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, 2004
                                       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
</TABLE>

           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


<TABLE>
<S>                                                  <C>
           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
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
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. [ X ]

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

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

                                       1
<PAGE>

As of June 30, 2004,  the  aggregate  market value of the voting and  non-voting
common   equity  of  Progress   Energy,   Inc.   held  by   non-affiliates   was
$10,653,481,488.  As of June 30, 2004, 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.

As of March 4, 2005,  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)     248,533,367
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, 2005 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, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES

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 DISCLOSURES 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

ITEM 9B. OTHER INFORMATION

                                    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

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                    Broad River LLC's Broad River Facility
Btu                            British thermal unit
CAIR                           Clean Air Interstate Rule
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, LLLP
the Company                    Progress Energy, Inc. and subsidiaries
CP&L                           Carolina Power & Light Company
CP&L Energy                    CP&L Energy, Inc.
CR3                            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
ETS                            Engineering and Track-work
ECRC                           Environmental Cost Recovery Clause
EITF                           Emerging Issues Task Force
EMCs                           Electric Membership Cooperatives
ENCNG                          Eastern North Carolina Natural Gas Company, formerly referred to as
                               EasternNC
EPA of 1992                    Energy Policy Act of 1992
EPIK                           EPIK Communications, Inc.
ESOP                           Employee Stock Ownership Plan
FASB                           Financial Accounting Standards Board
FDEP                           Florida Department of Environment and Protection
FERC                           Federal Energy Regulatory Commission
FIN No. 45                     Financial Accounting Standards Board (FASB) Interpretation No. 45,
                               "Guarantor's Accounting and Disclosure Requirements for Guarantees,
                               Including Indirect Guarantees of Indebtedness of Others"
FIN No. 46R                    FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities -
                               an Interpretation of ARB No. 51"
Florida Progress or FPC        Florida Progress Corporation
FPSC                           Florida Public Service Commission
Fuels                          Fuels business segment
Funding Corp.                  Florida Progress Funding Corporation
GAAP                           Accounting Principles Generally Accepted in the United States of America
Genco                          Progress Genco Ventures LLC
Georgia Power                  Georgia Power Company
Global                         U.S. Global LLC
Harris Plant                   Shearon Harris Nuclear Plant
the holding company            Progress Energy Corporate
Interpath                      Interpath Communications, Inc.
IBEW                           International Brotherhood of Electrical Workers
IRS                            Internal Revenue Service
ISO                            Independent System Operator

                                       4
<PAGE>

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
Medicare Act                   Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP                            Manufactured Gas Plant
MW                             Megawatt
MWh                            Megawatt-hour
NC Clean Air                   North Carolina Clean Smokestacks Act enacted in June 2002
NCNG                           North Carolina Natural Gas Corporation
NCUC                           North Carolina Utilities Commission
NDE                            Nondestructive Examination
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
O&M                            Operations & Maintenance Expense
Odyssey                        Odyssey Telecorp, Inc.
OPEB                           Postretirement benefits other than pensions
P11                            Intercession Unit P11
PCH                            Progress Capital Holdings, Inc.
PEC                            Progress Energy Carolinas, Inc.
PEC Electric                   PEC Electric business segment made up of the utility operations and
                               excludes operations of nonregulated subsidiaries
PEF                            Progress Energy Florida
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
Preferred Securities           FPC-obligated mandatorily redeemable preferred securities of FPC Capital I
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
PRP                            Potentially responsible party, as defined in CERCLA
PSSP                           Performance Share Sub-Plan
PTC                            Progress Telecommunications Corporation
PT LLC                         Progress Telecom, LLC
PUHCA                          Public Utility Holding Company Act of 1935, as amended
PURPA                          Public Utilities Regulatory Policies Act of 1978
PVI                            Progress Energy Ventures, Inc. (formerly referred to as CPL Energy
                               Ventures, Inc.)
PWR                            Pressurized water reactor
QF                             Qualifying facility
Rail Services                  Rail Services business segment
RCA                            Revolving credit agreement
Rockport                       Indiana Michigan Power Company's Rockport Unit No. 2
Robinson                       PEC's Robinson Nuclear Plant
ROE                            Return on Equity
RSA                            Restricted Stock Awards program
RTO                            Regional Transmission Organization

