million per reactor owned.  Congress is
     expected to approve  revisions  to the Price  Anderson Act during 2004 that
     could include increased limits and assessments per reactor owned. The final
     outcome of this matter cannot be predicted at this time.

     Under the NEIL policies,  if there were multiple terrorism losses occurring
     within one year, NEIL would make available one industry  aggregate limit of
     $3.2  billion,  along  with  any  amounts  it  recovers  from  reinsurance,
     government  indemnity or other sources up to the limits for each  claimant.
     If  terrorism  losses  occurred  beyond the one-year  period,  a new set of
     limits and resources would apply. For nuclear  liability claims arising out
     of terrorist acts, the primary level available through commercial  insurers
     is now subject to an industry  aggregate limit of $300 million.  The second
     level of coverage  obtained  through the assessments  discussed above would
     continue  to apply to losses  exceeding  $300  million  and  would  provide
     coverage in excess of any  diminished  primary  limits due to the terrorist
     acts.

     PEC self-insures  its transmission and distribution  lines against loss due
     to storm damage and other natural disasters.

     F. Asset Retirement Obligations

     SFAS No. 143 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 a  liability  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   AROs  for  nuclear
     decommissioning  of irradiated  plant  totaling  $880 million.  PEC used an
     expected  cash flow  approach  to measure  these  obligations.  This amount
     includes accruals  recorded prior to adoption totaling $491 million,  which
     were previously  recorded in cost of removal.  The related asset retirement
     costs, net of accumulated depreciation, recorded upon adoption totaled $117
     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 million,  pursuant to SFAS No.
     71.  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.

     The asset retirement costs related to nuclear decommissioning of irradiated
     plant,  net of accumulated  depreciation,  totaled $113 million at December
     31,  2003.  The  ongoing  expense  differences  between  SFAS  No.  143 and
     regulatory cost recovery are being deferred to the regulatory asset.

     Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear
     decommissioning  liability  totaled  $505  million at December 31, 2003 and
     $423  million at December  31, 2002.  Net  unrealized  gains on the nuclear
     decommissioning trust fund were included in regulatory  liabilities in 2003
     and cost of removal in 2002.

     The following table shows the changes to the asset  retirement  obligations
     during the year ended December 31, 2003:

     (in millions)
     Asset retirement obligations as of January 1, 2003             $ 880
     Accretion expense                                                 52
                                                                 ---------
     Asset retirement obligations as of  December 31, 2003          $ 932
                                                                 =========


                                      140
<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 previously  recognized removal and decommissioning costs as a component
     of accumulated  depreciation in accordance with  regulatory  treatment.  At
     December  31, 2003,  such costs  totaling  $994  million  were  included in
     regulatory  liabilities  on the  Consolidated  Balance Sheet and consist of
     removal costs of $927 million and removal costs for non-irradiated areas at
     nuclear  facilities  of $67  million.  At  December  31,  2002,  such costs
     totaling   $1,488   million  were  included  in  cost  of  removal  on  the
     Consolidated Balance Sheet and consist of removal costs of $877 million and
     decommissioning  costs for both the irradiated and non-irradiated  areas at
     nuclear  facilities of $611  million.  With the adoption of SFAS No. 143 in
     2003,  removal costs related to the irradiated areas at nuclear  facilities
     are  reported  as asset  retirement  obligations  on the 2003  Consolidated
     Balance Sheet.

     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  initially  granted the  deferral of the
     January 1, 2003  cumulative  adjustment.  During the third quarter of 2003,
     the NCUC issued an order allowing the deferral of the ongoing effects.

     In April  2003,  the SCPSC  approved a joint  request by PEC,  Duke  Energy
     Corporation  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.

     Therefore, the actions of the NCUC and SCPSC had no impact on the income of
     PEC for the year ended December 31, 2003.

4.   Inventory

     At December 31, inventory was comprised of:

     (in millions)                          2003            2002
                                        ------------     ------------

     Fuel                                   $ 118           $ 118
     Materials and supplies                   230             225
                                        ------------     ------------
     Total inventory                        $ 348           $ 343
                                        ============     ============

5.   Regulatory Matters

     A. Regulatory Assets and Liabilities

     As a regulated  entity,  PEC is subject to the  provisions  of SFAS No. 71.
     Accordingly,  PEC records certain assets and liabilities resulting from the
     effects of the  ratemaking  process which would not be recorded  under GAAP
     for nonregulated  entities.  PEC's ability to continue to meet the criteria
     for application of SFAS No. 71 may be affected in the future by competitive
     forces and  restructuring  in the electric utility  industry.  In the event
     that  SFAS  No.  71 no  longer  applied  to a  separable  portion  of PEC's
     operations,  related  regulatory assets and liabilities would be eliminated
     unless  an  appropriate   regulatory   recovery   mechanism  was  provided.
     Additionally,  these factors could result in an impairment of utility plant
     assets as determined pursuant to SFAS No. 144 (See Note 1C).

                                      141
<PAGE>

     At December 31, the balances of PEC's regulatory assets  (liabilities) were
     as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                                            2003              2002
                                                                         ----              ----
Deferred fuel cost                                                  $     113           $    146
                                                                  ----------------   ---------------

Deferred impact of  ARO  (Note 3F)                                        291                  -
Income taxes recoverable through future rates (Note 10)                    94                122
Loss on reacquired debt (Note 1C)                                          22                 13
Storm deferral (Note 5B)                                                   21                  -
Deferred DOE enrichment facilities-related costs  (Note 1C)                19                 25
Other                                                                      30                 46
                                                                  ----------------   ---------------
     Total long-term regulatory assets                                    477                206

Non-ARO cost of removal (Note 3F)                                        (994)                 -
Emission allowance                                                         (8)                (8)
Net nuclear decommissioning trust unrealized gains (Note 3F)              (99)                 -
Clean air compliance (Note 5B)                                            (74)                 -
                                                                  ----------------   ---------------
     Total long-term regulatory liabilities                            (1,175)                (8)
                                                                  ----------------   ---------------

         Net regulatory assets/(liabilities)                        $    (585)          $    344
                                                                  ================   ===============
</TABLE>

     Except for portions of deferred  fuel, all assets earn a return or the cash
     has not yet  been  expended,  in  which  case  the  assets  are  offset  by
     liabilities that do not incur a carrying cost. The utility expects to fully
     recover  these assets and refund the  liabilities  through  customer  rates
     under current regulatory practice.

     B. Retail Rate Matters


     The NCUC and SCPSC approved  proposals to accelerate cost recovery of PEC's
     nuclear generating assets beginning January 1, 2000, and continuing through
     2009.  The  aggregate  minimum  and  maximum  amounts of  accelerated  cost
     recovery are $530 million and $750 million, respectively.  Accelerated cost
     recovery  of these  assets  resulted in no  additional  expense in 2003 and
     additional  depreciation  expense  of  approximately  $53  million  and $75
     million  in 2002 and 2001,  respectively.  Total  accelerated  depreciation
     recorded through December 31, 2003 was $403 million.

     In conjunction with the acquisition of NCNG in 1999, 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.

     The NC Clean  Air Act of June 2002 (the  Clean  Air  Act),  requires  state
     utilities to reduce  emissions of nitrogen  oxide (NOx) and sulfur  dioxide
     (SO2)  from  coal-fired  plants.  The NCUC has  allowed  the  utilities  to
     amortize  and recover the costs  associated  with  meeting the new emission
     standards  over  a  seven-year   period  beginning  January  1,  2003.  PEC
     recognized  $74  million  of  clean  air  amortization  during  2003.  This
     legislation  freezes  PEC's base rates in North  Carolina  for five  years,
     subject to certain conditions (See Note 16D).

     In conjunction with the Company's merger with Florida Progress  Corporation
     (Florida  Progress),  PEC reached a settlement with the Public Staff of the
     NCUC in which it agreed to reduce rates to all of its non-real time pricing
     customers by $3 million in 2002, $5 million in 2003, and $6 million in both
     2004 and 2005.

     PEC   obtained   SCPSC  and  NCUC   approval  of  fuel  factors  in  annual
     fuel-adjustment  proceedings.  The SCPSC  approved  PEC's petition to leave
     billing rates unchanged from the prior year by order issued March 28, 2003.
     The NCUC approved an increase of $20 million by order issued  September 25,
     2003.

     On October 16, 2003, PEC made a filing with the NCUC to seek  permission to
     defer expenses  incurred from Hurricane Isabel and the February 2003 winter
     storms.  As a result of rising storm costs and the frequency of major storm
     damage,  PEC asked the NCUC to allow PEC to create a  deferred  account  in
     which PEC  would  place  expenses  incurred  as a result of named  tropical
     storms,  hurricanes and  significant  winter storms.  In December 2003, the
     NCUC  approved  PEC's  request to defer the costs and amortize  them over a
     period of 5 years  beginning  in the month the storm  occurs.  PEC  charged
     approximately  $24 million in 2003 from  Hurricane  Isabel and from current
     year ice storms to the deferred account,  of which $3 million was amortized
     during 2003.

                                      142
<PAGE>

     PEC retains funds internally to meet  decommissioning  liability.  The NCUC
     order  issued  February  2004  found that by January 1, 2008 PEC must begin
     transitioning  these  amounts to external  funds.  The  transition  of $131
     million must be  completed  by December 31, 2017,  and at least 10% must be
     transitioned  each year. PEC has exclusively  utilized external funding for
     its decommissioning liability since 1994.

     C. Regional Transmission Organizations and Standard Market Design

     In  2000,  the FERC  issued  Order  No.  2000 on RTOs,  which  set  minimum
     characteristics  and eight functions for transmission  entities,  including
     independent  system operators  (ISOs) and  transmission  companies that are
     required to become  FERC-approved  RTOs.  As a result of Order  2000,  PEC,
     along  with Duke  Energy  Corporation  and South  Carolina  Electric  & Gas
     Company,  filed  and  received  provisional  approval  from  the FERC for a
     GridSouth RTO. However,  in July 2001, the FERC issued orders  recommending
     that companies in the Southeast engage in mediation to develop a plan for a
     single RTO for the Southeast.  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. PEC filed comments in November 2002 and  supplement  comments
     in January  2003.  In April  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. The FERC has not yet issued a final
     rule on SMD NOPR.

     PEC has $33 million  invested in GridSouth at December 31, 2003.  Given the
     regulatory uncertainty of the ultimate timing,  structure and operations of
     GridSouth,  or an alternate  combined  transmission  structure,  PEC cannot
     predict the effect on future consolidated results of operations, cash flows
     or  financial  condition.   Furthermore,  the  SMD  NOPR  presents  several
     uncertainties,  including  what  percentage of the  investment in GridSouth
     will be recovered, how the elimination of transmission charges, as proposed
     in the SMD NOPR,  will impact PEC, and what amount of capital  expenditures
     will be necessary to create a new wholesale market.

6.   Impairments of Long-Lived Assets and Investments

     Effective  January  1, 2002,  PEC  adopted  SFAS No.  144,  which  provides
     guidance for the  accounting  and  reporting of  impairment  or disposal of
     long-lived assets. The statement supersedes SFAS No. 121. In 2003, 2002 and
     2001, PEC recorded pre-tax long-lived asset and investment  impairments and
     other charges of approximately $21 million,  $133 million and $157 million,
     respectively.

     A. Long-Lived Assets

     In 2002,  PEC  initiated  an  independent  valuation  study to  assess  the
     recoverability of Caronet's  long-lived  assets.  Based on this assessment,
     PEC recorded asset impairments of $101 million on a pre-tax basis and other
     charges of $7 million on a pre-tax basis in the third quarter of 2002. This
     write-down  constituted a significant  reduction in the book value of these
     long-lived assets. The long-lived asset impairments  included an impairment
     of  property,  plant  and  equipment,  construction  work  in  process  and
     intangible  assets. The impairment charge represents the difference between
     the fair value and carrying  amount of these  long-lived  assets.  The fair
     value of these  assets  was  determined  using a  valuation  study  heavily
     weighted  on the  discounted  cash flow  methodology,  while  using  market
     approaches as supporting information.

                                      143
<PAGE>

     B. Investments

     PEC continually  reviews its investments to determine  whether a decline in
     fair value  below the cost basis is other than  temporary.  In 2003,  PEC's
     affordable housing investment (AHI) portfolio was reviewed and deemed to be
     impaired based on various factors including  continued  operating losses of
     the AHI  portfolio and  management  performance  issues  arising at certain
     properties  within  the  AHI  portfolio.  As  a  result,  PEC  recorded  an
     impairment  on the AHI  portfolio of $18 million on a pre-tax  basis during
     the fourth  quarter of 2003.  PEC also recorded an impairment of $3 million
     on a cost investment.

     PEC  obtained a  valuation  study to assess  its  investment  in  Interpath
     Communications,  Inc.  (Interpath)  based  on  current  valuations  in  the
     technology  sector  during  2001.  Interpath  was  an  application  service
     provider business in which PEC had a 35% ownership interest. As a result of
     the   valuation   study,   PEC   recorded   investment    impairments   for
     other-than-temporary  declines  in the  fair  value  of its  investment  in
     Interpath.  The  investment  write-down was $157 million on a pre-tax basis
     for the year ended December 31, 2001. In May 2002,  Interpath merged with a
     third  party  and PEC's  ownership  was  diluted  to  approximately  19% of
     Interpath.   As  a  result,  PEC  reviewed  the  Interpath  investment  for
     impairment and wrote off the remaining amount of its cost-basis  investment
     in  Interpath,  recording a pre-tax  impairment of $25 million in the third
     quarter of 2002.  In the fourth  quarter  of 2002,  PEC sold its  remaining
     interest in Interpath for a nominal amount.

7.   Equity

     A. Capitalization

     At December 31, 2003,  PEC was authorized to issue up to 200 million shares
     of common stock. All shares issued and outstanding are held by the Company.
     Preferred stock  outstanding at December 31, 2003 and 2002 consisted of the
     following (in millions except per share and par value):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
       20,000,000 shares, cumulative, $100 par value Serial
       Preferred Stock
          $5.00 Preferred - 236,997 shares (redemption price $110.00)                 $24
          $4.20 Serial Preferred - 100,000 shares outstanding
              redemption price $102.00)                                                10
          $5.44 Serial Preferred -249,850 shares (redemption price
              $101.00)                                                                 25
                                                                                   -------
       Total Preferred Stock                                                          $59
                                                                                   =======
</TABLE>

     There are various provisions  limiting the use of retained earnings for the
     payment of dividends  under  certain  circumstances.  At December 31, 2003,
     there were no significant restrictions on the use of retained earnings.

     PEC's Articles of Incorporation provide that cash dividends on common stock
     shall be limited to 75% of net income  available  for  dividends  if common
     stock equity falls below 25% of total capitalization,  and to 50% if common
     stock  equity  falls below 20%. On December  31,  2003,  PEC's common stock
     equity was approximately 50.7% of total capitalization.

     Refer  to Note 8 for  additional  dividend  restrictions  related  to PEC's
     mortgage.

     B. Stock-Based Compensation Plans

     Employee Stock Ownership Plan

     Progress  Energy  sponsors the  Progress  Energy  401(k)  Savings and Stock
     Ownership   Plan   (401(k))   for   which   substantially   all   full-time
     non-bargaining   unit  employees  and  certain   part-time   non-bargaining
     employees  within  participating   subsidiaries  are  eligible.  PEC  is  a
     participating  subsidiary  of the 401(k),  which has matching and incentive
     goal features,  encourages  systematic  savings by employees and provides a
     method  of  acquiring  Progress  Energy  common  stock  and  other  diverse
     investments. The 401(k), as amended in 1989, is an Employee Stock Ownership
     Plan  (ESOP)  that can enter into  acquisition  loans to  acquire  Progress

                                      144
<PAGE>

     Energy common stock to satisfy 401(k) common stock needs.  Qualification as
     an ESOP did not change the level of benefits  received by  employees  under
     the 401(k). Common stock acquired with the proceeds of an ESOP loan is held
     by the 401(k) Trustee in a suspense  account.  The common stock is released
     from the suspense account and made available for allocation to participants
     as the ESOP loan is repaid.  Such  allocations  are used to partially  meet
     common  stock  needs  related to Progress  Energy  matching  and  incentive
     contributions and/or reinvested dividends.

     There were 4.0 million and 4.6 million ESOP suspense shares at December 31,
     2003 and 2002,  respectively,  with a fair value of $183  million  and $200
     million, respectively.  PEC's matching and incentive goal compensation cost
     under the 401(k) is determined based on matching  percentages and incentive
     goal attainment as defined in the plan. Such compensation cost is allocated
     to participants' accounts in the form of Progress Energy common stock, with
     the number of shares determined by dividing compensation cost by the common
     stock market value at the time of allocation. The 401(k) common stock share
     needs are met with open market  purchases,  with shares  released  from the
     ESOP  suspense  account and with newly issued  shares.  Costs for incentive
     goal  compensation  are accrued  during the fiscal year and typically  paid
     with shares in the  following  year;  costs for the matching  component are
     typically  met with shares in the same year  incurred.  PEC's  matching and
     incentive  cost which were and will be met with  shares  released  from the
     suspense  account totaled  approximately  $11 million,  $13 million and $13
     million for the years ended December 31, 2003, 2002 and 2001, respectively.
     Matching and incentive cost totaled  approximately $16 million, $14 million
     and $14 million  for the years  ended  December  31,  2003,  2002 and 2001,
     respectively.  PEC has a long-term note  receivable from the 401(k) Trustee
     related to the  purchase  of common  stock  from PEC in 1989 (now  Progress
     Energy common stock).  The balance of the note  receivable  from the 401(k)
     Trustee is included in the  determination  of unearned  ESOP common  stock,
     which reduces common stock equity.  Interest  income on the note receivable
     is not recognized for financial statement purposes.

     Stock Option Agreements

     Pursuant to Progress  Energy's 1997 Equity  Incentive  Plan and 2002 Equity
     Incentive  Plan,  as amended  and  restated as of July 10,  2002,  Progress
     Energy may grant  options to purchase  shares of common stock to directors,
     officers and  eligible  employees.  For the years ended  December 31, 2003,
     2002 and 2001, respectively, approximately 3.0 million, 2.9 million and 2.4
     million common stock options were granted. Of these amounts,  approximately
     1.9 million,  1.2 million and 1.0 million  options were granted to officers
     and eligible employees of PEC in 2003, 2002 and 2001, respectively.

     Other Stock-Based Compensation Plans

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

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

     The RSA program  allows the Company to grant  shares of  restricted  common
     stock to officers and key employees of the Company.  The restricted  shares
     generally vest on a graded vesting  schedule over a minimum of three years.
     Compensation  expense,  which is based on the fair value of common stock at
     the grant date, is recognized  over the  applicable  vesting  period and is
     reduced by any forfeitures.

     The total amount expensed by PEC for other stock-based  compensation  plans
     was $15  million,  $11  million  and $10  million  in 2003,  2002 and 2001,
     respectively.

                                      145
<PAGE>

     C. Accumulated Other Comprehensive Loss

     Components of accumulated other comprehensive loss are as follows:

     (in millions)                                       2003           2002
                                                   ------------     -----------
     Loss on cash flow hedges                            $ (6)        $  (10)
     Minimum pension liability adjustments                 (1)           (73)
                                                   ------------     -----------
     Total accumulated other comprehensive loss          $ (7)        $  (83)
                                                   ============     ===========

8.   Debt and Credit Facilities

     A. Debt and Credit

     At December 31, PEC's long-term debt consisted of the following (maturities
     and weighted-average interest rates at December 31, 2003):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                                             2003              2002
                                                                       ------------      -----------
First mortgage bonds, maturing 2004-2033                  6.42%           $ 1,900           $ 1,550
Pollution control obligations, maturing 2010-2024         1.69%               708               708
Unsecured notes, maturing 2012                            6.50%               500               500
Medium-term notes, maturing 2008                          6.65%               300               300
Miscellaneous notes                                                             -                 6
Unamortized premium and discount, net                                         (22)              (16)
Current portion of long-term debt                                            (300)                -
                                                                       ------------      -----------
     Total Long-Term Debt, Net                                            $ 3,086           $ 3,048
                                                                       ============      ===========
</TABLE>

     At December 31, 2003, PEC had committed lines of credit,  which are used to
     support its commercial paper  borrowings and had no outstanding  loans. PEC
     is required to pay minimal  annual  commitment  fees to maintain its credit
     facilities.  The following  table  summarizes  PEC's credit  facilities (in
     millions):

                        Description                           Total
    ----------------------------------------------------------------------

    364-Day (expiring 7/29/04)                                  $  165
    3-Year (expiring 7/31/05)                                      285
                                                         -----------------
                                                                $  450
                                                         =================

     At  December  31,  2003 and  2002,  PEC had $4  million  and $438  million,
     respectively,  of  outstanding  commercial  paper and other short term debt
     classified as short term obligations.  The weighted-average  interest rates
     of such short-term obligations at December 31, 2003 and 2002 were 2.25% and
     1.74%, respectively.

     The combined  aggregate  maturities of long-term debt for 2004 through 2008
     are   approximately,   in  millions,   $300,   $300,  $0,  $200  and  $300,
     respectively.

     B. Covenants and Default Provisions

     Financial Covenants
     PEC's credit line contains  various terms and conditions  that could affect
     PEC's  ability to borrow under these  facilities.  These  include a maximum
     debt to total  capital  ratio,  a  material  adverse  change  clause  and a
     cross-default provision.