                                       5
<PAGE>

SCPSC                          Public Service Commission of South Carolina
SEC                            U.S. Securities and Exchange Commission
Section 29                     Section 29 of the Internal Revenue Service Code
(See Note/s "#")               For all Sections, except the Carolina Power & Light Company Financial
                               Statements in Part II, Item 8, this is a reference to the Notes in the
                               Progress Energy Consolidated Financial Statements in Part II, Item 8
Service Company                Progress Energy Service Company, LLC
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. 109                   Statement of Financial Accounting Standards No. 109, "Accounting for Income
                               Taxes"
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. 123R                  Statement of Financial Accounting Standards No. 123R, "Accounting for
                               Stock-Based Compensation"
SFAS No. 133                   Statement of Financial Accounting Standards No. 133, "Accounting for
                               Derivative and Hedging Activities"
SFAS No. 138                   Statement of Financial Accounting Standards No. 138, "Accounting for
                               Certain Derivative Instruments and Certain Hedging Activities - An
                               Amendment of FASB Statement No. 133"
SFAS No. 142                   Statement of Financial Accounting Standards No. 142, "Goodwill and Other
                               Intangible Assets"
SFAS No. 143                   Statement of Financial Accounting Standards No. 143, "Accounting for Asset
                               Retirement Obligations"
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
Winchester Energy              Winchester Energy Company, Ltd. (formerly Westchester Gas Company)
Winchester Production          Winchester Production Company, Ltd., an indirectly owned subsidiary of
                               Progress Fuels Corporation
</TABLE>

                                       6
<PAGE>


                   SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

Certain  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 1) 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:  a) "Results  of  Operations"  about  trends and
uncertainties;  b) "Liquidity and Capital Resources" about operating cash flows,
estimated capital requirements through the year 2007 and future financing plans;
c) "Strategy" about Progress Energy,  Inc.'s,  strategy;  and d) "Other Matters"
about the  effects of new  environmental  regulations,  nuclear  decommissioning
costs  and  the  effect  of  electric  utility  industry  restructuring;  and 2)
statements made in the "Risk Factors" sections.

Any forward-looking  statement is based on information current as of the date of
this report and speaks only as of the date on which such  statement is made, and
neither Progress Energy, Inc., (the Company) nor Progress Energy Carolinas (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;  deregulation or  restructuring in
the electric  industry that may result in increased  competition and unrecovered
(stranded)  costs;  the ability of the Company to implement its cost  management
initiatives  as planned;  the  uncertainty  regarding  the timing,  creation and
structure  of  regional  transmission  organizations;  weather  conditions  that
directly influence the demand for electricity;  the Company's ability to recover
through the  regulatory  process,  and the timing of such recovery of, the costs
associated with the four hurricanes that impacted our service  territory in 2004
or other future significant weather events;  recurring seasonal  fluctuations in
demand for  electricity;  fluctuations  in the price of energy  commodities  and
purchased  power;  economic  fluctuations  and the  corresponding  impact on the
Company and its subsidiaries'  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 on the
Company's  financial  condition and ability to meet its cash and other financial
obligations  in the event its credit  ratings are  downgraded  below  investment
grade;  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;  the Company's  ability to
control  costs,  including  pension  and benefit  expense,  and achieve its cost
management  targets for 2007; 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 impact to the Company's  financial condition
and  performance  in the event it is  determined  the Company is not entitled to
previously  taken  Section  29 tax  credits;  the  impact of  future  accounting
pronouncements  regarding  uncertain  tax  positions;  the outcome of PEF's rate
proceeding  in 2005  regarding its future base rates;  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;  the  outcome  of any  ongoing or future
litigation  or similar  disputes  and the impact of any such  outcome or related
settlements;  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 and
PEC's filings with the United States  Securities and Exchange  Commission (SEC).
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.  The Company is 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.,  (PVI) began doing  business  under the 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 and there was no restructuring of any kind related to the name change.

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.  The
Progress  Ventures  business unit consists of the Fuels business segment (Fuels)
and  Competitive  Commercial  Operations  (CCO)  operating  segments.   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.  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 and  commodity  economic  hedging  activities.  Through its Rail Services
business  segment (Rail  Services),  Progress Energy engages in various rail and
railcar-related  services. In February 2005, Progress Energy signed a definitive
agreement to sell its Progress Rail subsidiary for a sales price of $405 million
(See Note 24). The Corporate and Other  Businesses  segment  primarily  includes
Service Company activities,  miscellaneous  nonregulated  activities and holding
company operations.  For information  regarding the revenues,  income and assets
attributable  to the Company's  business  segments,  See Note 20 to the Progress
Energy Consolidated Financial Statements in PART II, ITEM 8.