     PEC's credit line  requires a maximum  total debt to total capital ratio of
     65%. Indebtedness as defined by the bank agreement includes certain letters
     of credit and guarantees which are not recorded on the Consolidated Balance
     Sheets.  At December 31, 2003,  PEC's total debt to total capital ratio was
     51.4%.

     Material Adverse Change Clause
     The credit  facility of PEC includes a provision  under which lenders could
     refuse to advance  funds in the event of a material  adverse  change in the
     borrower's financial condition.

                                      146
<PAGE>

     Default Provisions
     PEC's  credit  lines  include  cross-default  provisions  for  defaults  of
     indebtedness in excess of $10 million. PEC's cross-default  provisions only
     apply  to  defaults   of   indebtedness   by  PEC  and  its   subsidiaries,
     respectively,  and not to other affiliates of PEC. In addition,  the credit
     lines of Progress  Energy include a similar  provision.  Progress  Energy's
     cross-default provisions only apply to defaults of indebtedness by Progress
     Energy and its significant subsidiaries, which includes PEC.

     The lenders may accelerate payment of any outstanding debt if cross-default
     provisions  are  triggered.  Any such  acceleration  would cause a material
     adverse change in the respective  company's  financial  condition.  Certain
     agreements  underlying PEC's indebtedness also limit PEC's ability to incur
     additional  liens  or  engage  in  certain  types  of  sale  and  leaseback
     transactions.

     Other Restrictions
     PEC's mortgage indenture provides that, as long as any first mortgage bonds
     are outstanding, cash dividends and distributions on PEC's common stock and
     purchases  of PEC's  common stock are  restricted  to aggregate  net income
     available  for PEC,  since  December  31, 1948,  plus $3 million,  less the
     amount of all preferred stock dividends and  distributions,  and all common
     stock  purchases,  since  December 31, 1948. At December 31, 2003,  none of
     PEC's  retained  earnings were  restricted.  Refer to Note 7 for additional
     dividend restrictions related to PEC's Articles of Incorporation.

     C. Secured Obligations

     PEC's  first  mortgage  bonds  are  secured  by their  respective  mortgage
     indentures. PEC's mortgage constitutes a first lien on substantially all of
     its  fixed  properties,  subject  to  certain  permitted  encumbrances  and
     exceptions.  The PEC  mortgage  also  constitutes  a lien  on  subsequently
     acquired  property.  At December 31,  2003,  PEC had  approximately  $2,608
     million in first  mortgage  bonds  outstanding  including  those related to
     pollution  control  obligations.  The PEC  mortgage  allows the issuance of
     additional mortgage bonds upon the satisfaction of certain conditions.

     D. Hedging Activities

     PEC uses  interest rate  derivatives  to adjust the fixed and variable rate
     components of its debt  portfolio and to hedge cash flow risk of fixed rate
     debt to be issued in the future.  See  discussion  of risk  management  and
     derivative transactions at Note 12.

9.   Fair Value of Financial Instruments

     At  December  31,  2003 and  2002,  there  were  miscellaneous  investments
     consisting  primarily of  investments in  company-owned  life insurance and
     other benefit plan assets with carrying amounts totaling  approximately $59
     million and $54  million,  respectively,  included in  miscellaneous  other
     property  and  investments.   The  carrying  amount  of  these  investments
     approximates  fair value due to the short maturity of certain  instruments.
     Other  instruments are presented at fair value in accordance with GAAP. The
     carrying amount of PEC's long-term debt, including current maturities,  was
     $3,386  million at  December  31, 2003 and $3,048  million at December  31,
     2002. The estimated fair value of this debt, as obtained from quoted market
     prices  for the same or  similar  issues,  was  $3,686  million  and $3,328
     million at December 31, 2003 and 2002, respectively.

     External trust funds have been established to fund certain costs of nuclear
     decommissioning.  These nuclear decommissioning trust funds are invested in
     stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are
     presented at amounts that  approximate  fair value.  Fair value is obtained
     from quoted market prices for the same or similar investments.

10.  Income Taxes

     Deferred income taxes are provided for temporary  differences  between book
     and tax bases of assets and liabilities.  Investment tax credits related to
     regulated  operations  are  amortized  over the service life of the related
     property.  To the extent that the  establishment  of deferred  income taxes
     under SFAS No. 109 is  different  from the recovery of taxes by PEC through
     the ratemaking  process,  the differences are deferred pursuant to SFAS No.
     71. A regulatory  asset or liability has been  recognized for the impact of
     tax  expenses  or benefits  that are  recovered  or  refunded in  different
     periods by the utilities pursuant to rate orders.

                                      147
<PAGE>

     Net  accumulated  deferred income tax  liabilities/(assets)  at December 31
     are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                               2003                  2002
                                                           --------------         -------------
     Accumulated depreciation and property
        cost differences                                         $ 1,207               $ 1,280
     Minimum pension liability                                        (1)                  (47)
     Deferred costs, net                                             (26)                  (50)
     Income tax credit carry forward                                 (22)                  (10)
     Valuation allowance                                               1                     8
     Miscellaneous other temporary differences, net                  (50)                  (10)
                                                           --------------         -------------

      Net accumulated deferred income tax liability              $ 1,109               $ 1,171
                                                           ==============         =============
</TABLE>

     Total  deferred  income tax  liabilities  were  $1,880  million  and $1,882
     million at December 31, 2003 and 2002, respectively.  Total deferred income
     tax assets  were $771  million and $711  million at  December  31, 2003 and
     2002, respectively.  At December 31, 2003 and 2002, PEC had net non-current
     deferred tax liabilities of $1,125 million and $1,105 million.  At December
     31, 2003 PEC had a net current  deferred tax asset of $16 million  which is
     included on the Consolidated  Balance Sheets under the caption  prepayments
     and other  current  assets.  At  December  31,  2002 PEC had a net  current
     deferred tax liability of $66 million which is included on the Consolidated
     Balance Sheets under the caption other current liabilities.

     PEC established  additional  valuation allowances of $1 million, $4 million
     and $4  million  during  2003,  2002  and  2001,  respectively,  due to the
     uncertainty  of  realizing  certain  future state tax  benefits.  PEC had a
     valuation  allowance of $8 million at December 31, 2002, which decreased by
     $7 million in 2003. The overall decrease in the 2003 valuation allowance is
     largely due to PEC's sale of its wholly-owned subsidiary Caronet. Caronet's
     valuation  allowance  balance at December  31, 2002 and 2001 was $8 million
     and $4 million,  respectively. PEC believes that it is more likely than not
     that the results of future  operations  will  generate  sufficient  taxable
     income to allow for the utilization of the remaining deferred tax assets.

     Reconciliations of PEC's effective income tax rate to the statutory federal
     income tax rate are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                  2003              2002              2001
                                              -------------     -------------     -------------

Effective income tax rate                          32.6%            32.5%             38.0%
State income taxes, net of federal benefit         (1.9)            (3.1)             (3.2)
Investment tax credit amortization                  1.4              1.9               2.5
Progress Energy tax benefit allocation              3.0              5.0                -
Other differences, net                             (0.1)            (1.3)             (2.3)
                                              -------------     -------------     -------------

Statutory federal income tax rate                  35.0%            35.0%             35.0%
                                              =============     =============     =============

     The provisions for income tax expense are comprised of:

(in millions)                                     2003              2002               2001
                                              -------------     -------------     ---------------
Income tax expense (credit):
Current   - federal                               $ 285             $ 265              $ 349
                  state                              37                36                 39
Deferred -  federal                                 (55)              (76)              (140)
                   state                            (13)               (6)               (10)
Investment tax credit                               (10)              (12)               (15)
                                              -------------     -------------     ---------------

       Total income tax expense                   $ 244             $ 207              $ 223
                                              =============     =============     ===============
</TABLE>

     PEC and  each of its  wholly-owned  subsidiaries  have  entered  into a Tax
     Agreement  with  Progress  Energy  (See Note 1C).  PEC's  intercompany  tax
     receivable  was $16 million and $13 million at December  31, 2003 and 2002,
     respectively.

                                      148
<PAGE>

11.  Benefit Plans

     PEC and some of its subsidiaries  have a  non-contributory  defined benefit
     retirement  (pension) plan for substantially all full-time  employees.  PEC
     also has supplementary  defined benefit pension plans that provide benefits
     to higher-level employees. In addition to pension benefits, PEC and some of
     its subsidiaries provide contributory other postretirement benefits (OPEB),
     including  certain  health care and life  insurance  benefits,  for retired
     employees  who meet  specified  criteria.  PEC uses a  measurement  date of
     December 31 for its pension and OPEB plans.

     The components of net periodic benefit cost for the years ended December 31
     are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                   Pension Benefits           Other Postretirement Benefits
                                         ---------------------------------    -----------------------------
     (in millions)                          2003         2002        2001        2003     2002     2001
                                         ---------------------------------    ---------------------------
     Service cost                        $     23    $     19    $     17     $      7   $    6   $    7
     Interest cost                             51          51          47           15       14       14
     Expected return on plan assets           (70)        (73)        (72)          (3)      (3)      (4)
     Amortization, net                          -           1          (6)           5        2        5
                                         ---------------------------------    ---------------------------
     Net periodic cost / (benefit)       $      4    $    (2)    $    (14)    $     24   $   19   $   22
                                         =================================    ===========================
</TABLE>

     Prior  service costs and benefits are  amortized on a  straight-line  basis
     over the average remaining service period of active participants. Actuarial
     gains and losses in excess of 10% of the greater of the  obligation  or the
     market-related  value of assets are  amortized  over the average  remaining
     service  period  of active  participants.  PEC uses a  five-year  averaging
     method to determine its market-related value of assets.

     Reconciliations  of the changes in the plans' benefit  obligations  and the
     plans' funded status are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                      Pension Benefits        Other Postretirement Benefits
                                                  ------------------------    ------------------------------
    (in millions)                                     2003        2002              2003             2002
                                                  ------------------------    ------------------------------
    Obligation at January 1                       $      802  $       682       $      234       $      192
    Service cost                                          23           19                7                6
    Interest cost                                         51           51               15               14
    Benefit payments                                     (46)         (46)              (8)              (9)
    Actuarial loss (gain)                                (82)          96               12               31
                                                  ------------------------    ------------------------------
    Obligation at December 31                            748          802              260              234
    Fair value of plan assets at December 31             694          574               43               33
                                                  ------------------------    ------------------------------

    Funded status                                        (54)        (228)            (217)            (201)
    Unrecognized transition obligation                     -            -               23               26
    Unrecognized prior service cost                        4            4                -                -
    Unrecognized net actuarial (gain) loss                61          238               41               38
    Minimum pension liability adjustment                  (2)        (125)               -                -
                                                  ------------------------    ------------------------------
    Prepaid (accrued) cost at December 31, net    $        9  $      (111)      $     (153)      $     (137)
                                                  ========================    ==============================
</TABLE>

     The net  prepaid  pension  cost  of $9  million  at  December  31,  2003 is
     recognized  in the  accompanying  Consolidated  Balance  Sheets as  prepaid
     pension cost of $28 million, which is included in other assets and deferred
     debits, and accrued benefit cost of $19 million, which is included in other
     liabilities and deferred credits.  The accrued pension cost at December 31,
     2002  is  included  in  other  liabilities  and  deferred  credits  in  the
     accompanying Consolidated Balance Sheets. The defined benefit pension plans
     with accumulated benefit obligations in excess of plan assets had projected
     benefit  obligations  totaling $22 million and $802 million at December 31,
     2003  and  2002,   respectively.   Those  plans  had  accumulated   benefit
     obligations  totaling $19 million and $685 million,  respectively,  no plan
     assets at December  31,  2003,  and plan assets  totaling  $574  million at
     December 31, 2002.  The total  accumulated  benefit  obligation for pension
     plans was $745  million  and $685  million at  December  31, 2003 and 2002,
     respectively.  The accrued OPEB cost is included in other  liabilities  and
     deferred credits in the accompanying Consolidated Balance Sheets.

                                      149
<PAGE>

     A minimum  pension  liability  adjustment  of $2  million,  related  to the
     supplementary  defined  benefit  pension plan, was recorded at December 31,
     2003.  This  adjustment  is offset  by a  corresponding  pre-tax  amount in
     accumulated other  comprehensive  loss, a component of common stock equity.
     Due to a  combination  of  decreases in the fair value of plan assets and a
     decrease in the  discount  rate used to measure the pension  obligation,  a
     minimum  pension  liability  adjustment  of $125  million  was  recorded at
     December 31, 2002.  This  adjustment  resulted in a charge of $4 million to
     intangible  assets,  included in other  assets and  deferred  debits in the
     accompanying  Consolidated  Balance  Sheets,  and a pre-tax  charge of $121
     million to  accumulated  other  comprehensive  loss,  a component of common
     stock equity.

     Reconciliations of the fair value of plan assets are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                         Pension Benefits        Other Postretirement Benefits
                                                  ----------------------------   -----------------------------
     (in millions)                                       2003            2002            2003         2002
                                                  ----------------------------     ------------------------
     Fair value of plan assets January 1                $ 574           $ 717            $ 33         $ 38
     Actual return on plan assets                         164            (97)              10          (5)
     Benefit payments                                    (46)            (46)             (8)          (9)
     Employer contributions                                 1               1               8            9
     Transfers                                              -             (1)               -            -
                                                  ------------    ------------     -----------  -----------
     Fair value of plan assets at December 31           $ 693           $ 574            $ 43         $ 33
                                                  ============    ============     ===========  ===========
</TABLE>

     In the table  above,  substantially  all employer  contributions  represent
     benefit payments made directly from Company assets.  The remaining benefits
     payments  were made directly  from plan assets.  The OPEB benefit  payments
     represent  the net PEC cost after  participant  contributions.  Participant
     contributions represent approximately 35% of gross benefit payments.

     The asset  allocation  for PEC's  plans at the end of 2003 and 2002 and the
     target allocation for the plans, by asset category, are as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                          Pension Benefits                       Other Postretirement Benefits
                             ------------------------------------------  ---------------------------------------------
                                Target        Percentage of Plan Assets       Target         Percentage of Plan Assets
                             Allocations            at Year End             Allocations            at Year End
                             -------------    ------------------------   -----------------    ------------------------
Asset Category                   2004              2003        2002            2004             2003         2002
                             -------------    ----------------------     -----------------    ----------------------
  Equity - domestic               50%               49%         47%               50%             49%           47%
  Equity - international          15%               22%         20%               15%             22%           20%
  Debt - domestic                 15%               11%         15%               15%             11%           15%
  Debt - international            10%               11%         10%               10%             11%           10%
  Other                           10%                7%          8%               10%              7%            8%
                             -------------    ----------------------     -----------------    ----------------------
  Total                          100%              100%        100%              100%            100%          100%
                             =============    ======================     =================    ======================
</TABLE>

     PEC  sets  target   allocations   among  asset  classes  to  provide  broad
     diversification  to protect against large  investment  losses and excessive
     volatility,  while  recognizing the importance of offsetting the impacts of
     benefit cost  escalation.  In  addition,  PEC employs  external  investment
     managers who have  complementary  investment  philosophies  and approaches.
     Tactical  shifts (plus or minus five percent) in asset  allocation from the
     target  allocations  are made based on the  near-term  view of the risk and
     return tradeoffs of the asset classes.

     In 2004, PEC expects to make required contributions of $17 million directly
     to pension  plan  assets.  The  expected  benefit  payments for the pension
     benefit plan for 2004 through 2008 and in total for 2009-2013, in millions,
     are  approximately  $48,  $49, $50,  $53, $55 and $301,  respectively.  The
     expected  benefit  payments  for the OPEB plan for 2004 through 2008 and in
     total for 2009-2013,  in millions,  are  approximately $7, $8, $9, $10, $10
     and $62,  respectively.  The  expected  benefit  payments  include  benefit
     payments  directly  from plan assets and  benefit  payments  directly  from
     Company  assets.  The benefit  payment  amounts reflect the net cost to PEC
     after any participant contributions.

                                      150
<PAGE>

     The  following  weighted-average  actuarial  assumptions  were  used in the
     calculation of the year-end obligation:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                  Pension Benefits         Other Postretirement Benefits
                                                              -------------------------    -----------------------------
                                                                    2003          2002             2003           2002
                                                              -------------------------    ----------------------------
Discount rate                                                      6.30%         6.60%            6.30%          6.60%
Rate of increase in future compensation - non-bargaining               -         4.00%                -              -
Rate of increase in future compensation - supplementary plan       5.00%         4.00%                -              -
Initial medical cost trend rate for pre-Medicare benefits              -             -            7.25%          7.50%
Initial medical cost trend rate for post-Medicare benefits             -             -            7.25%          7.50%
Ultimate medical cost trend rate                                       -             -            5.25%          5.25%
Year ultimate medical cost trend rate is achieved                      -             -             2009           2009
</TABLE>

     PEC's primary defined benefit retirement plan for non-bargaining  employees
     is a "cash  balance"  pension  plan as  defined  in EITF  Issue  No.  03-4.
     Therefore,  effective  December 31, 2003, PEC began to use the  traditional
     unit credit method for purposes of measuring the benefit obligation of this
     plan and will use that method to measure future  benefit  costs.  Under the
     traditional  unit credit method,  no assumptions  are included about future
     changes  in  compensation  and  the  accumulated   benefit  obligation  and
     projected benefit obligation are the same.

     The  following  weighted-average  actuarial  assumptions  were  used in the
     calculation of the net periodic cost:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                               Pension Benefits         Other Postretirement Benefits
                                                        ----------------------------    -------------------------------
                                                          2003      2002      2001        2003        2002       2001
                                                        ----------------------------    -------------------------------
Discount rate                                             6.60%     7.50%     7.50%        6.60%      7.50%       7.50%
Rate of increase in future compensation                   4.00%     4.00%     4.00%            -          -           -
Expected long-term rate of return on plan assets          9.25%     9.25%     9.25%        9.25%      9.25%       9.25%
Initial medical cost trend rate for pre-Medicare
benefits                                                      -         -         -        7.50%      7.50%       7.50%
Initial medical cost trend rate for post-Medicare
benefits                                                      -         -         -        7.50%      7.50%       7.50%
Ultimate medical cost trend rate                              -         -         -        5.25%      5.00%       5.00%
Year ultimate medical cost trend rate is achieved             -         -         -         2009       2008        2007
</TABLE>

     The expected  long-term  rates of return on plan assets were  determined by
     considering  long-term  historical  returns  for the  plans  and  long-term
     projected  returns  based on the plans'  target  asset  allocations.  Those
     benchmarks  support an expected  long-term  rate of return between 9.5% and
     10.0%. PEC has chosen to use an expected long-term rate of 9.25% due to the
     uncertainties of future returns.

     The medical  cost trend rates were assumed to decrease  gradually  from the
     initial rates to the ultimate rates.  Assuming a 1% increase in the medical
     cost trend rates, the aggregate of the service and interest cost components
     of the net periodic  OPEB cost for 2003 would  increase by $1 million,  and
     the OPEB  obligation at December 31, 2003,  would  increase by $18 million.
     Assuming a 1% decrease in the medical  cost trend rates,  the  aggregate of
     the service and interest cost  components of the net periodic OPEB cost for
     2003 would  decrease by $1 million and the OPEB  obligation at December 31,
     2003, would decrease by $15 million.

     In  December  2003,  the  Medicare   Prescription  Drug,   Improvement  and
     Modernization Act of 2003 (the Act) was signed into law. In accordance with
     guidance  issued by the FASB in FASB  Staff  Position  FAS  106-1,  PEC has
     elected to defer accounting for the effects of the Act due to uncertainties
     regarding the effects of the  implementation  of the Act and the accounting
     for certain provisions of the Act.  Therefore,  OPEB information  presented
     above and in the financial  statements  does not reflect the effects of the
     Act. When specific  authoritative  accounting  guidance is issued, it could
     require plan sponsors to change previously reported information.  PEC is in
     the early stages of reviewing the Act and determining its potential effects
     on PEC.

                                      151
<PAGE>

12.  Risk Management Activities and Derivatives Transactions

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

     A. Commodity Contracts - General

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

     In connection with the January 2003 EITF meeting, the FASB was requested to
     reconsider an interpretation of SFAS No. 133. The interpretation, which was
     contained in the Derivative Implementation Group's C11 guidance, related to
     the pricing of contracts that include broad market indices (e.g.,  CPI). In
     particular,  that guidance discussed 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  June  2003,  the  FASB  issued  final
     superseding  guidance  (DIG Issue C20) on this issue.  The new guidance was
     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 required a special transition adjustment as of October 1, 2003.

     PEC determined that it had one existing "normal" contract that was affected
     by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
     a pre-tax fair value loss transition adjustment of $38 million ($23 million
     after-tax)  in  the  fourth  quarter  of  2003,  which  was  recorded  as a
     cumulative effect of a change in accounting principle. The subject contract
     meets  the DIG  Issue  C20  criteria  for  normal  purchase  or  sale  and,
     therefore,  was designated as a normal  purchase as of October 1, 2003. The
     liability associated with the fair value loss will be amortized to earnings
     over the term of the related contract.

     B. Commodity Derivatives - Economic Hedges and Trading

     Nonhedging  derivatives,   primarily  electricity  forward  contracts,  are
     entered into for trading purposes and for economic hedging purposes.  While
     management  believes the economic hedges mitigate exposures to fluctuations
     in commodity  prices,  these  instruments  are not designated as hedges for
     accounting  purposes and are monitored  consistent with trading  positions.
     PEC manages open positions with strict  policies that limit its exposure to
     market  risk  and  require  daily  reporting  to  management  of  potential
     financial exposures. Gains and losses from such contracts were not material
     during  2003,  2002 or  2001,  and PEC did not  have  material  outstanding
     positions in such contracts at December 31, 2003 or 2002.

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

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

     PEC uses cash flow hedging  strategies to hedge variable  interest rates on
     long-term debt and to hedge interest rates with regard to future fixed-rate
     debt issuances.  PEC held no interest rate cash flow hedges at December 31,
     2003 or 2002. At December 31, 2003,  $1 million of net  after-tax  deferred
     losses in accumulated  other  comprehensive  income,  related to terminated
     hedges,  will be  reclassified to earnings during the next 12 months as the
     hedged interest payments occur.

     PEC uses fair value  hedging  strategies  to manage its  exposure  to fixed
     interest rates on long-term debt. At December 31, 2003 and 2002, PEC had no
     open interest rate fair value hedges.

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

                                      152
<PAGE>

13.  Related Party Transactions

     PEC participates in an internal money pool, operated by Progress Energy, to
     more  effectively  utilize cash resources and to reduce outside  short-term
     borrowings.  The money pool also is used to settle  intercompany  balances.
     The weighted-average  interest rate for the money pool was 1.47%, 2.18% and
     4.47% at December 31, 2003,  2002 and 2001,  respectively.  At December 31,
     2003,  PEC had $25  million of  amounts  payable to the money pool that are
     included  in notes  payable to  affiliated  companies  on the  Consolidated
     Balance  Sheets.  At  December  31,  2002,  PEC had $50  million of amounts
     receivable  from the money pool that are included in notes  receivable from
     affiliated  companies on the Consolidated  Balance Sheets. PEC recorded net
     interest  expense of approximately $1 million related to the money pool for
     2003 and 2002. Net interest expense for 2001 was not significant.

     The Company formed Progress Energy Service  Company,  LLC (PESC) to provide
     specialized  services,  at cost,  to the Company and its  subsidiaries,  as
     approved by the U.S.  Securities and Exchange  Commission (SEC). PEC has an
     agreement with PESC under which services, including purchasing, information
     technology,  telecommunications,   marketing,  treasury,  human  resources,
     accounting, real estate, legal and tax are rendered at cost. Amounts billed
     to PEC by PESC for these  services  during 2003,  2002 and 2001 amounted to
     $184 million, $198 million and $156 million,  respectively. At December 31,
     2003 and  2002,  PEC had net  payables  of $118  million  and $63  million,
     respectively, to PESC. During 2002, the Office of Public Utility Regulation
     within the SEC completed an audit  examination  of the Company's  books and
     records.  This examination is a standard process for all PUHCA registrants.
     Based on the review,  the method for  allocating  PESC costs to the Company
     and its affiliates  changed for 2003 and retroactive  reallocations of 2002
     and 2001  charges  were made during the first  quarter.  The net  after-tax
     impact of the  reallocation  of costs was a reduction of expenses at PEC by
     $10 million.

     The Company sold North Carolina Natural Gas Corporation  (NCNG) to Piedmont
     Natural Gas  Company,  Inc. on September  30, 2003.  During the years ended
     December  31, 2003,  2002 and 2001,  gas sales from NCNG to PEC amounted to
     $11 million, $18 million and $15 million,  respectively.  The gas sales for
     2003 indicated above exclude any sales subsequent to September 2003.

     PEC entered into a Tax Agreement with Progress Energy (See Note 10).

     In February 2002,  PEC  transferred  the Rowan Plant to Progress  Ventures,
     Inc. The property and  inventory  transferred  totaled  approximately  $244
     million.

     In August 2002, PEC transferred reservation payments for the manufacture of
     two combustion turbines to PEF at PEC's original cost of $20 million.

14.  Financial Information by Business Segment

     PEC's  operations  consist  primarily of the PEC Electric  segment which is
     engaged in the generation, transmission,  distribution and sale of electric
     energy  primarily in portions of North Carolina and South  Carolina.  These
     electric  operations are subject to the rules and  regulations of the FERC,
     the NCUC, the SCPSC and the NRC.

     The Other segment,  whose operations are primarily in the United States, is
     made up of other nonregulated  business areas including  telecommunications
     and  other  nonregulated  subsidiaries  that  do not  separately  meet  the
     disclosure  requirements of SFAS No. 131, "Disclosures about Segments of an
     Enterprise  and  Related   Information"  and  consolidation   entities  and
     eliminations.  Included are the operations of Caronet,  which recognized an
     $87  million  after-tax  asset  and  investment  impairment  in 2002 and an
     after-tax investment impairment of $107 million in 2001.


                                      153
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(In millions)                              PEC Electric          Other              Total
------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Revenues                                     $  3,589            $   11           $  3,600
Depreciation and amortization                     562                 1                563
Total interest charges, net                       194                 -                194
Impairment of long-lived assets &
    investments                                    11                10                 21
Income taxes                                      240                 4                244
Income before cumulative effect                   515               (13)               502
Total segment assets                           10,854               154             11,008
Capital and investment
    expenditures                                  470                 1                471
------------------------------------------------------------------------------------------------

Year Ended December 31, 2002

Revenues                                     $  3,539            $   15           $  3,554
Depreciation and amortization                     524                 4                528
Total interest charges, net                       212                 -                212
Impairment of long-lived assets &
    investments                                     -               126                126
Income taxes                                      237               (30)               207
Income before cumulative effect                   513               (85)               428
Total segment assets                           10,139               266             10,405
Capital and investment
    expenditures                                  624                12                636
------------------------------------------------------------------------------------------------

Year Ended December 31, 2001

Revenues                                     $  3,344            $   16           $  3,360
Depreciation and amortization                     522                 7                529
Total interest charges, net                       241                 -                241
Impairment of long-lived assets &
    investments                                     -               157                157
Income taxes                                      264               (41)               223
Income before cumulative effect                   468              (107)               361
Capital and investment
    expenditures                                  824                13                837
------------------------------------------------------------------------------------------------
</TABLE>

15.  Other Income and Other Expense

     Other  income and expense  includes  interest  income,  gain on the sale of
     investments,  impairment of investments  and other income and expense items
     as  discussed  below.  The  components  of  other,  net  as  shown  on  the
     Consolidated  Statements of Income and Comprehensive Income for years ended
     December 31, are as follows:

                                      154
<PAGE>
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)                                               2003         2002         2001
                                                            ----         ----         ----
Other income
Net financial trading gain (loss)                           $  (1)       $  (2)       $   3
Net energy brokered for resale gain                             2            1            3
Nonregulated energy and delivery services income                8           12           12
Investment gains                                                9           22            2
AFUDC equity                                                    2            6            9
Other                                                          12           21           13
                                                       ---------------------------------------
    Total other income                                      $  32        $  60        $  42
                                                       ---------------------------------------

Other expense
Nonregulated energy and delivery services expenses          $   9        $  14        $  21
Donations                                                       6            8           11
Investment losses                                              12           14            4
Other                                                          16           11           10
                                                       ---------------------------------------
   Total other expense                                      $  43        $  47        $  46
                                                       ---------------------------------------

Other, net                                                  $ (11)       $  13        $  (4)
                                                       =======================================
</TABLE>

     Net financial  trading gain (loss)  represents  non-asset-backed  trades of
     electricity  and gas.  Nonregulated  energy and delivery  services  include
     power  protection  services  and mass market  programs  (surge  protection,
     appliance  services and area light sales) and  delivery,  transmission  and
     substation work for other utilities.

16.  Commitments and Contingencies

     A. Purchase Obligations

     The following table reflects PEC's  contractual  cash obligations and other
     commercial commitments in the respective periods in which they are due.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

(in millions)
Contractual Cash Obligations       2004          2005        2006         2007        2008   Thereafter
-------------------------------------------------------------------------------------------------------
Fuel                              $ 433        $ 244       $ 195        $  96       $  33       $   73
Purchased power                     110          110         110          110          74          474
Construction Obligations              5            -           -            -           -            -
Other Purchase Obligations            -            -           -            -           -           13
-------------------------------------------------------------------------------------------------------
Total                             $ 548        $ 354       $ 305        $ 206       $ 107       $  560
</TABLE>

     Fuel and Purchased Power

     PEC has entered  into various  long-term  contracts  for coal,  gas and oil
     requirements  of  its  generating   plants.   Total  payments  under  these
     commitments were $498 million,  $529 million and $496 million in 2003, 2002
     and 2001,  respectively.  Estimated annual payments for firm commitments of
     fuel  purchases  and   transportation   costs  under  these  contracts  are
     approximately $433 million, $244 million, $195 million, $96 million and $33
     million for 2004  through  2008,  respectively,  with $73  million  payable
     thereafter.

     Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
     between PEC and the North Carolina  Eastern  Municipal  Power Agency (Power
     Agency),  PEC is  obligated  to  purchase a  percentage  of Power  Agency's
     ownership  capacity of, and energy from, the Harris Plant. In 1993, PEC and
     Power Agency  entered into an  agreement to  restructure  portions of their
     contracts  covering  power  supplies and  interests in jointly owned units.
     Under the terms of the 1993 agreement, PEC increased the amount of capacity
     and energy purchased from Power Agency's  ownership  interest in the Harris
     Plant,  and the buyback  period was extended six years  through  2007.  The
     estimated  minimum  annual  payments  for these  purchases,  which  reflect
     capacity  costs,  total   approximately  $36  million.   These  contractual
     purchases  totaled $36 million,  $36 million and $33 million for 2003, 2002
     and 2001,  respectively.  In 1987,  the NCUC  ordered  PEC to  reflect  the
     recovery of the capacity  portion of these costs on a levelized  basis over
     the original 15-year buyback period,  thereby deferring for future recovery
     the difference  between such costs and amounts  collected through rates. In
     1988, the SCPSC ordered similar treatment,  but with a 10-year levelization
     period.  At December 31, 2002, PEC had deferred  purchased  capacity costs,
     including  carrying costs accrued on the deferred  balances of $17 million.
     At December 31, 2003 all previously deferred costs have been expensed.

                                      155
<PAGE>

     PEC has a  long-term  agreement  for the  purchase  of  power  and  related
     transmission  services from Indiana Michigan Power Company's  Rockport Unit
     No. 2  (Rockport).  The  agreement  provides  for the purchase of 250 MW of
     capacity   through  2009  with  estimated   minimum   annual   payments  of
     approximately  $42 million,  representing  capital-related  capacity costs.
     Estimated  annual payments for energy and capacity costs are  approximately
     $70  million   through  2009.   Total  purchases   (including   energy  and
     transmission  use  charges)  under the Rockport  agreement  amounted to $66
     million, $59 million and $63 million for 2003, 2002 and 2001, respectively.

     Effective June 1, 2001, PEC executed a long-term agreement for the purchase
     of power from Skygen Energy LLC's Broad River facility  (Broad River).  The
     agreement  provides  for the purchase of  approximately  500 MW of capacity
     through 2021 with an original minimum annual payment of  approximately  $16
     million, primarily representing  capital-related capacity costs. A separate
     long-term agreement for additional power from Broad River commenced June 1,
     2002. This agreement provided for the additional  purchase of approximately
     300 MW of capacity  through 2022 with an original minimum annual payment of
     approximately  $16 million  representing  capital-related  capacity  costs.
     Total purchases under the Broad River  agreements  amounted to $37 million,
     $38 million, and $21 million in 2003, 2002 and 2001 respectively.

     PEC has various pay-for-performance  purchased power contracts with certain
     cogenerators  (qualifying  facilities) for approximately 400 MW of capacity
     expiring at various times through 2009.  These  purchased  power  contracts
     generally  provide for  capacity  and energy  payments.  Payments  for both
     capacity  and  energy are  contingent  upon the QFs'  ability to  generate.
     Payments  made under  these  contracts  were $118  million in 2003 and $145
     million in 2002 and 2001.

     Construction Obligations

     PEC  has  purchase  obligations  for  various  combustion  turbines.  Total
     purchases under these obligations were $21 million for 2003 and $13 million
     for 2002. Future purchase obligations are $5 million for 2004.

     Other Contractual Obligations

     On December 31, 2002, PEC entered into a contractual commitment to purchase
     at least $13 million of capital parts by December 31, 2010. At December 31,
     2003 no capital parts have been purchased under this contract.

     B. Leases

     PEC  leases  office  buildings,  computer  equipment,  vehicles,  and other
     property  and  equipment  with various  terms and  expiration  dates.  Rent
     expense under  operating  leases  totaled $11 million,  $10 million and $22
     million  for  2003,  2002 and 2001,  respectively.  Assets  recorded  under
     capital leases consist of:

     (in millions)                               2003         2002
                                                 ----         ----
     Buildings                                  $   30       $   28
     Less:  Accumulated amortization               (10)         (10)
                                             -----------    ----------
                                                $   20       $   18
                                             ===========    ==========

                                      156

<PAGE>

     Minimum annual rental payments,  excluding executory costs such as property
     taxes, insurance and maintenance,  under long-term  noncancelable leases at
     December 31, 2003 are:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

     (in millions)                                   Capital Leases      Operating Leases
                                                     --------------      ----------------
     2004                                                  $  2              $   6
     2005                                                     2                  9
     2006                                                     2                  6
     2007                                                     2                  6
     2008                                                     2                  6
     Thereafter                                              25                102
                                                     --------------      ----------------
                                                           $ 35              $ 135
                                                                         ================
     Less amount representing imputed interest              (15)
                                                     --------------
     Present value of net minimum lease payments           $ 20
                                                     ==============
</TABLE>

     PEC is the lessor of electric  poles,  streetlights  and other  facilities.
     Rents  received  are  contingent  upon usage and totaled $31  million,  $28
     million and $31 million for 2003, 2002 and 2001, respectively.

     C. Guarantees

     As a part of normal business,  PEC enters into various agreements providing
     financial or  performance  assessments to third  parties.  Such  agreements
     include,  for  example,  guarantees,  standby  letters of credit and surety
     bonds.  These  agreements  are entered into primarily to support or enhance
     the creditworthiness  otherwise attributed to subsidiaries on a stand-alone
     basis,   thereby   facilitating  the  extension  of  sufficient  credit  to
     accomplish the subsidiaries'  intended commercial purposes. At December 31,
     2003,  management  does not believe  conditions are likely for  performance
     under these agreements.

     At December 31, 2003, outstanding guarantees consisted of the following:

     (in millions)
     Standby letters of credit          $   3
     Surety bonds                          19
                                    ------------
        Total                           $ 22
                                    ============

     Standby Letters of Credit
     PEC has issued standby letters of credit to financial  institutions for the
     benefit  of third  parties  that have  extended  credit to PEC 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 on interest  payments on outstanding debt  obligations.
     If a subsidiary does not pay amounts when due under a covered contract, the
     counterparty   may  present   its  claim  for  payment  to  the   financial
     institution,  which will in turn request payment from PEC. Any amounts owed
     by its subsidiaries are reflected in the Consolidated Balance Sheets.

     Surety Bonds
     At  December  31,  2003,  PEC had $19  million  in surety  bonds  purchased
     primarily for purposes such as providing workers' compensation coverage and
     obtaining  licenses,  permits and rights-of-way.  To the extent liabilities
     are  incurred as a result of the  activities  covered by the surety  bonds,
     such liabilities are included in the Consolidated Balance Sheets.

     Guarantees Issued by the Parent
     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.

     D. Claims and Uncertainties

     1. PEC is  subject  to  federal,  state  and local  regulations  addressing
     hazardous  and solid  waste  management,  air and water  quality  and other
     environmental matters.

                                      157
<PAGE>

     Hazardous and Solid Waste Management

     Various  organic  materials  associated with the production of manufactured
     gas,  generally  referred to as coal tar, are  regulated  under federal and
     state laws.  The  principal  regulatory  agency that is  responsible  for a
     specific former  manufactured gas plant (MGP) site depends largely upon the
     state in which the site is  located.  There are  several MGP sites to which
     PEC  has  some  connection.  In this  regard,  PEC  and  other  potentially
     responsible  parties (PRPs) are  participating  in,  investigating  and, if
     necessary,  remediating former MGP sites with several regulatory  agencies,
     including,  but not limited to, the U.S.  Environmental  Protection  Agency
     (EPA)  and  the  North  Carolina  Department  of  Environment  and  Natural
     Resources,  Division  of  Waste  Management  (DWM).  In  addition,  PEC  is
     periodically  notified  by  regulators  such as the EPA and  various  state
     agencies of its involvement or potential  involvement in sites,  other than
     MGP sites, that may require investigation and/or remediation.

     There are nine  former MGP sites and other 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.  At December 31, 2003,
     approximately  $9 million remains in this  centralized  fund with a related
     accrual of $9 million recorded for the associated expenses of environmental
     issues.  PEC  does not  believe  that it can  provide  an  estimate  of the
     reasonably  possible  total  remediation  costs  beyond  what is  currently
     accrued due to the fact that  investigations have not been completed at all
     sites.  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 PRPs. 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 any of these MGP
     sites.

     In September  2003, the Company sold NCNG to Piedmont  Natural Gas Company,
     Inc. As part of the sales agreement, the Company retained responsibility to
     remediate five former NCNG MGP sites, all of which also are associated with
     PEC, to state  standards  pursuant to an  Administrative  Order by consent.
     These sites are  anticipated to have  investigation  or  remediation  costs
     associated with them. NCNG had previously accrued  approximately $2 million
     for probable and  reasonably  estimable  remediation  costs at these sites.
     These accruals have been recorded on an undiscounted  basis. At the time of
     the sale,  the  liability  for  these  costs and the  related  accrual  was
     transferred  to PEC. PEC does not believe it can provide an estimate of the
     reasonably  possible  total  remediation  costs beyond the accrual  because
     investigations have not been completed at all sites. Therefore,  PEC cannot
     currently determine the total costs that may be incurred in connection with
     the investigation and/or 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.
     All  claims  have  settled  other  than  with  insolvent  carriers.   These
     settlements  have not had 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 NOx, SO2, 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.


                                      158
<PAGE>

     The EPA is  conducting  an  enforcement  initiative  related to a number of
     coal-fired   utility  power  plants  in  an  effort  to  determine  whether
     modifications  at  those  facilities  were  subject  to New  Source  Review
     requirements or New Source  Performance  Standards under the Clean Air Act.
     PEC was asked to provide  information to the EPA as part of this initiative
     and  cooperated in providing the requested  information.  The EPA initiated
     civil enforcement  actions against other unaffiliated  utilities as part of
     this initiative.  Some of these actions  resulted in settlement  agreements
     calling for expenditures by these unaffiliated utilities, 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. PEC cannot predict the outcome of this matter.

     In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
     addressing the regional  transport of ozone (NOx SIP Call).  The EPA's rule
     requires 23  jurisdictions,  including North  Carolina,  South Carolina and
     Georgia, to further reduce NOx emissions in order to attain a pre-set state
     NOx (NOx)  emission  level by May 31,  2004.  PEC is  currently  installing
     controls  necessary to comply with the rule.  Capital  expenditures to meet
     these measures in North and South Carolina could reach  approximately  $370
     million,  which  has  not  been  adjusted  for  inflation.  PEC  has  spent
     approximately $258 million to date related to these expenditures. Increased
     operation  and  maintenance  costs  relating  to the NOx SIP  Call  are not
     expected to be material to 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 8-hour
     ozone standard.  In October 1999, the District of Columbia Circuit Court of
     Appeals  ruled  against  the EPA with regard to the  federal  8-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 8-hour ozone standard and is proceeding  with
     the   implementation   process.   North  Carolina  has  promulgated   final
     regulations,  which will  require  PEC to install  NOx  controls  under the
     State's  8-hour  standard.  The costs of those controls are included in the
     $370 million cost estimate above.  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 NOx  emissions by May 1, 2003.  The final rule also
     includes a set of  regulations  that  affect  NOx  emissions  from  sources
     included  in  the  petitions.   The  North  Carolina   coal-fired  electric
     generating  plants are included in these petitions.  Acceptable state plans
     under the NOx SIP Call can be  approved  in lieu of the final rules the EPA
     approved  as  part  of the  126  petitions.  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 NOx 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 indicated it will rescind the Section 126 rule in
     a future rulemaking. PEC expects a favorable outcome of this matter.

     In June 2002,  legislation  was  enacted in North  Carolina  requiring  the
     state's  electric  utilities  to reduce the  emissions  of NOx and SO2 from
     coal-fired  power  plants.  PEC  expects  its  capital  costs to meet these
     emission  targets  will be  approximately  $813  million  by 2013.  PEC has
     expended  approximately $30 million of these capital costs through December
     31, 2003. 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

                                      159
<PAGE>

     at least 70% of their  projected  capital costs during the  five-year  rate
     freeze period.  Pursuant to the law, PEC entered into an agreement with the
     state of North  Carolina  to  transfer  to the state all  future  emissions
     allowances  it  generates  from  over-complying  with the federal  emission
     limits when these units are  completed.  The law also requires the state to
     undertake  a study  of  mercury  and  carbon  dioxide  emissions  in  North
     Carolina.  Operation  and  maintenance  costs  will  increase  due  to  the
     additional personnel, materials and general maintenance associated with the
     equipment.  Operation and maintenance expenses are recoverable through base
     rates,  rather than as part of this program.  PEC cannot predict the future
     regulatory interpretation, implementation or impact of this law.