The Company  has  approximately  24,000  megawatts  (MW) of electric  generation
capacity  and serves  approximately  2.9 million  retail  electric  customers in
portions of North  Carolina,  South  Carolina  and Florida and also serves other
load-serving  entities.  PEC's and PEF's  customer  base and  demand  cycles are
complementary. Historically, PEC normally has a summer peaking demand, while PEF
normally 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 Company's electric generation capacity and delivering
reliable, competitively priced energy.

Progress Energy revenues for the year ended December 31, 2004, were $9.8 billion
and assets at year-end were $26.0 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 Web
site 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.

                                       8
<PAGE>

SIGNIFICANT DEVELOPMENTS

Sale of Natural Gas Assets

In December 2004, the Company sold certain gas-producing  properties and related
assets owned by Winchester Production Company, Ltd. (Winchester Production),  an
indirectly  owned  subsidiary of Progress Fuels  Corporation  (Progress  Fuels),
which is included in the Fuels  segment.  Net  proceeds  of  approximately  $251
million were used to reduce debt (See Note 4A).

2004 Hurricanes

Hurricanes Charley,  Frances, Ivan and Jeanne struck significant portions of the
Company's service  territories  during the third quarter of 2004,  significantly
impacting PEF's territory. As of December 31, 2004, restoration of the Company's
systems from  hurricane  related  damage was estimated at $398 million (See Note
3).

Divestiture of Synthetic Fuel Partnership Interests

In June 2004, the Company,  through its subsidiary  Progress Fuels, sold, in two
transactions,  a combined 49.8%  partnership  interest in Colona Synfuel Limited
Partnership,  LLLP,  one of its synthetic  fuel  facilities.  Substantially  all
proceeds  from the sales will be  received  over time,  which is typical of such
sales in the industry (See Note 4B).

Railcar Ltd., Divestiture

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 of approximately $75 million were used to reduce debt (See Note 4C).

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  (PT  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 PT LLC (See Note 5A).

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. Net proceeds of
approximately $97 million were used to reduce debt (See Note 4D).

NCNG Divestiture

In September 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 $443 million were used to reduce debt (See Note 4E).

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  approximately  $168 million (See Note
5B).

                                       9
<PAGE>

Wholesale Energy Contract Acquisition

In May 2003, Progress Ventures,  Inc. (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 Note 5C).

Westchester Acquisition

In  April  2002,  Progress  Fuels  acquired  100%  of  Westchester  Gas  Company
(Westchester).  During 2004,  the name of the company was changed to  Winchester
Energy Co. Ltd., (Winchester Energy). 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 Note 5D).

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 Note 5E).

Florida Progress Acquisition

On November 30, 2000, the Company  completed its acquisition of Florida Progress
Corporation (FPC), a diversified,  exempt electric utility holding company,  for
an aggregate purchase price of approximately $5.4 billion. The Company paid cash
consideration  of  approximately  $3.5 billion and issued 46.5 million shares of
common stock valued at  approximately  $1.9  billion.  In addition,  the Company
issued 98.6 million  contingent value obligations (CVOs) valued at approximately
$49 million.

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

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 2004 working on a  comprehensive  energy bill.
While  that  legislation  passed  the  House,  the  Senate  failed  to pass  the
legislation  in 2004.  The  Company  expects  that  there  will be an  effort to
resurrect the legislation in 2005. 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 nonutility 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.

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.

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.

                                       10
<PAGE>

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
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.  These standards have
been clarified and supplemented by subsequent FERC orders.  The new standards of
conduct govern the relationship between transmission  providers and their energy
affiliates in a manner that  prevents  excessive  market power and  preferential
treatment.  Each  utility  was  required  to  submit  a plan  and  schedule  for
compliance with the new rules by February 2004. PEC and PEF have complied in all
material  respects with all of the requirements  associated with these standards
and FERC orders.

In April 2004, the FERC issued two orders concerning  utilities' ability to sell
wholesale  electricity  at  market-based  rates.  In the first  order,  the FERC
adopted two new interim screens for assessing potential  generation market power
of  applicants  for  wholesale  market-based  rates,  and  described  additional
analyses and  mitigation  measures that could be presented if an applicant  does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider  whether the FERC's current  methodology
for  determining  whether a public  utility  should be allowed to sell wholesale
electricity at market-based  rates should be modified in any way.  Management is
unable to predict  the outcome of these  actions by the FERC or their  effect on
future results of operations and cash flows. PEF does not have market-based rate
authority for wholesale  sales in peninsular  Florida.  Given the difficulty PEC
believes it would  experience in passing one of the interim  screens,  on August
12,  2004,  PEC notified  the FERC that it would  revise its  Market-based  Rate
tariff  to  restrict  it to  sales  outside  PEC's  control  area and file a new
cost-based  tariff for sales within PEC's  control  area that  incorporates  the
FERC's default  cost-based rate methodologies for sales of one year or less. PEC
anticipates making this filing the first quarter of 2005.