     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.  In 2003, the EPA proposed two alternative  control plans that
     would limit mercury  emissions from coal-fired  power plants.  The first, a
     Maximum  Available Control  Technology (MACT) standard  applicable to every
     coal-fired plant,  would require compliance in 2008. The second, a national
     mercury  cap and  trade  program,  would  require  limits  to be met in two
     phases,  2010 and 2018.  The mercury  rule is  expected to become  final in
     December  2004.  Achieving  compliance  with either  proposal could involve
     significant  capital  costs which  could be material to PEC's  consolidated
     financial position or results of operations. PEC cannot predict the outcome
     of this matter.

     In conjunction with the proposed mercury rule, the EPA proposed to regulate
     nickel  emissions from residual  oil-fired  units. The agency estimates the
     proposal will reduce national nickel emissions to  approximately  103 tons.
     The rule is expected to become final in December 2004.

     In December 2003, the EPA released its proposed Interstate Air Quality Rule
     (commonly known as the Fine Particulate  Transport Rule and/or the Regional
     Transport Rule). The EPA's proposal  requires 28  jurisdictions,  including
     North Carolina, South Carolina,  Georgia and Florida, to further reduce NOx
     and SO2 emissions in order to attain  pre-set NOx and SO2 emissions  levels
     (which have not yet been determined).  The rule is expected to become final
     in 2004.  The  installation  of controls  necessary to comply with the rule
     could involve significant capital costs.

     Water Quality

     As a result of the operation of certain control equipment needed to address
     the air quality  issues  outlined  above,  new  wastewater  streams will be
     generated at the applicable facilities. Integration of these new wastewater
     streams  into the existing  wastewater  treatment  processes  may result in
     permitting,  construction and treatment  challenges to PEC in the immediate
     and extended future.

     After  many  years  of  litigation  and  settlement  negotiations  the  EPA
     published  regulations in February 2004 for the  implementation  of Section
     316(b) of the Clean  Water  Act.  The  purpose of these  regulations  is to
     minimize  adverse  environmental  impacts  caused by cooling  water  intake
     structures  and  intake   systems.   Over  the  next  several  years  these
     regulations will impact the larger base load generation  facilities and may
     require the  facilities  to mitigate  the effects to aquatic  organisms  by
     constructing   intake   modifications  or  undertaking   other  restorative
     activities.  Substantial costs could be incurred by the facilities in order
     to comply with the new  regulation.  The Company cannot predict the outcome
     and impacts to the facilities at this time.

     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 PEC's  consolidated
     financial  position or results of 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.

     2. 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.

                                      160
<PAGE>

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

     After the DOE failed to comply with the decision in Indiana  Michigan Power
     v. DOE, a group of  utilities  petitioned  the Court of Appeals in Northern
     States  Power  (NSP) v. DOE,  seeking an order  requiring  the DOE to begin
     taking spent  nuclear  fuel by January 31, 1998.  The DOE took the position
     that its delay was  unavoidable,  and the DOE was excused from  performance
     under the terms and  conditions of the  contract.  The Court of Appeals did
     not order the DOE to begin  taking  spent  nuclear  fuel,  stating that the
     utilities had a potentially  adequate  remedy by filing a claim for damages
     under the contract.

     After the DOE failed to begin  taking  spent  nuclear  fuel by January  31,
     1998,  a group of  utilities  filed a motion  with the Court of  Appeals to
     enforce the mandate in NSP v. DOE.  Specifically,  this group of  utilities
     asked the Court to permit the utilities to escrow their waste fee payments,
     to order the DOE not to use the waste fund to pay damages to the utilities,
     and to order the DOE to establish a schedule for disposal of spent  nuclear
     fuel.  The Court denied this motion  based  primarily on the grounds that a
     review of the matter was premature, and that some of the requested remedies
     fell outside of the mandate in NSP v. DOE.

     Subsequently, a number of utilities each filed an action for damages in the
     Federal  Court of  Claims.  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.

     On January 14, 2004,  PEC filed a complaint with the United States Court of
     Federal Claims against the United States of America  (Department of Energy)
     claiming that the DOE breached the Standard  Contract for Disposal of Spent
     Nuclear Fuel by failing to accept spent nuclear fuel from various  Progress
     Energy  facilities  on or before  January  31,  1998.  Damages due to DOE's
     breach will likely exceed $100 million.  Similar suits have been  initiated
     by over two dozen other utilities.

     In July 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. On November
     5, 2003,  Congressional  negotiators  approved $580 million for fiscal year
     2004 for the Yucca  Mountain  project,  $123 million more than the previous
     year. 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  to  the  expiration  of  these  licenses,  dry  storage  may be
     necessary.  PEC obtained NRC  approval in December  2000 to use  additional
     storage space at the Harris Plant.

     3. In August 2003,  PEC was served as a co-defendant  in a purported  class
     action  lawsuit  styled as Collins v. Duke Energy  Corporation et al, Civil
     action No.  03CP404050,  in South Carolina's  Circuit Court of Common Pleas
     for the Fifth  Judicial  Circuit.  PEC is one of three  electric  utilities
     operating in South  Carolina  named in the suit. The plaintiffs are seeking
     damages for the alleged  improper  use of electric  easements  but have not
     asserted a dollar amount for their damage  claims.  The  complaint  alleges
     that the licensing of  attachments on electric  utility  poles,  towers and
     other  structures  to  non-utility   third  parties  or   telecommunication
     companies  for other than the  electric  utilities'  internal use along the
     electric right-of-way constitutes a trespass.

     In  September  2003,  PEC  filed a motion  to  dismiss  all  counts  of the
     complaint on  substantive  and  procedural  grounds.  In October 2003,  the
     plaintiffs  filed a motion  to amend  their  complaint.  PEC  believes  the
     amended  complaint  asserts  the  same  factual  allegations  as are in the
     original complaint and also seeks money damages and injunctive relief.

     The court has not yet held any  hearings  or made any rulings in this case.
     In  November  2003,  PEC filed a motion to dismiss  the  plaintiffs'  first
     amended  complaint.  PEC cannot  predict the outcome of the outcome of this
     matter, but will vigorously defend against the allegations.

                                      161
<PAGE>

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

                                      162
<PAGE>

INDEPENDENT AUDITORS' REPORT

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

We have audited the consolidated balance sheets of Progress Energy, Inc. and its
subsidiaries  at  December  31,  2003 and  2002,  and the  related  consolidated
statements of income,  changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2003 and have issued our report
thereon  dated  February 20, 2004 (which  expresses an  unqualified  opinion and
includes an  explanatory  paragraph  concerning  the adoption of new  accounting
principles in 2003 and 2002); such consolidated  financial statements and report
are  included  herein.  Our audits  also  included  the  consolidated  financial
statement schedule of the Company, listed in Item 8. This consolidated financial
statement  schedule  is the  responsibility  of the  Company's  management.  Our
responsibility  is to express an opinion  based on our audits.  In our  opinion,
such consolidated  financial statement schedule,  when considered in relation to
the basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.


/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004

                                      163
<PAGE>

INDEPENDENT AUDITORS' REPORT

TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:

We have  audited  the  consolidated  balance  sheets of  Carolina  Power & Light
Company d/b/a Progress  Energy  Carolinas,  Inc. and its  subsidiaries  (PEC) at
December 31, 2003 and 2002,  and the related  consolidated  statements of income
and  comprehensive  income,  retained  earnings,  and cash flows for each of the
three  years in the period  ended  December  31, 2003 and have issued our report
thereon  dated  February  20, 2004  (which  express an  unqualified  opinion and
includes an  explanatory  paragraph  concerning  the adoption of new  accounting
principles  in 2003);  such  consolidated  financial  statements  and report are
included herein. Our audits also included the consolidated  financial  statement
schedule of PEC listed in Item 8. This consolidated financial statement schedule
is the  responsibility of PEC's management.  Our responsibility is to express an
opinion  based  on our  audits.  In our  opinion,  such  consolidated  financial
statement  schedule,   when  considered  in  relation  to  the  basic  financial
statements  taken as a whole,  presents  fairly  in all  material  respects  the
information set forth therein.


/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004


                                      164
<PAGE>

                              PROGRESS ENERGY, INC.
                     Schedule II - Valuation and Qualifying
                    Accounts For the Years Ended December 31,
                               2003, 2002 and 2001

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

                               Balance at         Additions                                               Balance at
                                Beginning         Charged to           Other                                End of
        Description             of Period          Expenses          Additions         Deductions           Period
-------------------------------------------------------------------------------------------------------------------------

Year Ended
   December 31, 2003

 Uncollectible accounts           $ 40              $ 26               $  -            $ (38)  (a)           $  28
 Fossil dismantlement
   reserve                         142                 1                  -                 -                  143
 Nuclear refueling
   outage reserve                   10                 8                  -              (16)  (b)               2


Year Ended
   December 31, 2002

 Uncollectible accounts           $ 39              $ 15               $  -            $ (14)  (a)           $  40
 Fossil dismantlement
   reserve                         141                 1                  -                -                   142
 Nuclear refueling
   outage reserve                    -                10                  -                -                    10


Year Ended
   December 31, 2001

 Uncollectible accounts           $ 26              $ 12               $ 20  (c)       $ (19)  (a)           $  39
 Fossil dismantlement
   reserve                         135                 6                  -                -                   141
 Nuclear refueling
   outage reserve                   11                17                  -              (28)  (b)               -





(a) Represents write-off of uncollectible accounts, net of recoveries.
(b) Represents payments of actual expenditures related to the outages.
(c) Represents the reclassification of Rail Services' uncollectible accounts
    from Net Assets Held for Sale.

--------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      165
<PAGE>

                         CAROLINA POWER & LIGHT COMPANY
                         d/b/a PROGRESS ENERGY CAROLINAS
                     Schedule II - Valuation and Qualifying
                    Accounts For the Years Ended December 31,
                               2003, 2002 and 2001

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

                                 Balance at        Additions                                              Balance at
                                 Beginning        Charged to          Other                                 End of
         Description             of Period          Expense         Additions         Deductions            Period
----------------------------------------------------------------------------------------------------------------------

Year Ended
   December 31, 2003

  Uncollectible accounts           $ 11              $ 12              $  -             $ (10)  (a)          $  13


Year Ended
   December 31, 2002

  Uncollectible accounts           $ 12              $  8              $  -             $  (9)  (a)          $  11


Year Ended
   December 31, 2001

  Uncollectible accounts           $ 17              $  4              $  -             $  (9)  (a)          $  12




(a) Represents write-off of uncollectible accounts, net of recoveries.
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      166
<PAGE>

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

None

ITEM 9A.   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 its  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  Chief  Executive  Officer  and Chief  Financial
Officer  concluded that its disclosure  controls and procedures are effective in
timely  alerting  them to  material  information  relating  to  Progress  Energy
(including  its  consolidated  subsidiaries)  required  to be  included  in  its
periodic SEC filings.

There has been no change in Progress  Energy's  internal  control over financial
reporting  during  the  quarter  ended  December  31,  2003 that has  materially
affected, or is reasonably likely to materially affect its 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 its 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  Chief  Executive
Officer and Chief Financial Officer  concluded that its disclosure  controls and
procedures  are  effective  in  timely  alerting  them to  material  information
relating  to  PEC  (including  its  consolidated  subsidiaries)  required  to be
included in its periodic SEC filings.

There has been no change in PEC's  internal  control  over  financial  reporting
during the quarter ended December 31, 2003 that has materially  affected,  or is
reasonably  likely to  materially  affect its internal  control  over  financial
reporting.


                                      167
<PAGE>

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

a)   Information  on  Progress  Energy,  Inc.'s  directors  is set  forth in the
     Progress Energy 2003  definitive  proxy statement dated March 31, 2004, and
     incorporated  by reference  herein.  Information on PEC's  directors is set
     forth in the PEC 2003 definitive  proxy statement dated March 31, 2004, and
     incorporated by reference herein.

b)   Information on both Progress  Energy's and PEC's executive  officers is set
     forth in PART I and incorporated by reference herein.

c)   The  Company  has  adopted  a Code of  Ethics  that  applies  to all of its
     employees,  including its Chief Executive Officer, Chief Financial Officer,
     Chief  Accounting  Officer and  Controller (or persons  performing  similar
     functions). The Company's Board of Directors has adopted the Company's Code
     of Ethics as its own standard.  Board members, Company officers and Company
     employees  certify  their  compliance  with the Code of Ethics on an annual
     basis.  The Company's Code of Ethics is posted on its Internet  website and
     can be accessed at www.progress-energy.com and is available in print to any
     shareholder upon request by writing to Progress Energy, Inc.

     The Company intends to satisfy the disclosure  requirement under Item 10 of
     Form 8-K relating to  amendments  to or waivers  from any  provision of the
     Code of Ethics  applicable to the Company's CEO, CFO, CAO and Controller by
     posting such information on its Internet website, www.progress-energy.com.

d)   The Board of Directors  has  determined  that David L. Burner and Carlos A.
     Saladrigas  are the "Audit  Committee  Financial  Experts"  as that term is
     defined in the rules promulgated by the Securities and Exchange  Commission
     pursuant to the  Sarbanes-Oxley  Act of 2002, and have  designated  them as
     such. Both Mr. Burner and Mr.  Saladrigas are "independent" as that term is
     defined  in the  general  independence  standards  of the  New  York  Stock
     Exchange listing standards.

e)   The following are available on the Company's  website and in print:

     o    Audit Committee Charter
     o    Corporate Governance Committee Charter
     o    Organization and Compensation Committee Charter
     o    Corporate Governance Guidelines

ITEM 11.   EXECUTIVE COMPENSATION

Information  on Progress  Energy's  executive  compensation  is set forth in the
Progress  Energy 2003  definitive  proxy  statement  dated March 31,  2004,  and
incorporated by reference herein. Information on PEC's executive compensation is
set forth in the PEC 2003  definitive  proxy statement dated March 31, 2004, and
incorporated by reference herein.

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

a)   Information regarding any person Progress Energy knows to be the beneficial
     owner of more than five (5%) percent of any class of its voting  securities
     is set forth in its 2003 definitive proxy statement,  dated March 31, 2004,
     and incorporated herein by reference.

     Information  regarding any person PEC knows to be the  beneficial  owner of
     more than five (5%)  percent of any class of its voting  securities  is set
     forth in its 2003  definitive  proxy  statement,  dated March 31, 2004, and
     incorporated herein by reference.

b)   Information  on  security  ownership  of the  Progress  Energy's  and PEC's
     management  is set forth in the  Progress  Energy  and PEC 2003  definitive
     proxy  statements  dated March 31,  2004,  and  incorporated  by  reference
     herein.

                                      168
<PAGE>

c)   Information  on the equity  compensation  plans of  Progress  Energy is set
     forth under the  heading  "Equity  Compensation  Plan  Information"  in the
     Progress  Energy 2003  definitive  proxy statement dated March 31, 2004 and
     incorporated by reference herein.

ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information on certain  relationships  and related  transactions is set forth in
the Progress Energy and PEC 2003  definitive  proxy  statements  dated March 31,
2004, and incorporated by reference herein.

ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information regarding principal accountant fees and services is set forth in the
Progress Energy and PEC 2003 definitive  proxy  statements dated March 31, 2004,
and incorporated by reference herein.


                                       169
<PAGE>

                                     PART IV


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

     a)   The following documents are filed as part of the report:

          1.  Consolidated  Financial  Statements  Filed:
                    See ITEM 8 -  Consolidated Financial Statements and
                                  Supplementary Data

          2.  Consolidated Financial Statement Schedules Filed:
                    See ITEM 8 - Consolidated Financial Statements and
                                 Supplementary Data

          3.  Exhibits Filed:
                    See EXHIBIT INDEX

     b)   Reports on Form 8-K or Form 8-K/A  filed or  furnished  during or with
          respect  to the last  quarter  of 2003 and the  portion  of the  first
          quarter of 2004 prior to the filing of this Form 10-K:

          Progress Energy, Inc.
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                          Financial
            Item          Statements
          Reported         Included             Date of Event                Date Filed
          --------         --------             -------------                ----------
             12              Yes               February 26, 2004           February 26, 2004
              5              No                February 24, 2004           February 24, 2004
              5              No                January 23, 2004            January 23, 2004
           9, 12             Yes               January 21, 2004            January 21, 2004
           7, 9              Yes               December 1, 2003            December 1, 2003
           9, 12             Yes               October 22, 2003            October 22, 2003


          Progress Energy Carolinas, Inc.

                          Financial
            Item          Statements
          Reported         Included             Date of Event                Date Filed
          --------         --------             -------------                ----------
             12              Yes               February 26, 2004           February 26, 2004
              5              No                January 23, 2004            January 23, 2004
           9, 12             Yes               January 21, 2004            January 21, 2004
           9, 12             Yes               October 22, 2003            October 22, 2003
</TABLE>


                                      170
<PAGE>

PROGRESS ENERGY, INC. RISK FACTORS

In this section,  unless the context indicates  otherwise,  references to "our,"
"we," "us" or similar terms refer to Progress Energy,  Inc. and its consolidated
subsidiaries.  Investing in our securities  involves risks,  including the risks
described below,  that could affect the energy  industry,  as well as us and our
business.  Although we have tried to discuss key  factors,  please be aware that
other risks may prove to be important in the future. New risks may emerge at any
time and we cannot  predict  such risks or estimate the extent to which they may
affect our financial performance.  Before purchasing our securities,  you should
carefully  consider the following risks and the other information in this Annual
Report, as well as the documents we file with the SEC from time to time. Each of
the  risks  described  below  could  result  in a  decrease  in the value of our
securities and your investment therein.

Risks Related to the Energy Industry

We are  subject  to fluid and  complex  government  regulations  that may have a
negative impact on our business and our results of operations.

We are subject to comprehensive  regulation by several federal,  state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers.  We are required
to have  numerous  permits,  approvals and  certificates  from the agencies that
regulate  our  business.  We  believe  the  necessary  permits,   approvals  and
certificates  have  been  obtained  for our  existing  operations  and  that our
business is conducted in accordance with applicable laws; however, we are unable
to  predict  the impact on our  operating  results  from the  future  regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional   regulations  could  have  an  adverse  impact  on  our  results  of
operations.

The 108th  Congress spent much of 2003 working on a  comprehensive  energy bill.
While  that  legislation  passed  the  House,  the  Senate  failed  to pass  the
legislation  in  2003.  There  will  probably  be an  effort  to  resurrect  the
legislation in 2004. The  legislation  would have further  clarified the Federal
Energy  Regulatory  Commission's  (FERC) role with  respect to  Standard  Market
Design and mandatory Regional  Transmission  Organizations (RTOs) and would have
repealed PUHCA. The Company cannot predict the outcome of this matter.

The Federal Energy Regulatory  Commission ("FERC"),  the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental  Protection Agency ("EPA"), the North
Carolina Utilities  Commission  ("NCUC"),  the Florida Public Service Commission
("FPSC"), and the Public Service Commission of South Carolina ("SCPSC") regulate
many aspects of our utility  operations,  including  siting and  construction of
facilities,  customer  service and the rates that we can charge  customers.  Our
system is also subject to the  jurisdiction  of the SEC under the Public Utility
Holding  Company Act of 1935 ("PUHCA").  The rules and  regulations  promulgated
under PUHCA impose a number of  restrictions  on the  operations  of  registered
utility holding companies and their subsidiaries.  These restrictions  include a
requirement that, subject to a number of exceptions,  the SEC approve in advance
securities  issuances,  acquisitions  and  dispositions  of utility assets or of
securities of utility  companies,  and acquisitions of other  businesses.  PUHCA
also generally  limits the operations of a registered  holding company like ours
to a single  integrated  public utility system,  plus additional  energy-related
businesses.   Furthermore,   PUHCA  rules  require  that  transactions   between
affiliated  companies in a  registered  holding  company  system be performed at
cost, with limited exceptions.

We are unable to predict the impact on our business and  operating  results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.

We are subject to numerous  environmental laws and regulations that may increase
our cost of  operations,  impact or limit our  business  plans,  or expose us to
environmental liabilities.

We are subject to numerous  environmental  regulations affecting many aspects of
our present and future  operations,  including  air  emissions,  water  quality,
wastewater  discharges,   solid  waste  and  hazardous  waste.  These  laws  and
regulations  can  result in  increased  capital,  operating,  and  other  costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations.  These  laws and  regulations  generally  require  us to obtain and
comply with a wide variety of environmental licenses,  permits,  inspections and
other  approvals.  Both public  officials  and private  individuals  may seek to
enforce  applicable  environmental  laws and regulations.  We cannot predict the
outcome (financial or operational) of any related litigation that may arise.


                                      171
<PAGE>

In addition,  we may be a responsible party for environmental  clean up at sites
identified by a regulatory  body. We cannot predict with certainty the amount or
timing of all future  expenditures  related to environmental  matters because of
the  difficulty  of  estimating  clean up costs.  There is also  uncertainty  in
quantifying  liabilities under  environmental laws that impose joint and several
liability on all PRPs.

We cannot assure you that existing environmental regulations will not be revised
or that new regulations  seeking to protect the environment  will not be adopted
or become applicable to us. Revised or additional  regulations,  which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers,  could have a material
adverse effect on our results of operations.

The uncertain outcome  regarding the timing,  creation and structure of regional
transmission  organizations,  or RTOs,  may  materially  impact  our  results of
operations, cash flows or financial condition.

Congress, FERC, and the state utility regulators have paid significant attention
in recent years to  transmission  issues,  including the possibility of regional
transmission  organizations.  While these deliberations have not yet resulted in
significant  changes  to  our  utilities'  transmission  operations,  they  cast
uncertainty  over those  operations,  which constitute a material portion of our
assets.

For the last several  years,  the FERC has  supported  independent  RTOs and has
indicated  a  belief  that it has the  authority  to  order  transmission-owning
utilities to transfer  operational  control of their transmission assets to such
RTOs. Many state  regulators,  including most regulators in the Southeast,  have
expressed  skepticism over the potential benefits of RTOs and generally disagree
with the FERC's interpretation of its authority to mandate RTOs.

In addition,  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"). The
proposed rules set forth in the SMD NOPR would require, among other things, that
1) all  transmission  owning utilities  transfer  control of their  transmission
facilities to an independent  third party;  2)  transmission  service to bundled
retail  customers  be provided  under the  FERC-regulated  transmission  tariff,
rather than state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established for the buying and selling of electric  energy;  and 5) load-serving
entities (LSEs) be required to meet minimum criteria for generating reserves. If
adopted as proposed,  the rules set forth in the SMD NOPR would materially alter
the manner in which  transmission and generation  services are provided and paid
for. We filed  comments in November  2002 and  supplemental  comments in January
2003. The FERC has not yet issued a final rule on SMD. Furthermore, the SMD NOPR
presents several uncertainties,  including what percentage of our investments in
GridSouth and GridFlorida will be recovered, how the elimination of transmission
charges, as proposed in the SMD NOPR, will impact us, and what amount of capital
expenditures will be necessary to create a new wholesale market.

To date, our electric utilities have responded as follows:

o    PEC and other  investor-owned  utilities filed  applications with the FERC,
     the NCUC and the SCPSC for approval of an RTO,  currently named  GridSouth.
     However,  PEC and the  other  GridSouth  participants  withdrew  their  RTO
     application  before the NCUC and the SCPSC pending the review of the FERC's
     SMD NOPR. A determination about refiling will be made at a later date.

o    PEF and other investor-owned utilities filed applications with the FERC and
     the FPSC for  approval of an RTO,  currently  named  GridFlorida.  The FERC
     provisionally  approved the structure and  governance of  GridFlorida.  The
     FPSC's  most  recent  order  in  December   2003  ordered   further   state
     proceedings.

The actual  structure of  GridSouth,  GridFlorida  or any  alternative  combined
transmission structure,  as well as the date it may become operational,  depends
upon the resolution of all regulatory  approvals and technical issues. Given the
regulatory  uncertainty  of the ultimate  timing,  structure  and  operations of
GridSouth,  GridFlorida  or an alternate  combined  transmission  structure,  we
cannot predict  whether their creation will have any material  adverse effect on
our  future  consolidated  results  of  operations,   cash  flows  or  financial
condition.

Since weather conditions directly influence the demand for and cost of providing
electricity,  our results of  operations,  financial  condition,  cash flows and
ability to pay  dividends  on our common  stock can  fluctuate  on a seasonal or
quarterly basis and can be negatively  affected by changes in weather conditions
and severe weather.


                                      172
<PAGE>

Our results of operations,  financial  condition,  cash flows and ability to pay
dividends  on our common stock may be affected by changing  weather  conditions.
Weather conditions in our service territories,  primarily North Carolina,  South
Carolina, and Florida,  directly influence the demand for electricity affect the
price of energy  commodities  necessary to provide  electricity to our customers
and energy commodities that our nonregulated businesses sell.

Electric  power  demand is generally a seasonal  business.  In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
As a  result,  our  overall  operating  results  in  the  future  may  fluctuate
substantially  on a seasonal basis.  The pattern of this  fluctuation may change
depending on the nature and location of  facilities  we acquire and the terms of
power sale contracts into which we enter. In addition, we have historically sold
less power, and  consequently  earned less income,  when weather  conditions are
milder.  While we believe that our North Carolina,  South Carolina,  and Florida
markets  complement  each other during normal seasonal  fluctuations,  unusually
mild weather  could  diminish our results of  operations  and harm our financial
condition.

Furthermore,  severe  weather in these states,  such as  hurricanes,  tornadoes,
severe  thunderstorms  and  snow and ice  storms,  can be  destructive,  causing
outages,  downed  power  lines  and  property  damage,  requiring  us  to  incur
additional and unexpected expenses and causing us to lose generating revenues.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2003, commercial and industrial customers represented approximately
37% of our electric revenues. As a result,  changes in the macroeconomy can have
negative  impacts on our revenues.  As our commercial  and industrial  customers
experience economic hardships, our revenues can be negatively impacted. In North
and  South  Carolina,  sales to  industrial  customers  have  been  affected  by
downturns in the textile and chemical industries.

Deregulation or restructuring  in the electric  industry may result in increased
competition  and  unrecovered  costs that could  adversely  affect the financial
condition,  results  of  operations  or  cash  flows  of us and  our  utilities'
businesses.

Increased competition resulting from deregulation or restructuring efforts could
have a significant  adverse financial impact on us and our utility  subsidiaries
and  consequently  on our  results  of  operations  and  cash  flows.  Increased
competition  could also result in increased  pressure to lower costs,  including
the cost of  electricity.  Retail  competition  and the  unbundling of regulated
energy and gas service could have a significant  adverse  financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower  profit  margins  or  increased  costs  of  capital.  Because  we have not
previously operated in a competitive retail  environment,  we cannot predict the
extent and timing of entry by additional  competitors into the electric markets.
Due to several  factors,  however,  there currently is little  discussion of any
movement toward  deregulation in North Carolina,  South Carolina and Florida. We
cannot  predict when we will be subject to changes in legislation or regulation,
nor can we predict  the  impact of these  changes  on our  financial  condition,
results of operations or cash flows.

Risks Related to Us and Our Business

As a  holding  company,  we are  dependent  on  upstream  cash  flows  from  our
subsidiaries.  As a result, our ability to meet our ongoing and future financial
obligations  and to pay dividends on our common stock is primarily  dependent on
the earnings and cash flows of our operating  subsidiaries  and their ability to
pay upstream dividends or to repay funds to us.

We are a holding company. As such, we have no operations of our own. Our ability
to meet our  financial  obligations  and to pay dividends on our common stock at
the current  rate is  primarily  dependent on the earnings and cash flows of our
operating  subsidiaries and their ability to pay upstream  dividends or to repay
funds to us. Prior to funding us, our  subsidiaries  have financial  obligations
that must be  satisfied,  including  among others,  debt service,  dividends and
obligations to trade creditors.

The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators.  Accordingly, our profit
margins  could be adversely  affected if we or our utility  subsidiaries  do not
control operating costs.

                                      173
<PAGE>

The NCUC, the SCPSC and the FPSC each exercises  regulatory authority for review
and approval of the retail  electric  power rates charged  within its respective
state.  State  regulators  may not allow our  utility  subsidiaries  to increase
retail  rates in the manner or to the extent  requested  by those  subsidiaries.
State  regulators  may also seek to reduce retail rates.  For example,  in March
2002, PEF entered into a Stipulation and Settlement Agreement that required PEF,
among other  things,  to reduce its retail rates and to operate  under a revenue
sharing plan through 2005 which provides for possible rate refunds to its retail
customers.  The Agreement will also require increased  capital  expenditures for
PEF's  Commitment to Excellence  program.  However,  if PEF's base rate earnings
fall below a 10% return on equity,  PEF may  petition the FPSC to amend its base
rates. Additionally, a North Carolina law passed in 2002 froze PEC's base retail
rates  for  five  years  unless  there  are  significant  cost  changes  due  to
governmental  action,  significant  expenditures  due to force  majeure or other
extraordinary  events beyond the control of PEC. The same legislation required a
significant  increase in capital  expenditures  over the next several  years for
clean air improvements.  The cash costs incurred by our utility subsidiaries are
generally not subject to being fixed or reduced by state regulators. Our utility
subsidiaries will also require dedicated capital expenditures. Thus, our ability
to maintain our profit margins  depends upon stable demand for  electricity  and
our efforts to manage our costs.

There are  inherent  potential  risks in the  operation  of nuclear  facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could  result in fines or the shutdown of our nuclear  units,  which may present
potential exposures in excess of our insurance coverage.

We own and operate five nuclear units through our subsidiaries, PEC (four units)
and PEF (one unit), that represent approximately 4,220 megawatts, or 18%, of our
generation capacity. Our nuclear facilities are subject to environmental, health
and financial  risks such as the ability to dispose of spent  nuclear fuel,  the
ability to maintain  adequate  capital reserves for  decommissioning,  potential
liabilities  arising out of the operation of these facilities,  and the costs of
securing  the  facilities  against  possible  terrorist  attacks.   We  maintain
decommissioning trusts and external insurance coverage to minimize the financial
exposure to these risks;  however,  it is possible that damages could exceed the
amount of our insurance coverage.

The  NRC  has  broad  authority  under  federal  law  to  impose  licensing  and
safety-related  requirements for the operation of nuclear generation facilities.
In the event of non-compliance,  the NRC has the authority to impose fines or to
shut down a unit, or both,  depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could  require us to make  substantial  capital  expenditures  at our
nuclear plants. In addition,  although we have no reason to anticipate a serious
nuclear  incident at our plants,  if an incident did occur, it could  materially
and adversely affect our results of operations or financial  condition.  A major
incident  at a nuclear  facility  anywhere  in the world  could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.

Our facilities  require licenses that need to be renewed or extended in order to
continue  operating.  We do not anticipate any problems renewing these licenses.
However,  as a result  of  potential  terrorist  threats  and  increased  public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.

Our  financial  performance  depends on the  successful  operation  of  electric
generating facilities by our subsidiaries and our ability to deliver electricity
to our customers.

Operating  electric  generating  facilities and delivery  systems  involves many
risks, including:

     o    operator error and breakdown or failure of equipment or processes;
     o    operating  limitations  that may be imposed by  environmental or other
          regulatory requirements;
     o    labor disputes;
     o    fuel supply interruptions; and
     o    catastrophic events such as fires,  earthquakes,  explosions,  floods,
          terrorist attacks or other similar occurrences.

A decrease or elimination of revenues generated from our subsidiaries'  electric
generating  facilities and  electricity  delivery  systems or an increase in the
cost of operating the  facilities  could have an adverse  effect on our business
and results of operations.

Our business is dependent on our ability to successfully access capital markets.
Our  inability  to access  capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.

                                      174
<PAGE>

We rely on access to both short-term money markets and long-term capital markets
as a significant  source of liquidity for capital  requirements not satisfied by
the cash  flow from our  operations.  If we are not able to  access  capital  at
competitive  rates,  our ability to  implement  our  strategy  will be adversely
affected.  We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings.  However,  certain market disruptions
or a  downgrade  of our credit  rating may  increase  our cost of  borrowing  or
adversely  affect  our  ability to access one or more  financial  markets.  Such
disruptions could include:

     o    an economic downturn;
     o    the  bankruptcy  of an  unrelated  energy  company;
     o    capital  market conditions generally;
     o    market prices for electricity and gas;
     o    terrorist attacks or threatened attacks on our facilities or unrelated
          energy companies; or
     o    the overall health of the utility industry.

Restrictions on our ability to access  financial  markets may affect our ability
to execute our business  plan as scheduled.  An inability to access  capital may
limit our ability to pursue  improvements or acquisitions  that we may otherwise
rely on for future growth.

Increases in our  leverage  could  adversely  affect our  competitive  position,
business planning and flexibility,  financial condition,  ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.

Our cash requirements arise primarily from the  capital-intensive  nature of our
electric utilities.  In addition to operating cash flows, we rely heavily on our
commercial paper and long-term debt. At December 31, 2003,  commercial paper and
bank  borrowings  and  long-term  debt  balances  for  Progress  Energy  and its
subsidiaries were as follows (in millions):
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                      Outstanding Commercial Paper    Total Long-Term
Company                               and Bank Borrowings             Debt, Net
------------------                    -----------------------------   -------------------
Progress Energy, unconsolidated (a)       $    -                       $   4,292
PEC                                            4                           3,086
PEF                                            -                           1,879 (b)
Other Subsidiaries                             -                             677 (c)
                                      -----------------------------   -------------------
Progress Energy, consolidated             $    4                       $   9,934 (b)(d)
</TABLE>

(a)  Represents solely the outstanding indebtedness of the holding company.
(b)  On February 21, 2003, PEF issued $650.0 million aggregate  principal amount
     of its first mortgage  bonds,  the proceeds from which were or will be used
     to reduce,  redeem,  or retire our  outstanding  long-term and  short-term,
     secured and unsecured, indebtedness.
(c)  Includes the following  subsidiaries:  Progress Genco  Ventures,  LLC ($241
     million),  Florida Progress Funding Corporation ($270 million) and Progress
     Capital Holdings, Inc. ($166 million).
(d)  Net of current  portion,  which at December 31, 2003, was $868 million on a
     consolidated basis.

Progress Energy and its  subsidiaries  have an aggregate of six committed credit
lines that support our commercial  paper programs  totaling $1.6 billion.  While
our financial policy precludes us from issuing commercial paper in excess of our
credit  lines,  at  December  31,  2003,  we did not have any  commercial  paper
outstanding,  leaving  $1.6 billion  available  for future  borrowing  under our
credit lines.

Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios and minimum coverage ratios.  Under the credit  facilities,  indebtedness
includes  certain letters of credit and guarantees which are not recorded on our
consolidated Balance Sheets. At December 31, 2003, the maximum and actual ratios
were as follows:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                           Leverage Ratios                  Coverage Ratios
     Company        Maximum Ratio     Actual Ratio    Maximum Ratio     Actual Ratio
     -------        -------------     ------------    -------------     ------------
Progress Energy         68%                 61.5%         2.5:1            3.74:1
PEC                     65%                 51.4%          n/a               n/a
PEF                     65%                 51.5%         3.0:1            9.22:1
Genco                   40%                 24.6%        1.25:1            6.35:1
</TABLE>

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<PAGE>

In the event our capital  structure  changes such that we approach the permitted
ratios,  our  access  to  capital  and  additional   liquidity  could  decrease.
Furthermore,  the  credit  lines of  Progress  Energy,  PEC,  PEF and Genco each
include  provisions  under which  lenders  could refuse to advance funds to each
company under their  respective  credit lines in the event of a material adverse
change in the  respective  company's  financial  condition.  A limitation in our
liquidity could have a material adverse impact on our business  strategy and our
ongoing  financing needs.

Our  indebtedness  also includes  several  cross-default  provisions which could
significantly  impact our financial condition.  Progress Energy's,  PEC's, PEF's
and Genco's credit lines each include  cross-default  provisions for defaults of
indebtedness in excess of $10 million. Under these provisions, if the applicable
borrower or certain  subsidiaries fail to pay various debt obligations in excess
of $10  million,  the  lenders  could  accelerate  payment  of  any  outstanding
borrowings  and terminate  their  commitments to the credit  facility.  Progress
Energy's  cross default  provisions  only apply to defaults of  indebtedness  by
Progress Energy and its significant  subsidiaries  (i.e., PEC, Florida Progress,
PEF, PCH, PVI and Progress Fuels). PEC's and PEF's cross-default provisions only
apply  to  defaults  of  indebtedness  by PEC and PEF  and  their  subsidiaries,
respectively, not other affiliates of PEC and PEF.

Additionally,  certain of Progress  Energy's  long-term debt indentures  contain
cross-default  provisions for defaults of indebtedness in excess of $25 million;
these  provisions only apply to other  obligations of Progress  Energy,  not its
subsidiaries.  In the event that either of these  cross-default  provisions  are
triggered,  the debt holders  could  accelerate  payment of  approximately  $4.8
billion in long-term debt. Any such acceleration  would cause a material adverse
change in the  respective  company's  financial  condition.  Certain  agreements
underlying our indebtedness  also limit our ability to incur additional liens or
engage in certain types of sale and leaseback transactions.

Changes in economic  conditions  could result in higher  interest  rates,  which
would  increase our interest  expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:

o    increasing the cost of future debt financing;
o    impacting  our ability to pay  dividends on our common stock at the current
     rate;
o    making  it  more  difficult  for  us  to  satisfy  our  existing  financial
     obligations;
o    limiting  our ability to obtain  additional  financing,  if we need it, for
     working capital, acquisitions, debt service requirements or other purposes;
o    increasing our vulnerability to adverse economic and industry conditions;
o    requiring  us to  dedicate  a  substantial  portion  of our cash  flow from
     operations to payments on our debt,  which would reduce funds  available to
     us for operations, future business opportunities or other purposes;
o    limiting our  flexibility  in planning for, or reacting to,  changes in our
     business and the industry in which we compete;
o    placing us at a competitive  disadvantage  compared to our  competitors who
     have less debt; and
o    causing a downgrade in our credit ratings.

Any reduction in our credit  ratings could increase our borrowing  costs,  limit
our access to additional capital and require posting of collateral, all of which
could  materially and adversely  affect our business,  results of operations and
financial condition.

In February  2003,  Moody's  announced  that it was lowering  Progress  Energy's
senior  unsecured debt rating from "Baa1" to "Baa2," and changing the outlook of
the rating from  negative to stable.  Moody's cited the slower than planned pace
of the  Company's  efforts  to pay down debt  from its  acquisition  of  Florida
Progress as the primary reason for the ratings change.  Moody's also changed the
outlook of PEF's  senior  secured  debt from stable to  negative.  PEC's  senior
unsecured  debt has been assigned a rating by S&P of "BBB+"  (negative  outlook)
and by Moody's of "Baa1" (stable outlook).  PEF's senior unsecured debt has been
assigned a rating by S&P of "BBB+"  (negative  outlook)  and by Moody's of "A-2"
(stable  outlook).  In August 2003,  Standard & Poor's  Ratings  Group (S&P),  a
division of The McGraw-Hill  Companies,  Inc., announced that it had lowered its
corporate  credit rating on Progress Energy Inc., PEC, PEF, and Florida Progress
to BBB from BBB+.  The  outlook of the  ratings  was  changed  from  negative to
stable. While our nonregulated operations, including those conducted through our
Progress  Ventures business unit, have a higher level of risk than our regulated
utility  operations,  we will seek to maintain a solid  investment  grade rating
through prudent capital management and financing structures. We cannot, however,
assure you that any of Progress  Energy's current  ratings,  or those of PEC and
PEF,  will  remain in effect for any given  period of time or that a rating will
not be lowered or  withdrawn  entirely by a rating  agency if, in its  judgment,
circumstances  in the  future so  warrant.  Any  downgrade  could  increase  our
borrowing  costs and  adversely  affect  our  access  to  capital,  which  could
negatively impact our financial  results.  Further,  we may be required to pay a
higher interest rate in future  financings,  and our potential pool of investors
and funding sources could  decrease.  Although we would have access to liquidity

                                      176
<PAGE>

under our committed and uncommitted  credit lines, if our short-term rating were
to fall below A-2 or P-2,  the  current  ratings  assigned  by S&P and  Moody's,
respectively,  it could  significantly  limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy,  sell or hold our  securities  or those of PEC or PEF and that each  rating
should be evaluated independently of any other rating.

Our energy  marketing  business  relies on Progress  Energy's  investment  grade
ratings to stand behind  transactions  in that  business.  At December 31, 2003,
Progress Energy has issued  guarantees  with a notional amount of  approximately
$332 million to support CCO's energy marketing businesses. Based upon the amount
of trading  positions  outstanding  at December 31, 2003,  if Progress  Energy's
ratings were to decline below investment grade, we would have to deposit cash or
provide letters of credit or other cash collateral for approximately $56 million
for the benefit of our counterparties.  Additionally, the power supply agreement
with Jackson  Electric  Membership  Corporation  that PVI acquires from Williams
Energy  Marketing  and Trading  Company  includes a performance  guarantee  that
Progress Energy assumed. In the event that Progress Energy's credit ratings fall
below investment grade,  Progress Energy will be required to provide  additional
security for its guarantee in form and amount acceptable to Jackson,  but not to
exceed the coverage amount.  The coverage amount at the inception of PVI's power
sale  to  Jackson  is  $285  million  and  will  decline  over  the  life of the
transaction.  At December 31, 2003, the coverage  amount is $280 million.  These
collateral  requirements  could  adversely  affect our  profitability  on energy
trading and marketing transactions and limit our overall liquidity.

The use of  derivative  contracts  in the normal  course of our  business  could
result in financial losses that negatively impact our results of operations.

We use  derivatives,  including  futures,  forwards  and  swaps,  to manage  our
commodity  and  financial  market  risks.  In the  future,  we  could  recognize
financial  losses on these  contracts  as a result of  volatility  in the market
values of the underlying commodities or if a counterparty fails to perform under
a  contract.  In the  absence of  actively  quoted  market  prices  and  pricing
information from external sources, the valuation of these financial  instruments
can involve management's judgment or use of estimates.  As a result,  changes in
the underlying  assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.

We could incur a significant  tax  liability,  and our results of operations and
cash flows may be  materially  and  adversely  affected if the Internal  Revenue
Service denies or otherwise makes unusable the Section 29 tax credits related to
our coal and synthetic fuels businesses.

Through our Fuels  segment,  we produce  coal-based  solid  synthetic  fuel. The
production  and sale of the synthetic fuel from these  facilities  qualifies for
tax credits under Section 29 if certain requirements are satisfied,  including a
requirement   that  the  synthetic  fuel  differs   significantly   in  chemical
composition  from the coal used to produce such synthetic fuel and that the fuel
was produced from a facility that was placed in service before July 1, 1998. All
of our synthetic fuel facilities have received  favorable 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.  In
September 2002, all of our majority-owned  synthetic fuel entities were accepted
into the  IRS'  Pre-Filing  Agreement  (PFA)  program.  The PFA  program  allows
taxpayers to voluntarily accelerate the IRS examination process in order to seek
resolution  of  specific  issues.  Either  we or the IRS can  withdraw  from the
program at any time, and issues not resolved  through the program may proceed to
the next level of the IRS  examination  process.  We believe  that we operate in
conformity with all the necessary  requirements to be allowed such credits under
Section 29. The current  Section 29 tax credit program will expire at the end of
2007. With respect to any IRS review or audit of our synthetic fuel  operations,
if we fail to prevail through the  administrative or legal process,  there could
be a significant  tax liability owed for previously  taken Section 29 credits or
we could lose our ability to claim future tax credits that we might otherwise be
able to benefit from both of which would significantly  impact earnings and cash
flows.

In  October  2003,   the  United  States  Senate   Permanent   Subcommittee   on
Investigations  began a  general  investigation  concerning  synthetic  fuel tax
credits claimed under Section 29 of the Internal Revenue Code. The investigation
generally  relates  to the  utilization  of the tax  credits,  the nature of the
technologies and fuels created, the use of the synthetic fuel, and other aspects
of Section 29 and is not  specific  to our  synthetic  fuel  operations.  We are
providing information in connection with this investigation as requested.

There  are  risks  involved  with  the  operation  of our  nonregulated  plants,
including  dependence on third parties and related  counter-party  risks,  and a
lack of operating  history,  all of which may make our wholesale  generation and
overall operations less profitable and more unstable.

                                      177
<PAGE>

At December 31,  2003,  we had  approximately  3,100  megawatts of  nonregulated
generation in commercial operation.

The  operation  of  wholesale  generation  facilities  is subject to many risks,
including those listed below.  During the execution of our wholesale  generation
strategy, these risks will intensify. These risks include:

o    We may enter into or otherwise acquire long-term contracts that take effect
     at a  future  date  based  upon  our  current  expectations  of our  future
     wholesale  generation  capacity.  If our expected  future capacity does not
     meet our expectations, we may not be able to meet our obligations under any
     such long-term  contracts and may have to purchase power in the spot market
     at then  prevailing  prices.  Accordingly,  we may lose  current and future
     customers,  impair our ability to implement  our  wholesale  strategy,  and
     suffer  reputational  harm.  Additionally,  if  we  are  unable  to  secure
     favorable  pricing in the spot  market,  our results of  operations  may be
     diminished.  We may  also  become  liable  under  any  related  performance
     guarantees then in existence.

o    Our wholesale  facilities  depend on third parties  through power  purchase
     agreements,  fuel supply and  transportation  agreements,  and transmission
     grid connection agreements.  If such third parties breach their obligations
     to us, our  revenues,  financial  condition,  cash flow and ability to make
     payments  of  interest  and  principal  on  our  outstanding  debts  may be
     impaired.  Any material breach by any of these parties of their obligations
     under the project contracts could adversely affect our cash flows and could
     impair our ability to make  payments of  principal  of and  interest on our
     indebtedness.

o    We depend on transmission and distribution facilities owned and operated by
     utilities and other energy companies to deliver the electricity and natural
     gas that we sell to the wholesale market. If transmission is disrupted,  or
     if capacity is  inadequate,  our ability to sell and deliver  products  and
     satisfy our contractual obligations may be hindered.  Although the FERC has
     issued  regulations  designed to encourage  competition in wholesale market
     transactions  for  electricity,  there is the potential that fair and equal
     access to  transmission  systems will not be  available or that  sufficient
     transmission  capacity will not be available to transmit  electric power as
     we desire.  We cannot predict the timing of industry changes as a result of
     these  initiatives or the adequacy of  transmission  facilities in specific
     markets.

o    Agreements  with our  counter-parties  frequently will include the right to
     terminate  and/or withhold  payments or performance  under the contracts if
     specific events occur.  If a project  contract were to be terminated due to
     nonperformance by us or by the other party to the contract,  our ability to
     enter into a substitute agreement having substantially equivalent terms and
     conditions is uncertain.

o    Because  many  of  our  facilities  are  newly   constructed  and  have  no
     significant  operating history,  various unexpected events may increase our
     expenses  or reduce our  revenues  and impair  our  ability to service  the
     related  project  debt.  As with any new business  venture of this size and
     nature,  operation  of our  facility  could be  affected  by many  factors,
     including  start-up  problems,  the  breakdown  or failure of  equipment or
     processes,  the performance of our facility below expected levels of output
     or efficiency, failure to operate at design specifications, labor disputes,
     changes in law,  failure  to obtain  necessary  permits  or to meet  permit
     conditions,  government  exercise of eminent domain power or similar events
     and  catastrophic  events  including  fires,  explosions,  earthquakes  and
     droughts.

o    Our facilities  seek to enter into long-term  power purchase  agreements to
     sell  all  or a  portion  of  their  generating  capacity.  Currently,  the
     percentage  of our  anticipated  nonregulated  capacity  that will be under
     contract is as follows: 2004--85%,  2005--50% and 2006--50%.  Following the
     expiration or early termination of our power purchase agreements, or to the
     extent we cannot  otherwise  secure  contracts  for our  current and future
     generation   capacity,   our  facilities  will  generally  become  merchant
     facilities.  Our  merchant  facilities  may not be  able  to find  adequate
     purchasers,  attain favorable pricing,  or otherwise compete effectively in
     the  wholesale   market.   Additionally,   numerous  legal  and  regulatory
     limitations  restrict  our  ability to operate a  facility  on a  wholesale
     basis.

Our energy marketing and trading operations are subject to risks that may reduce
our  revenues  and  adversely  impact our results of  operations  and  financial
condition, many of which are beyond our control.

Our fleet of  nonregulated  plants may sell energy into the spot market or other
competitive  power  markets or on a  contractual  basis.  We may also enter into
contracts to purchase and sell electricity,  natural gas and coal as part of our
power  marketing and energy  trading  operations.  Our business may also include
entering  into  long-term   contracts  that  supply   customers'  full  electric
requirements.  These  contracts  do not  guarantee  us any rate of return on our

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capital  investments  through  mandated  rates,  and our revenues and results of
operations  from  these  contracts  are likely to depend,  in large  part,  upon
prevailing market prices for power in our regional markets and other competitive
markets.  These market prices can fluctuate  substantially over relatively short
periods  of time.  Trading  margins  may erode as  markets  mature,  and  should
volatility decline, we may have diminished opportunities for gain.

In  particular,  we  believe  that  over the past few  years,  the  Southeastern
wholesale  energy market has been overbuilt and accordingly  believe that supply
exceeds demand. Due to this overbuilding, we believe that spot prices as well as
contractual pricing will provide us with a reduced rate of return on our capital
investment  and our revenues and results of operations  from this market will be
lower than originally expected unless and until demand catches up with supply.

In addition,  the Enron Corporation  bankruptcy and enhanced regulatory scrutiny
have  contributed to more rigorous  credit rating review of  participants in the
energy marketing and trading business. Credit downgrades of certain other market
participants have significantly reduced such participants'  participation in the
wholesale  power  markets.  These events are causing a decrease in the number of
significant participants in the wholesale power markets, which could result in a
decrease in the volume and  liquidity in the  wholesale  power  markets.  We are
unable to predict the impact of such  developments  on our power  marketing  and
trading business.

Furthermore,  the FERC,  which has  jurisdiction  over wholesale power rates, as
well as ISOs that oversee some of these markets,  may impose price  limitations,
bidding rules and other  mechanisms  to address some of the  volatility in these
markets. Fuel prices also may be volatile, and the price we can obtain for power
sales may not change at the same rate as fuel costs changes. These factors could
reduce  our  margins  and  therefore   diminish  our  revenues  and  results  of
operations.

Volatility in market prices for fuel and power may result from:

     o    weather conditions;
     o    seasonality;
     o    power usage;
     o    illiquid markets;
     o    transmission or transportation constraints or inefficiencies;
     o    availability of competitively priced alternative energy sources;
     o    demand for energy commodities;
     o    natural  gas,  crude oil and  refined  products,  and coal  production
          levels;
     o    natural disasters, wars, embargoes and other catastrophic events; and
     o    federal,  state and foreign  energy and  environmental  regulation and
          legislation.

We actively manage the market risk inherent in our energy marketing  operations.
Nonetheless,  adverse  changes in energy and fuel prices may result in losses in
our earnings or cash flows and adversely affect our balance sheet. Our marketing
and risk management  procedures may not work as planned.  As a result, we cannot
predict  with  precision  the  impact  that  our  marketing,  trading  and  risk
management  decisions may have on our business,  operating  results or financial
position. In addition, to the extent that we do not cover the entire exposure of
our  assets  or our  positions  to  market  price  volatility,  or  our  hedging
procedures do not work as planned,  fluctuating commodity prices could cause our
sales and net income to be volatile.


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PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS

In this  section,  references  to "we,"  "our,"  "us" or  similar  terms  are to
Progress Energy Carolinas, Inc. and its consolidated subsidiaries.  Investing in
our securities  involves risks,  including the risks described below, that could
affect the energy  industry,  as well as us and our  business.  Although we have
tried to discuss key  factors,  please be aware that other risks may prove to be
important in the future.  New risks may emerge at any time and we cannot predict
such  risks or  estimate  the  extent to which  they may  affect  our  financial
performance. Before purchasing our securities, you should carefully consider the
following  risks and the other  information  in this Annual  Report,  as well as
documents  we file with the SEC from time to time.  Each of the risks  described
below  could  result  in a  decrease  in the  value of our  securities  and your
investment therein.

Risks Related to the Energy Industry

We are  subject  to fluid and  complex  government  regulations  that may have a
negative impact on our business and our results of operations.

We are  subject  to  comprehensive  regulation  by  several  federal  and  state
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers.  We are required
to have  numerous  permits,  approvals and  certificates  from the agencies that
regulate  our  business.  We  believe  the  necessary  permits,   approvals  and
certificates  have  been  obtained  for our  existing  operations  and  that our
business is conducted in accordance with applicable laws; however, we are unable
to  predict  the impact on our  operating  results  from the  future  regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional   regulations  could  have  an  adverse  impact  on  our  results  of
operations.

The Federal Energy Regulatory  Commission ("FERC"),  the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental  Protection Agency ("EPA"), the North
Carolina  Utilities  Commission  ("NCUC") and the Public  Service  Commission of
South  Carolina  ("SCPSC")  regulate  many  aspects of our  utility  operations,
including siting and construction of facilities,  customer service and the rates
that we can charge customers.  Although we are not a registered  holding company
under the Public Utility Holding Company Act of 1935, as amended  ("PUHCA"),  we
are subject to many of the regulatory provisions of PUHCA.

We are a wholly-owned  subsidiary of Progress Energy,  Inc., a registered public
utility holding company under PUHCA.  Repeal of PUHCA has been proposed,  but it
is unclear whether or when such a repeal would occur. It is also unclear to what
extent repeal of PUHCA would result in additional or new regulatory oversight or
action at the federal or state levels, or what the impact of those  developments
might be on our business.

We are unable to predict the impact on our business and  operating  results from
future  regulatory  activities of these federal and state  agencies.  Changes in
regulations  or the imposition of additional  regulations  could have a negative
impact on our business and results of operations.

We are subject to numerous  environmental laws and regulations that may increase
our cost of  operations,  impact or limit our  business  plans,  or expose us to
environmental liabilities.

We are subject to numerous  environmental  regulations affecting many aspects of
our present and future  operations,  including  air  emissions,  water  quality,
wastewater  discharges,  solid  waste,  and  hazardous  waste.  These  laws  and
regulations  can  result  in  increased  capital,  operating  and  other  costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations.  These  laws and  regulations  generally  require  us to obtain and
comply with a wide variety of environmental licenses,  permits,  inspections and
other  approvals.  Both public  officials  and private  individuals  may seek to
enforce  applicable  environmental  laws and regulations.  We cannot predict the
financial or operational outcome of any related litigation that may arise.

In addition,  we may be a responsible party for environmental  clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount and
timing of all future  expenditures  related to environmental  matters because of
the  difficulty  of  estimating  clean up costs.  There is also  uncertainty  in
quantifying  liabilities under  environmental laws that impose joint and several
liability on all PRPs.

We cannot assure you that existing environmental regulations will not be revised
or that new regulations  seeking to protect the environment  will not be adopted
or become applicable to us. Revised or additional  regulations,  which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers,  could have a material
adverse effect on our results of operations.

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Deregulation or  restructuring  in the electric  utility  industry may result in
increased  competition  and unrecovered  costs that could  adversely  affect our
financial condition, results of operations and cash flows.

Increased competition resulting from deregulation or restructuring efforts could
have a significant  adverse  financial  impact on our results of operations  and
cash flows.  Increased  competition  could also result in increased  pressure to
lower rates.  Retail  competition and the unbundling of regulated energy and gas
service  could  have a  significant  adverse  financial  impact  on us due to an
impairment  of  assets,  a loss of retail  customers,  lower  profit  margins or
increased  costs of  capital.  Because  we have  not  previously  operated  in a
competitive retail environment, we cannot predict the extent and timing of entry
by additional  competitors  into the electric  markets.  Due to several factors,
however,   there   currently  is  little   discussion  of  any  movement  toward
deregulation  in North  Carolina and South  Carolina.  We cannot predict when we
will be subject to changes in legislation or regulation,  nor can we predict the
impact of these  changes on our  financial  condition,  results of operations or
cash flows.

The uncertain outcome  regarding the timing,  creation and structure of regional
transmission  organizations,  or RTOs,  may  materially  impact  our  results of
operations, cash flows or financial condition.

For the last several  years,  the FERC has  supported  independent  RTOs and has
indicated  a  belief  that it has the  authority  to  order  transmission-owning
utilities  to  transfer  operational  control  of their  transmission  assets to
participate in such RTOs.  Many state  regulators,  including most regulators in
the Southeast, have expressed skepticism over the potential benefits of RTOs and
generally  disagree with the FERC's  interpretation  of its authority to mandate
RTOs.

In addition,  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"). The
proposed rules set forth in the SMD NOPR would require, among other things, that
1) all  transmission  owning utilities  transfer  control of their  transmission
facilities to an independent  third party;  2)  transmission  service to bundled
retail  customers be provided  under the FERC-  regulated  transmission  tariff,
rather than state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission  congestion;  4) new energy markets be
established  for the  buying  and  selling of  electric  energy;  and 5) LSEs be
required  to meet  minimum  criteria  for  generating  reserves.  If  adopted as
proposed,  the rules set forth in the SMD NOPR would materially alter the manner
in which  transmission  and  generation  services  are  provided  and paid  for.
Progress  Energy,  Inc.  filed  comments  on the SMD NOPR in  November  2002 and
supplemental  comments in January 2003. The FERC has not yet issued a final rule
on SMD. Furthermore, the SMD NOPR presents several uncertainties, including what
percentage  of  our  investments  in  GridSouth  will  be  recovered,   how  the
elimination of  transmission  charges,  as proposed in the SMD NOPR, will impact
us, and what amount of capital  expenditures  will be  necessary to create a new
wholesale market.

In response, PEC and other investor-owned  utilities filed applications with the
FERC, the NCUC and the SCPSC for approval of an RTO,  currently named GridSouth.
However, PEC and the other GridSouth participants withdrew their RTO application
before the NCUC and the SCPSC  pending  the  review of the  FERC's  SMD NOPR.  A
determination about refilling will be made at a later date.

The actual  structure  of  GridSouth or any  alternative  combined  transmission
structure,  as well as the  date it may  become  operational,  depends  upon the
resolution  of  all  regulatory   approvals  and  technical  issues.  Given  the
regulatory  uncertainty  of the ultimate  timing,  structure  and  operations of
GridSouth,  or an alternate combined transmission  structure,  we cannot predict
whether  their  creation  will have any  material  adverse  effect on our future
consolidated results of operations, cash flows or financial condition.

Since weather conditions directly influence the demand for and cost of providing
electricity,  our results of operations,  financial condition and cash flows can
fluctuate on a seasonal or  quarterly  basis and can be  negatively  affected by
changes in weather conditions and severe weather.

Our results of operations, financial condition and cash flows may be affected by
changing  weather  conditions.  Weather  conditions  in our service  territories
directly  influence  the demand for  electricity  and affect the price of energy
commodities necessary to provide electricity to our customers.

Electric  power  demand is generally a seasonal  business.  In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this  fluctuation may change depending on the nature and location

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of  facilities  we acquire and the terms of power sale  contracts  into which we
enter.  In addition,  we have  historically  sold less power,  and  consequently
earned less income, when weather conditions are milder. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.

Furthermore,  severe  weather  in North  Carolina  and South  Carolina,  such as
hurricanes,  tornadoes,  severe  thunderstorms  and snow and ice storms,  can be
destructive,  causing outages, downed power lines and property damage, requiring
us to incur additional and unexpected expenses and causing us to lose generating
revenues.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2003, commercial and industrial customers represented approximately
24% and 18% of our electric revenues,  respectively. As a result, changes in the
macroeconomy  can have negative  impacts on our revenues.  As our commercial and
industrial  customers  experience  economic  hardships,   our  revenues  can  be
negatively impacted.

Risks Related to Us and Our Business

Under a North  Carolina  law passed in 2002,  our base rates are frozen for five
years  and we are  required  to  increase  capital  expenditures  for  clean air
improvements.  Accordingly,  our profit margin could be adversely affected if we
do not control operating costs.

The NCUC and the SCPSC  each  exercises  regulatory  authority  for  review  and
approval of the retail electric power rates charged within its respective state.
State  regulators may not allow us to increase  retail rates in the manner or to
the extent we request.  State regulators may also seek to reduce retail rates. A
North  Carolina  law passed in 2002 froze our base  retail  rates for five years
unless  there  are  significant   cost  changes  due  to  governmental   action,
significant  expenditures  due to force  majeure or other  extraordinary  events
beyond our control.  That same  legislation  required a significant  increase in
capital expenditures over the next several years for clean air improvements. The
cash costs incurred by us are generally not subject to being fixed or reduced by
state regulators. We will also require dedicated capital expenditures. Thus, our
ability  to  maintain  our  profit  margins   depends  upon  stable  demand  for
electricity and our efforts to manage our costs.

There are  inherent  potential  risks in the  operation  of nuclear  facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could  result in fines or the shutdown of our nuclear  units,  which may present
potential exposures in excess of our insurance coverage.

We own and  operate  four  nuclear  units  that  represent  approximately  3,382
megawatts,  or  approximately  27%,  of our  generation  capacity.  Our  nuclear
facilities are subject to environmental,  health and financial risks such as the
ability to dispose of spent  nuclear  fuel,  the  ability to  maintain  adequate
capital reserves for decommissioning,  potential  liabilities arising out of the
operation of these facilities,  and the costs of securing the facilities against
possible  terrorist  attacks.  We maintain a decommissioning  trust and external
insurance coverage to minimize the financial  exposure to these risks;  however,
it is possible that damages could exceed the amount of our insurance coverage.

The  NRC  has  broad  authority  under  federal  law  to  impose  licensing  and
safety-related  requirements for the operation of nuclear generation facilities.
In the event of non-compliance,  the NRC has the authority to impose fines or to
shut  down any of our  units,  or both,  depending  upon its  assessment  of the
severity  of  the  situation,  until  compliance  is  achieved.  Revised  safety
requirements promulgated by the NRC could require us to make substantial capital
expenditures at our nuclear plants.  In addition,  although we have no reason to
anticipate a serious nuclear  incident at any of our plants,  if an incident did
occur,  it could  materially  and adversely  affect our results of operations or
financial  condition.  A major  incident at a nuclear  facility  anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.

Our facilities  require licenses that need to be renewed or extended in order to
continue  operating.  We do not anticipate any problems renewing these licenses.
However,  as a result  of  potential  terrorist  threats  and  increased  public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.

Our financial  performance  depends on the successful  operation of our electric
generating facilities and our ability to deliver electricity to our customers.

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Operating  electric  generating  facilities and delivery  systems  involves many
risks, including:

     o    operator error and breakdown or failure of equipment or processes;
     o    operating  limitations  that may be imposed by  environmental or other
          regulatory requirements;
     o    labor disputes;
     o    fuel supply interruptions; and
     o    catastrophic events such as fires,  earthquakes,  explosions,  floods,
          terrorist attacks or other similar occurrences.

A decrease or  elimination of revenues  generated  from our electric  generating
facilities  and  electricity  delivery  systems  or an  increase  in the cost of
operating  the  facilities  could have an  adverse  effect on our  business  and
results of operations.

Our business is dependent on our ability to successfully access capital markets.
Our  inability  to access  capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.

We rely on access to both short-term money markets and long-term capital markets
as a significant  source of liquidity for capital  requirements not satisfied by
the cash  flow from our  operations.  If we are not able to  access  capital  at
competitive  rates,  our ability to implement  our business  operations  will be
adversely affected.  We believe that we will maintain sufficient access to these
financial  markets based upon current credit  ratings.  However,  certain market
disruptions  or a  downgrade  of our  credit  rating  may  increase  our cost of
borrowing  or  adversely  affect our  ability  to access  one or more  financial
markets. Such disruptions could include:

     o    an economic downturn;
     o    a ratings downgrade of Progress Energy, Inc.;
     o    the bankruptcy of an unrelated energy company;
     o    capital market conditions generally;
     o    market prices for electricity;
     o    terrorist attacks or threatened  attacks on our facilities or those of
          unrelated energy companies; or
     o    the overall health of the utility industry.

Restrictions on our ability to access  financial  markets may affect our ability
to execute our business  plan as scheduled.  An inability to access  capital may
limit our ability to pursue  improvements or acquisitions  that we may otherwise
rely on for future growth.

Increases in our  leverage  could  adversely  affect our  competitive  position,
business planning and flexibility,  financial condition,  ability to service our
debt obligations and ability to access capital on favorable terms.

Our cash requirements arise primarily from the  capital-intensive  nature of our
business. In addition to operating cash flows, we rely heavily on our commercial
paper and long-term debt. At December 31, 2003, our commercial paper balance was
zero, we had $25 million notes payable to affiliated companies and our long-term
debt balances were approximately $3.1 billion (with current portion of long-term
debt of $300 million at December 31, 2003).

We have a committed  credit line that supports our commercial paper programs and
matures in July 2005.  At December 31, 2003,  we had no  outstanding  borrowings
under this line.

Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios.  At December 31, 2003,  the maximum and actual  ratios,  pursuant to the
terms of the credit facilities, were 65% and 51.4%, respectively.  Indebtedness,
as defined under the credit  facility  agreements,  includes  certain letters of
credit and guarantees that are not recorded on our balance sheets.

In the event our capital  structure  changes such that we approach the permitted
ratios,  our  access  to  capital  and  additional   liquidity  could  decrease.
Furthermore,  our credit lines  include  provisions  under which  lenders  could
refuse to advance funds to us in the event of a material  adverse  change in our
financial condition. A limitation in our liquidity could have a material adverse
impact on our business strategy and our ongoing financing needs.

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Our   indebtedness   also   includes   cross-default   provisions   which  could
significantly  impact  our  financial   condition.   Our  credit  lines  include
cross-default  provisions for defaults of indebtedness in excess of $10 million.
Under these  provisions,  if the  applicable  borrower fails to pay various debt
obligations in excess of $10 million,  the lenders could  accelerate  payment of
any  outstanding  borrowings  and  terminate  their  commitments  to the  credit
facility.   Our   cross-default   provisions  only  apply  to  defaults  on  our
indebtedness,  but  not  defaults  by  our  affiliates.  In  the  event  that  a
cross-default  provision was triggered,  our lenders could accelerate payment of
any  outstanding  debt.  Any such  acceleration  would cause a material  adverse
change in our financial condition.

Changes in economic  conditions  could result in higher  interest  rates,  which
would  increase our interest  expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:

     o    increasing the cost of future debt financing;
     o    making it more  difficult  for us to satisfy  our  existing  financial
          obligations;
     o    limiting our ability to obtain  additional  financing,  if we need it,
          for working capital, acquisitions,  debt service requirements or other
          purposes;
     o    increasing  our   vulnerability   to  adverse  economic  and  industry
          conditions;  o requiring us to dedicate a  substantial  portion of our
          cash flow from operations to payments on our debt,  which would reduce
          funds available to us for operations, future business opportunities or
          other purposes;
     o    limiting our  flexibility  in planning for, or reacting to, changes in
          our business and the industry in which we compete;
     o    placing us at a competitive  disadvantage  compared to our competitors
          who have less debt; and
     o    causing a downgrade in our credit ratings.

Any reduction in our credit ratings could increase our borrowing costs and limit
our access to additional  capital,  which could  materially and adversely affect
our business, results of operations and financial condition.

Our senior  secured debt has been assigned a rating by Standard & Poor's Ratings
Group,  a division  of The McGraw  Hill  Companies,  Inc.,  of "BBB+"  (negative
outlook) and by Moody's Investors  Service,  Inc. of "A3" (stable outlook).  Our
senior  unsecured  debt  rating  has been  assigned  a rating  by S&P of  "BBB+"
(negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's
rating philosophy links the ratings of a utility subsidiary to the credit rating
of its  parent  corporation.  Accordingly,  if S&P  were to  downgrade  Progress
Energy,   Inc.'s  credit  ratings,  our  credit  rating  would  also  likely  be
downgraded,  regardless of whether or not we had  experienced  any change in our
business  operations or financial  conditions.  We will seek to maintain a solid
investment  grade  rating  through  prudent  capital  management  and  financing
structures.  We cannot, however, assure you that our current ratings will remain
in effect for any given  period of time or that our ratings  will not be lowered
or withdrawn  entirely by a rating agency if, in its judgment,  circumstances in
the future so warrant.  Any downgrade  could  increase our  borrowing  costs and
adversely  affect our  access to  capital,  which  could  negatively  impact our
financial results.  Further, we may be required to pay a higher interest rate in
future financings, and our potential pool of investors and funding sources could
decrease.  Although we would have access to liquidity  under our  committed  and
uncommitted  credit lines, if our short-term  rating were to fall below "A-2" or
"P-2," the current ratings assigned by S&P and Moody's,  respectively,  it could
significantly  limit our access to the commercial paper market. We note that the
ratings from credit  agencies are not  recommendations  to buy, sell or hold our
securities and that each rating should be evaluated  independently  of any other
rating.

The use of  derivative  contracts  in the normal  course of our  business  could
result in financial losses that negatively impact our results of operations.

We use  derivatives,  including  futures,  forwards  and  swaps,  to manage  our
commodity  and  financial  market  risks.  In the  future,  we  could  recognize
financial  losses on these  contracts  as a result of  volatility  in the market
values of the underlying commodities or if a counterparty fails to perform under
a  contract.  In the  absence of  actively  quoted  market  prices  and  pricing
information from external sources, the valuation of these financial  instruments
can involve management's judgment or use of estimates.  As a result,  changes in
the underlying  assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.


184
<PAGE>

                                   SIGNATURES

Pursuant to the  requirements of Section 13 or 15(d) of the Securities  Exchange
Act of 1934, the registrants  have duly caused this report to be signed on their
behalf by the undersigned, thereunto duly authorized.


                                           PROGRESS ENERGY, INC.
                                           CAROLINA POWER & LIGHT COMPANY
Date: March 12, 2004                       (Registrants)

                                           By:  /s/Robert B.  McGehee
                                           ------------------------------------
                                           Robert B. McGehee
                                           Chief Executive Officer
                                           Progress Energy, Inc.

                                           By: /s/Fred N. Day IV
                                           ------------------------------------
                                           Fred N. Day IV
                                           President and Chief Executive Officer
                                           Carolina Power & Light Company

                                           By: /s/Geoffrey S. Chatas
                                           ------------------------------------
                                           Geoffrey S. Chatas
                                           Executive Vice President and
                                           Chief Financial Officer
                                           Progress Energy, Inc.
                                           Carolina Power & Light Company

                                           By: /s/Robert H. Bazemore, Jr.
                                           ------------------------------------
                                           Robert H. Bazemore, Jr.
                                           Vice President and Controller
                                           (Chief Accounting Officer)
                                           Progress Energy, Inc.
                                           Carolina Power & Light Company

Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following  persons on behalf of the  registrant and
in the capacities and on the date indicated.

Signature                             Title                  Date

/s/ William Cavanaugh III             Director               March 12, 2004
-------------------------
(William Cavanaugh III,
 Chairman)


/s/ Edwin B. Borden                   Director               March 12, 2004
--------------------
(Edwin B. Borden)


/s/ James E. Bostic, Jr.              Director               March 12, 2004
------------------------
(James E. Bostic, Jr.)


/s/ David L. Burner                   Director               March 12, 2004
--------------------
(David L. Burner)

                                      185
<PAGE>

/s/ Charles W. Coker                  Director               March 12, 2004
---------------------
(Charles W. Coker)


/s/ Richard L. Daugherty              Director               March 12, 2004
-------------------------
(Richard L. Daugherty)


/s/ W.D. Frederick, Jr.               Director               March 12, 2004
------------------------
(W.D. Frederick, Jr.)


/s/ William O. McCoy                  Director               March 12, 2004
---------------------
(William O. McCoy)


/s/ E. Marie McKee                    Director               March 12, 2004
-------------------
(E. Marie McKee)


/s/ John H. Mullin, III               Director               March 12, 2004
------------------------
(John H. Mullin, III)


/s/ Richard A. Nunis                  Director               March 12, 2004
---------------------
(Richard A. Nunis)

/s/Peter S. Rummell                   Director               March 12,2004
-------------------
(Peter S. Rummell)

/s/ Carlos A. Saladrigas              Director               March 12, 2004
-------------------------
(Carlos A. Saladrigas)


/s/ J. Tylee Wilson                   Director               March 12, 2004
--------------------
(J. Tylee Wilson)


/s/ Jean Giles Wittner                Director               March 12, 2004
-----------------------
(Jean Giles Wittner)




<PAGE>

                                  EXHIBIT INDEX
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                   Progress
Number                     Exhibit                                                 Energy, Inc.         PEC

*2(a)             Agreement and Plan of Merger By and Among  Carolina  Power                                 X
                  & Light Company,  North Carolina  Natural Gas  Corporation
                  and  Carolina   Acquisition   Corporation,   dated  as  of
                  November  10, 1998 (filed as Exhibit No. 2(b) to Quarterly
                  Report  on  Form  10-Q  for  the  quarterly  period  ended
                  September 30, 1998, File No. 1-3382.)

*2(b)             Agreement and Plan of Merger by and among  Carolina  Power                                 X
                  & Light Company,  North Carolina  Natural Gas  Corporation
                  and  Carolina   Acquisition   Corporation,   Dated  as  of
                  November  10,  1998,  as Amended and  Restated as of April
                  22, 1999 (filed as Exhibit 2 to  Quarterly  Report on Form
                  10-Q for the quarterly  period ended March 31, 1999,  File
                  No. 1-3382).

*2(c)             Agreement and Plan of Exchange, dated as of August 22, X X
                  1999, by and among Carolina Power & Light Company, Florida
                  Progress Corporation and CP&L Holdings, Inc.
                  (filed as Exhibit 2.1 to Current  Report on Form 8-K dated
                  August 22, 1999, File No. 1-3382).

*2(d)             Amended and Restated  Agreement  and Plan of Exchange,  by           X                     X
                  and  among  Carolina   Power  &  Light  Company,   Florida
                  Progress  Corporation  and CP&L Energy,  Inc.,  dated as of
                  August 22, 1999,  amended and restated as of March 3, 2000
                  (filed as Annex A to Joint  Preliminary Proxy Statement of
                  Carolina  Power  &  Light  Company  and  Florida  Progress
                  Corporation dated March 6, 2000, File No. 1-3382).

*3a(1)            Restated Charter of Carolina Power & Light Company, as                                     X
                  amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly
                  Report on Form 10-Q for the quarterly period ended June 30,
                  1995, File No. 1-3382).

*3a(2)            Restated Charter of Carolina Power & Light Company as                                      X
                  amended on May 10, 1996 (filed as Exhibit No. 3(i) to
                  Quarterly Report on Form 10-Q for the quarterly period ended
                  June 30, 1997, File No. 1-3382).

*3a(3)            Amended and  Restated  Articles of  Incorporation  of CP&L           X
                  Energy,  Inc.,  as amended  and  restated on June 15, 2000
                  (filed as Exhibit No.  3a(1) to  Quarterly  Report on Form
                  10-Q for the  quarterly  period ended June 30, 2000,  File
                  No. 1-15929 and No. 1-3382).


                                      187
<PAGE>

*3b(1)            Amended and Restated Articles of Incorporation of CP&L               X
                  Energy, Inc., as amended and restated on December 4, 2000
                  (filed as Exhibit 3b(1) to Annual Report on Form 10-K dated
                  March 28, 2002, File No. 1-3392 and 1-15929).

*3b(2)            By-Laws of Carolina Power & Light Company, as amended on                                   X
                  December 12, 2001 (filed as Exhibit 3b(2) to Annual Report on
                  Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929).

*3b(3)            By-Laws of Progress Energy, Inc., as amended and restated            X
                  December 12, 2001 (filed as Exhibit No. 3 to Current Report on
                  Form 8-K dated January 17, 2002, File No. 1-15929).

*4a(1)            Resolution of Board of Directors,  dated December 8, 1954,                                 X
                  authorizing the issuance of, and  establishing  the series
                  designation,  dividend  rate  and  redemption  prices  for
                  Carolina Power & Light Company's  Serial  Preferred  Stock,
                  $4.20  Series  (filed as Exhibit 3(c), File No. 33-25560).

*4a(2)            Resolution of Board of Directors,  dated January 17, 1967,                                 X
                  authorizing the issuance of, and  establishing  the series
                  designation,  dividend  rate  and  redemption  prices  for
                  Carolina Power & Light Company's  Serial  Preferred  Stock,
                  $5.44  Series  (filed as Exhibit 3(d), File No. 33-25560).

*4a(3)            Statement of  Classification  of Shares dated  January 13,                                 X
                  1971,  relating to the  authorization of, and establishing
                  the  series  designation,  dividend  rate  and  redemption
                  prices for Carolina Power & Light Company's Serial Preferred
                  Stock,  $7.95  Series (filed as Exhibit 3(f), File No. 33-25560).

*4a(4)            Statement of  Classification  of Shares dated September 7,                                 X
                  1972,  relating to the  authorization of, and establishing
                  the  series  designation,  dividend  rate  and  redemption
                  prices for Carolina Power & Light Company's Serial Preferred
                  Stock,  $7.72  Series (filed as Exhibit 3(g), File No. 33-25560).

*4b(1)            Mortgage and Deed of Trust dated as of May 1, 1940 between                                 X
                  Carolina Power & Light Company and The Bank of New York formerly,
                  Irving Trust Company) and Frederick G. Herbst (Douglas J.
                  MacInnes,  Successor),  Trustees  and  the  First  through
                  Fifth Supplemental  Indentures thereto (Exhibit 2(b), File
                  No. 2-64189);  the Sixth through Sixty-sixth  Supplemental
                  Indentures  (Exhibit 2(b)-5,  File  No.  2-16210;  Exhibit
                  2(b)-6,   File  No. 2-16210;   Exhibit  4(b)-8,  File  No.
                  2-19118;   Exhibit 4(b)-2,   File  No.  2-22439;   Exhibit
                  4(b)-2, File No. 2-24624;  Exhibit 2(c), File No. 2-27297;
                  Exhibit 2(c),  File No.  2-30172;  Exhibit 2(c),  File No.
                  2-35694;  Exhibit 2(c),  File No.  2-37505;  Exhibit 2(c),
                  File No. 2-39002;  Exhibit 2(c), File No. 2-41738; Exhibit
                  2(c),  File No.  2-43439;  Exhibit 2(c), File No. 2-47751;
                  Exhibit 2(c),   File  No.  2-49347;   Exhibit  2(c),  File
                  No. 2-53113;  Exhibit  2(d),  File  No.  2-53113;  Exhibit
                  2(c),  File No.  2-59511;  Exhibit 2(c), File No. 2-61611;
                  Exhibit 2(d),   File  No.  2-64189;   Exhibit  2(c),  File
                  No. 2-65514;  Exhibits  2(c) and 2(d),  File No.  2-66851;
                  Exhibits 4(b)-1,  4(b)-2,  and 4(b)-3,  File  No. 2-81299;
                  Exhibits   4(c)-1  through   4(c)-8,   File   No. 2-95505;
                  Exhibits 4(b) through 4(h),  File No.  33-25560;  Exhibits

                                      188
<PAGE>

                  4(b) and 4(c), File No. 33-33431;  Exhibits 4(b) and 4(c),
                  File  No.  33-38298;  Exhibits  4(h)  and  4(i),  File No.
                  33-42869;  Exhibits 4(e)-(g), File No. 33-48607;  Exhibits
                  4(e) and 4(f), File No. 33-55060;  Exhibits 4(e) and 4(f),
                  File   No.   33-60014;   Exhibits   4(a)   and   4(b)   to
                  Post-Effective   Amendment  No.  1,  File  No.   33-38349;
                  Exhibit 4(e),  File No.  33-50597;  Exhibit 4(e) and 4(f),
                  File No.  33-57835;  Exhibit to Current Report on Form 8-K
                  dated August 28, 1997,  File No. 1-3382;  Form of Carolina
                  Power & Light Company First  Mortgage  Bond,  6.80% Series
                  Due  August  15,  2007 filed as Exhibit 4 to Form 10-Q for
                  the period  ended  September  30, 1998,  File No.  1-3382;
                  Exhibit  4(b),  File No.  333-69237;  and Exhibit  4(c) to
                  Current Report on Form 8-K dated March 19, 1999,  File No.
                  1-3382.);  and  the  Sixty-eighth  Supplemental  Indenture
                  (Exhibit  No.  4(b) to  Current  Report  on Form 8-K dated
                  April  20,  2000,  File No.  1-3382;  and the  Sixty-ninth
                  Supplemental   Indenture  (Exhibit  No.  4b(2)  to  Annual
                  Report  on Form  10-K  dated  March  29,  2001,  File  No.
                  1-3382);  and  the  Seventieth   Supplemental   Indenture,
                  (Exhibit  4b(3) to Annual  Report on Form 10-K dated March
                  29,  2001,  File  No.  1-3382);   and  the   Seventy-first
                  Supplemental  Indenture (Exhibit 4b(2) to Annual Report on
                  Form 10-K dated March 28, 2002).

*4b(2)            Seventy-second   Supplemental   Indenture,   dated  as  of                                 X
                  September  1,  2003,  to PEC  Mortgage  and  Deed of Trust
                  dated May 1,  1940,  between  PEC and The Bank of New York
                  and Douglas J. MacInnes,  as Trustees  (filed as Exhibit 4
                  to PEC Report on Form 8-K dated  September 12, 2003,  File
                  No.1-03382).

*4c(1)            Indenture,   dated  as  of  February  15,  2001,   between           X
                  Progress  Energy,  Inc. and Bank One Trust Company,  N.A.,
                  as  Trustee,  with  respect  to  Senior  Notes  (filed  as
                  Exhibit 4(a) to Form 8-K dated  February  27,  2001,  File
                  No. 1-15929).

*4c(2)            Indenture,  dated  as of March 1,  1995,  between  Carolina                                X
                  Power & Light Company Bankers  Trust  Company,  as  Trustee,
                  with  respect  to Unsecured  Subordinated  Debt Securities
                  (filed as Exhibit No.  4(c) to  Current  Report on Form 8-K
                  dated  April 13, 1995, File No. 1-3382).

*4c(3)            Resolutions  adopted  by the  Executive  Committee  of the                                 X
                  Board of  Directors  at a meeting  held on April 13, 1995,
                  establishing  the  terms  of the  8.55%  Quarterly  Income

                                      189
<PAGE>

                  Capital  Securities  (Series  A  Subordinated   Deferrable
                  Interest  Debentures)  (filed as  Exhibit  4(b) to Current
                  Report on Form 8-K dated April 13, 1995, File No. 1-3382).

*4d               Indenture (for Senior Notes), dated as of March 1, 1999                                    X
                  between Carolina Power & Light Company and The Bank of New
                  York, as Trustee, (filed as Exhibit No. 4(a) to Current
                  Report on Form 8-K dated March 19, 1999, File No.
                  1-3382),  and the First  and  Second  Supplemental  Senior
                  Note  Indentures  thereto  (Exhibit  No.  4(b) to  Current
                  Report  on  Form  8-K  dated  March  19,  1999,  File  No.
                  1-3382);  Exhibit No.  4(a) to Current  Report on Form 8-K
                  dated April 20, 2000, File No. 1-3382).

*4e               Indenture (For Debt  Securities),  dated as of October 28,                                 X
                  1999 between  Carolina Power & Light Company and The Chase
                  Manhattan  Bank,  as  Trustee  (filed as  Exhibit  4(a) to
                  Current  Report on Form 8-K dated  November 5, 1999,  File
                  No. 1-3382), and an Officer's  Certificate issued pursuant
                  thereto,  dated as of October 28,  1999,  authorizing  the
                  issuance  and sale of  Extendible  Notes due  October  28,
                  2009  (Exhibit  4(b) to  Current  Report on Form 8-K dated
                  November 5, 1999, File No. 1-3382).

*4f               Contingent  Value  Obligation   Agreement,   dated  as  of           X
                  November 30, 2000, between CP&L Energy,  Inc. and The Chase
                  Manhattan Bank, as Trustee  (Exhibit 4.1 to Current Report
                  on Form 8-K dated December 12, 2000, File No. 1-3382).

*10a(1)           Purchase,  Construction and Ownership Agreement dated July                                 X
                  30, 1981 between  Carolina Power & Light Company and North
                  Carolina  Municipal  Power Agency  Number 3 and  Exhibits,
                  together with resolution  dated December 16, 1981 changing
                  name to North  Carolina  Eastern  Municipal  Power Agency,
                  amending  letter dated  February 18, 1982,  and  amendment
                  dated   February   24,  1982   (filed  as   Exhibit 10(a),
                  File No. 33-25560).

*10a(2)           Operating and Fuel  Agreement  dated July 30, 1981 between                                 X
                  Carolina   Power  &  Light  Company  and  North   Carolina
                  Municipal  Power Agency  Number 3 and  Exhibits,  together
                  with  resolution  dated December 16, 1981 changing name to
                  North Carolina  Eastern  Municipal Power Agency,  amending
                  letters  dated August 21, 1981 and December 15, 1981,  and
                  amendment    dated    February    24,   1982   (filed   as
                  Exhibit 10(b), File No. 33-25560).

*10a(3)           Power  Coordination  Agreement dated July 30, 1981 between                                 X
                  Carolina   Power  &  Light  Company  and  North   Carolina
                  Municipal  Power Agency  Number 3 and  Exhibits,  together
                  with  resolution  dated December 16, 1981 changing name to
                  North  Carolina   Eastern   Municipal   Power  Agency  and
                  amending   letter   dated   January  29,  1982  (filed  as
                  Exhibit 10(c), File No. 33-25560).

                                      190
<PAGE>

*10a(4)           Amendment   dated   December   16,   1982   to   Purchase,                                 X
                  Construction  and Ownership  Agreement dated July 30, 1981
                  between  Carolina Power & Light Company and North Carolina
                  Eastern  Municipal  Power Agency (filed as Exhibit  10(d),
                  File No. 33-25560).

*10a(5)           Agreement Regarding New Resources and Interim Capacity                                     X
                  between Carolina Power & Light Company and North Carolina
                  Eastern Municipal Power Agency dated October 13, 1987 (filed
                  as Exhibit 10(e), File No. 33-25560).

*10a(6)           Power   Coordination   Agreement  -  1987A  between  North                                 X
                  Carolina  Eastern  Municipal  Power  Agency  and  Carolina
                  Power  &  Light  Company  for  Contract   Power  From  New
                  Resources Period 1987-1993 dated  October 13,  1987 (filed
                  as Exhibit 10(f), File No. 33-25560).

*10b(1)           Progress  Energy,  Inc.  $250,000,000  364-Day Amended and           X
                  Restated Credit  Agreement  dated as of November  10, 2003
                  (filed as Exhibit  10(i) to Quarterly  Report on Form 10-Q
                  for the period ended  September 30, 2003, File No. 1-03382
                  and 1-15929).

 *10b(2)          Amendment and Restatement, dated as of July 30, 2003, to the                               X
                  364-Day Revolving Credit Agreement among PEC and certain
                  Lenders (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q
                  for the period ended June 30, 2003, File No. 1-3382 and 1-15929).

*10b(3)           Notice, dated March 25, 2003 to the Agent for the Lenders named                            X
                  in the PEC 364-Day Revolving Credit Agreement dated July 31,
                  2002, of a commitment reduction in the amount of $120,000,000
                  (filed  as  Exhibit  10(ii) to Quarterly Report on Form 10-Q
                  for the period  ended  March 31, 2003, File No. 1-03382 and
                  1-15929).

*10b(4)           Assumption Agreement from The Bank of New York dated August 5,                             X
                  2002 for a total commitment of $25 million, increasing the
                  amount of the PEC 364-Day and 3-Year Revolving  Credit
                  Agreements, dated July 31, 2002, to $285,000,000 each
                  (filed as Exhibit 10(v)  to Quarterly  Report on Form 10-Q
                  for the period  ended September 30, 2002,  File No. 1-03382
                  and 1-15929).

 *10b(5)          Carolina  Power  &  Light  Company   $272,500,000  364-Day                                 X
                  Revolving  Credit  Agreement  dated  as of July  31,  2002
                  (filed as Exhibit 10(iv) to Quarterly  Report on Form 10-Q
                  for the period ended  September 30, 2002,  File No. 1-3382).

 *10b(6)          Assumption  Agreement  from  The  Bank of New  York  dated                                 X
                  August  5,  2002 for a total  commitment  of $25  million,
                  increasing  the  amount  of the  PEC  364-Day  and  3-Year
                  Revolving Credit  Agreements dated as of July 31, 2002, to

                                      191
<PAGE>

                  $285,000,000  each  (filed as exhibit  10(v) to  Quarterly
                  Report  on  Form  10-Q  for  the  quarterly  period  ended
                  September 30, 2002, File No. 1-3382 and 1-15929).

 *10b(7)          Amendment and Restatement  dated July 26, 2002 to Progress                                 X
                  Energy,   Inc.'s   $450,000,000  3-Year  Revolving  Credit
                  Agreement dated November 13, 2001 as amended  February 13,
                  2002 (filed as Exhibit  10(i) to Quarterly  Report on Form
                  10-Q for the  quarterly  period ended  September 30, 2002,
                  File No. 1-3382 and 1-15929).

*10b(8)           Amendment,  dated  February 13, 2002, to Progress  Energy,           X
                  Inc.  $450,000,000 3-Year Revolving Credit Agreement dated
                  November  13,  2001  (filed  as  Exhibit  10b(8) to Annual
                  Report on Form 10-K dated March 28, 2002,  File No. 1-3392
                  and 1-15929).

*10b(9)           Progress Energy, Inc. $450,000,000 3-Year Revolving Credit           X
                  Agreement dated as of November 13, 2001 (filed as Exhibit
                  10b(6) to Annual Report on Form 10-K dated March 28, 2002,
                  File No. 1-3392 and 1-15929).

*10b(10)          PEF 364-Day $200,000,000 Credit Agreement dated as of April          X
                  1, 2003 (filed as Exhibit 10(ii) to Florida Power Corporation
                  Form 10-Q for the quarter ended March 31, 2003).

*10b(11)          PEF 3-Year $200,000,000 Credit Agreement, dated as of April          X
                  1, 2003 (filed as Exhibit 10(iii) to the Florida Power
                  Corporation Form 10-Q for the quarter ended March 31, 2003).

-+*10c(1)         Directors Deferred Compensation Plan effective January 1,                                  X
                  1982 as amended (filed as Exhibit 10(g), File No. 33-25560).

-+*10c(2)         Retirement Plan for Outside Directors (filed as Exhibit                                    X
                  10(i), File No. 33-25560).

-+*10c(3)         Key Management Deferred Compensation Plan (filed as Exhibit                                X
                  10(k), File No. 33-25560).

+*10c(4)          Resolutions of the Board of Directors, dated March 15,                                     X
                  1989, amending the Key Management Deferred Compensation Plan
                  (filed as Exhibit 10(a), File No. 33-48607).

-+*10c(5)         Resolutions of the Board of Directors dated May 8, 1991,             X                     X
                  amending the PEC Directors Deferred Compensation Plan (filed
                  as Exhibit 10(b), File No. 33-48607).

+*10c(6)          Resolutions of Board of Directors dated July 9, 1997,                                      X
                  amending the Deferred Compensation Plan for Key Management
                  Employees of Carolina Power & Light Company.

                                      192
<PAGE>

+*10c(7)          Progress  Energy,  Inc.  Non-Employee  Director Stock Unit           X                     X
                  Plan,  amended and restated effective July 10, 2002 (filed
                  as  Exhibit  10(ii) to  Quarterly  Report on Form 10-Q for
                  the  period  ended June 30,  2003,  File No.  1-03382  and
                  1-15929).

-+*10c(8)         Carolina   Power  &   Light   Company   Restricted   Stock           X                     X
                  Agreement,  as approved  January 7, 1998,  pursuant to the
                  Company's  1997  Equity  Incentive  Plan (filed as Exhibit
                  No. 10 to Quarterly  Report on Form 10-Q for the quarterly
                  period ended March 31, 1998, File No. 1-3382.)

-+*10c(9)         Progress  Energy,  Inc.  Restoration  Retirement  Plan, as           X                     X
                  amended  and  restated  July 10,  2002  (filed as  Exhibit
                  10(i) to  Quarterly  Report  on Form  10-Q for the  period
                  ended June 30, 2003, File No. 1-3382 and 1-15929).

-+*10c(10)        Amended  and  Restated   Supplemental   Senior   Executive           X                     X
                  Retirement Plan of Progress Energy,  Inc., as last amended
                  July 10,  2002  (filed as Exhibit  10b(iii)  to  Quarterly
                  Report on Form 10-Q for the period  ended  June 30,  2003,
                  File No. 1-3382 and 1-15929).

-+*10c(11)        Performance  Share  Sub-Plan of the 2002 Progress  Energy,           X                     X
                  Inc. Equity  Incentive Plan,  dated July 9, 2002 (filed as
                  Exhibit  10(vii) to Quarterly  Report on Form 10-Q for the
                  quarterly  period  ended  September  30,  2002,  File  No.
                  1-3382 and 1-15929).

-+*10c(12)        Performance  Share  Sub-Plan of the 1997 Equity  Incentive           X                     X
                  Plan,  as  amended  January  1,  2001  (filed  as  Exhibit
                  10c(11)  to Annual  Report on Form  10-K  dated  March 28,
                  2002, File No. 1-3382 and 1-15929).

+*10c(13)         2002 Progress Energy,  Inc. Equity Incentive Plan, amended           X                     X
                  and  restated  July 10, 2002  (filed as Exhibit  10(vi) to
                  Quarterly  Report  on Form 10-Q for the  quarterly  period
                  ended September 30, 2002, File No. 1-3382 and 1-15929).

+*10c(14)         1997 Equity Incentive Plan, Amended and Restated as of               X                     X
                  September 26, 2001 (filed as Exhibit 4.3 to Progress Energy
                  Form S-8 dated September 27, 2001, File No.
                  1-3382).

+*10c(15)         Progress Energy, Inc. Form of Stock Option Agreement                 X                     X
                  (filed as Exhibit 4.4 to Form S-8 dated September 27, 2001,
                  File No. 333-70332).

+*10c(16)         Progress Energy, Inc. Form of Stock Option Award (filed as           X                     X
                  Exhibit 4.5 to Form S-8 dated September 27, 2001, File No.
                  333-70332).

                                      193
<PAGE>

-+*10c(17)        Amended   Management   Incentive   Compensation   Plan  of           X                     X
                  Progress  Energy,  Inc., as amended January 1, 2003 (filed
                  as  Exhibit  10(iv) to  Quarterly  Report on Form 10-Q for
                  the  period  ended  June 30,  2003,  File No.  1-3382  and
                  1-15929).

-+*10c(18)        Progress Energy, Inc. Management Deferred                            X                     X
                  Compensation  Plan,  revised and restated as of January 1,
                  2003 (filed as Exhibit 4.3 to Progress  Energy Form S-8 on
                  May 2, 2003, File No. 333-104952).

+*10c(19)         Agreement dated April 27, 1999 between Carolina Power &                                    X
                  Light Company and Sherwood H. Smith, Jr. (filed as Exhibit
                  10b, File No. 1-3382).

+*10c(20)         Employment  Agreement  dated  August 1, 2000  between  CP&L          X
                  Service  Company LLC and William  Cavanaugh  III (filed as
                  Exhibit  10(i) to  Quarterly  Report  on Form 10-Q for the
                  quarterly  period  ended  September  30,  2000,  File  No.
                  1-15929 and No. 1-3382).

+*10c(21)         Employment   Agreement   dated   August  1,  2000  between                                 X
                  Carolina  Power & Light  Company  and  William  S.  "Skip"
                  Orser  (filed as  Exhibit  10(ii) to  Quarterly  Report on
                  Form 10-Q for the  quarterly  period ended  September  30,
                  2000, File No. 1-15929 and No. 1-3382).

+*10c(22)         Employment Agreement dated August 1, 2000 between Carolina                                 X
                  Power & Light Company and Tom Kilgore (filed as Exhibit
                  10(iii) to Quarterly Report on Form 10-Q for the quarterly
                  period ended September 30, 2000, File No.
                  1-15929 and No. 1-3382).

+*10c(23)         Employment  Agreement  dated  August 1, 2000  between  CP&L          X
                  Service  Company LLC and Robert  McGehee (filed as Exhibit
                  10(iv) to Quarterly  Report on Form 10-Q for the quarterly
                  period ended  September 30, 2000, File No. 1-15929 and No.
                  1-3382).

+*10c(24)         Form of Employment Agreement dated August 1, 2000 (i)                X                     X
                  between Carolina Power & Light Company and Don K. Davis; and
                  (ii) between CP&L Service Company LLC and Peter M.
                  Scott III and William D. Johnson  (filed as Exhibit  10(v)
                  to Quarterly  Report on Form 10-Q for the quarterly period
                  ended  September  30,  2000,  File  No.  1-15929  and  No.
                  1-3382).

+*10c(25)         Form of  Employment  Agreement  dated  August  1, 2000 (i)           X                     X
                  between  Carolina  Power & Light  Company and Fred Day IV,
                  C.S.  "Scotty" Hinnant and E. Michael  Williams;  and (ii)
                  between  CP&L  Service  Company  LLC and Bonnie V.  Hancock
                  (filed as Exhibit 10(vi) to Quarterly  Report on Form 10-Q
                  for the quarterly  period ended  September 30, 2000,  File
                  No. 1-15929 and No. 1-3382).

                                      194
<PAGE>

+*10c(26)         Employment  Agreement  dated  November  30,  2000  between           X
                  Carolina Power & Light Company,  Florida Power Corporation
                  and  H.  William   Habermeyer,   Jr.   (filed  as  Exhibit
                  10.(b)(32)  to Florida  Progress  Corporation  and Florida
                  Power  Corporation  Annual  Report  on Form  10-K for the
                  year ended December 31, 2000).

+10c(27)          Form of Employment Agreement between (i) Progress Energy             X
                  Service Company, LLC and Brenda F. Castonguay, effective
                  September 2002; and (ii) Progress Energy Service Company and
                  John R. McArthur, effective January 2003; dated December 15,
                  2003 (filed as Exhibit 10c(27) to Annual Report on Form 10-K
                  for the year ended December 31, 2002, File No. 1-33382 and
                  1-5929).

+10c(28)          Employment Agreement dated October 1, 2003 between Progress          X
                  Energy Service Company, LLC and Geoffrey S. Chatas

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

21                Subsidiaries of Progress Energy, Inc.                                X

23(a)             Consent of Deloitte & Touche LLP.                                    X                     X

31(a)             302 Certification of Chief Executive Officer                         X                     X

31(b)             302 Certification of Chief Financial Officer                         X                     X

32(a)             906 Certification of Chief Executive Officer                         X                     X

32(b)             906 Certification of Chief Financial Officer                         X                     X


*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement required to be filed as
   an exhibit to this report pursuant to Item 14 (c) of Form 10-K.
-Sponsorship of this management contract or compensation plan or arrangement was
   transferred from Carolina Power & Light Company to Progress Energy, Inc.,
   effective August 1, 2000.
</TABLE>


                                      195
<PAGE>

                              PROGRESS ENERGY, INC.
                                 EXHIBIT NO. 12
                COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                 Years Ended December 31,

                                                                 2003            2002            2001          2000         1999
                                                                 ----            ----            ----          ----         ----

                                                                                   (Millions of Dollars)
Earnings, as defined:
  Income from continuing operations before cumulative
   effect of changes in accounting principles               $         811   $         552   $         541  $       478  $      383
  Fixed charges, as below                                             657             667             719          275         193
  Capitalized interest                                                (20)            (38)              -            -           -
  Income taxes, as below                                             (117)           (166)           (162)         188         250
-----------------------------------------------------------------------------------------------------------------------------------
    Total earnings, as defined                              $       1,331   $       1,015   $       1,098  $       941  $      826
===================================================================================================================================

Fixed Charges, as defined:
  Interest on long-term debt                                $         595   $         600   $         578  $       224  $      174
  Other interest                                                       37              41             112           37           7
  Imputed interest factor in rentals-charged
    principally to operating expenses                                  18              19              21            9           7
  Preferred dividend requirements of subsidiaries (a)                   7               7               8            5           5
-----------------------------------------------------------------------------------------------------------------------------------
    Total fixed charges, as defined                         $         657   $         667   $         719  $       275  $      193
===================================================================================================================================

Income Taxes:
    Income tax expense (benefit)                            $        (109)  $        (158)  $        (154) $       196  $     258
    Included in AFUDC - deferred taxes in
       book depreciation                                               (8)             (8)             (8)          (8)         (8)
-----------------------------------------------------------------------------------------------------------------------------------
    Total income taxes                                      $        (117)  $        (166)  $        (162) $       188  $      250
===================================================================================================================================

Ratio of Earnings to Fixed Charges                                   2.03            1.52            1.53         3.42        4.28
</TABLE>


(a)  Preferred  dividends of subsidiaries not deductible times ratio of earnings
     before income taxes to net income







                                      196
<PAGE>

                         PROGRESS ENERGY CAROLINAS, INC.
                                 EXHIBIT NO. 12
              COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
       PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

                                                                                  Years Ended December 31,

                                                                 2003           2002           2001         2000           1999
                                                                 ----           ----           ----         ----           ----

                                                                                    (Millions of Dollars)
Earnings, as defined:
  Income before cumulative effect of change in accounting
   principles                                               $         505  $         431  $        364  $       461  $         382
  Fixed charges, as below                                             200            220           264          246            196
  Income taxes, as below                                              236            199           215          282            250
-----------------------------------------------------------------------------------------------------------------------------------
    Total earnings, as defined                              $         941  $         850  $        843  $       989  $         828
===================================================================================================================================

Fixed Charges, as defined:
  Interest on long-term debt                                $         185  $         205  $        246  $       224  $         181
  Other interest                                                       11             12            11           17             10
  Imputed interest factor in rentals-charged
    principally to operating expenses                                   4              3             7            5              5
-----------------------------------------------------------------------------------------------------------------------------------
    Total fixed charges, as defined                         $         200  $         220  $        264  $       246  $         196
===================================================================================================================================

Earnings Before Income Taxes                                $         741  $         630  $        579  $       743  $         632

Ratio of Earnings Before Income Taxes to Income before               1.47           1.46          1.59         1.61           1.65
    cumulative effect of change in accounting principles

Income Taxes:
    Income tax expense                                      $         244  $         207  $        223  $       290  $         258
    Included in AFUDC - deferred taxes in
       book depreciation                                              (8)             (8)           (8)          (8)            (8)
-----------------------------------------------------------------------------------------------------------------------------------
    Total income taxes                                      $         236  $         199  $        215  $       282  $         250
===================================================================================================================================

Fixed Charges and Preferred Dividends Combined:
  Preferred dividend requirements                           $           3  $           3  $          3  $         3  $           3
  Portion deductible for income tax purposes                            -              -             -            -              -
  Preferred dividend requirements not deductible            $           3  $           3  $          3  $         3  $           3

Preferred dividend factor:
    Preferred dividends not deductible times ratio of
      earnings before income taxes to net income            $           4  $           4  $          5  $         5  $           5
    Preferred dividends deductible for income taxes                     -              -             -            -              -
    Fixed charges, as above                                           200            220           264          246            196
-----------------------------------------------------------------------------------------------------------------------------------
      Total fixed charges and preferred dividends combined  $         204  $         224  $        269  $       251  $         201
===================================================================================================================================

Ratio of Earnings to Fixed Charges                                   4.71           3.86          3.19         4.02           4.22

Ratio of Earnings to Fixed Charges and Preferred
  Dividends Combined                                                 4.61           3.79          3.13         3.94           4.12
</TABLE>


                                      197
<PAGE>

                                                                     Exhibit 21


                      SUBSIDIARIES OF PROGRESS ENERGY, INC.
                              AT DECEMBER 31, 2003


The following is a list of certain direct and indirect subsidiaries of Progress
Energy, Inc. and their respective states of incorporation:
<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>

        Carolina Power & Light Company d/b/a PEC                             North Carolina

        Florida Progress Corporation                                         Florida
                 Florida Power Corporation d/b/a/ PEF                        Florida
                 Progress Telecommunications Corporation                     Florida
                                Progress Telecom, LLC                        Delaware
                 Progress Capital Holdings, Inc.                             Florida
                          Progress Fuels Corporation                         Florida
                                   Progress Rail Services Corporation        Alabama

        Progress Ventures, Inc.                                              North Carolina

        Strategic Resource Solutions Corp.                                   North Carolina

        Progress Energy Service Company, LLC                                 North Carolina
</TABLE>


                                      198
<PAGE>

                                                                  Exhibit 23(a)


                          INDEPENDENT AUDITORS' CONSENT


We consent to the  incorporation  by reference  in  Registration  Statement  No.
33-33520 on Form S-8,  Post-Effective  Amendment 1 to Registration Statement No.
33-38349  on Form  S-3,  Registration  Statement  No.  333-81278  on  Form  S-3,
Registration  Statement No. 333-81278-01 on Form S-3, Registration Statement No.
333-81278-02 on Form S-3,  Registration  Statement No. 333-81278-03 on Form S-3,
Post-Effective  Amendment 1 to Registration Statement No. 333-69738 on Form S-3,
Registration  Statement No.  333-70332 on Form S-8,  Registration  Statement No.
333-87274 on Form S-3, Post-Effective  Amendment 1 to Registration Statement No.
333-47910  on Form  S-3,  Registration  Statement  No.  333-52328  on Form  S-8,
Post-Effective  Amendment 1 to Registration Statement No. 333-89685 on Form S-8,
and Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of
our reports dated February 20, 2004 (which  express an  unqualified  opinion and
include an  explanatory  paragraph  concerning  the  adoption of new  accounting
principles  in 2003 and 2002);  appearing in this Annual  Report on Form 10-K of
Progress Energy, Inc. for the year ended December 31, 2003.

We also consent to the incorporation by reference in Registration  Statement No.
333-58800 on Form S-3 of Carolina  Power & Light Company d/b/a  Progress  Energy
Carolinas,  Inc.  (PEC) of our reports dated February 20, 2004 (which express an
unqualified  opinion  and  includes  an  explanatory  paragraph  concerning  the
adoption of new accounting principles in 2003),  appearing in this Annual Report
on Form 10-K of (PEC) for the year ended December 31, 2003.


/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 12, 2004




                                      199