On December 23, 2004, PEF advised the FERC that PEF only has  market-based  rate
authority in Southern  Company's  control area in Georgia.  PEF also advised the
FERC that PEF filed market power studies in 2003  demonstrating that it does not
have market power in that market and that because nothing has changed since that
study was performed, PEF should not have to perform the new tests.

Although the Company cannot predict the ultimate  outcome of these changes,  the
Company does not anticipate  that the current  operations of PEC or PEF would be
impacted  materially if they were unable to sell power at market-based  rates in
their respective control areas.

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,
acquisitions  of  securities  and utility  assets,  and  services  performed  by
Progress Energy Service Company, LLC.

While various proposals, including the 2004 energy bill, have been introduced in
Congress  regarding  PUHCA,  the prospects for legislative  reform or repeal are
uncertain at this time.

                                       11
<PAGE>

REGULATORY MATTERS

GENERAL

PEC is subject to regulation in North Carolina by the North  Carolina  Utilities
Commission  (NCUC),  and in South Carolina by the Public  Service  Commission of
South  Carolina  (SCPSC)  and PEF is  subject  to  regulation  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
cost recovery of unusual or unexpected expense,  such as severe storm costs, and
issuances  of  securities.  PEC and PEF are also  subject to  regulation  by the
United States Nuclear Regulatory Commission (NRC). 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  generating  units and PEF owns and operates
one nuclear  generating unit regulated by the 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.  Nuclear  units are
periodically   removed  from  service  to  accommodate   normal   refueling  and
maintenance outages, repairs and certain other modifications.

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.

On April 19, 2004, the NRC announced  that it has renewed the operating  license
for PEC's Robinson  Nuclear Plant  (Robinson) for an additional 20 years through
July 2030. The original operating license of 40 years was set to expire in 2010.
NRC  operating  licenses  held by PEC  currently  expire  in  December  2014 and
September  2016 for Brunswick  Units 2 and 1,  respectively.  An  application to
extend these  licenses 20 years was submitted in October 2004. The NRC operating
license  held  by PEC  for the  Shearon  Harris  Nuclear  Plant  (Harris  Plant)
currently  expires in October  2026.  An  application  to extend this license 20
years is expected to be submitted in the fourth quarter of 2006.

The NRC  operating  license  held by PEF for  Crystal  River  Unit  No.  3 (CR3)
currently  expires in December  2016. An  application  to extend this license 20
years is expected to be submitted in the first quarter of 2009.

A condition of the operating license for each unit requires an approved plan for
decontamination and decommissioning.

On February 27,  2004,  PEC  requested  to have its license for the  Independent
Spent Fuel Storage  Installation at the Robinson Plant extended by 20 years with
an exemption request for an additional 20-year extension. Its current license is
due to expire in August 2006.  PEC expects to receive this  extension  including
the exemption.

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.

                                       12
<PAGE>

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 Robinson reactor head was re-inspected during its 2004 outage, and no
indication of control rod drive mechanism  cracking or corrosion of the head was
observed.  The head is scheduled for  replacement  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.
The NRC also issued a bulletin  requesting  PWR licensees to address  inspection
plans for reactor pressure vessel lower head penetrations. The Company completed
a bare metal visual  inspection of the vessel bottom at Robinson during its 2004
outage  and at Harris and CR3 during  their 2003  outages  and found no signs of
corrosion  or leakage at any 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 has reviewed the required
inspection  frequencies and has  incorporated  them into long-range  plans.  The
Harris Plant will  complete the required  nonvisual  nondestructive  examination
(NDE)  inspection prior to February 2008. Both CR3 and Robinson will be required
to inspect  their new heads within seven years or four  refueling  outages after
replacement.  CR3 plans to inspect  its new head  prior to the end of 2009,  and
Robinson will need to inspect its new head prior to the end of 2012.

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 at nuclear  facilities and closer  coordination with
the Company's partners in intelligence,  military, law enforcement and emergency
response at the  federal,  state and local  levels.  The Company  completed  the
requirements as outlined in the orders by the committed dates. 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
(2010),  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.

With certain  modifications  and additional  approval by the NRC,  including the
installation  of onsite dry storage  facilities at PEF's  nuclear unit,  Crystal
River Unit No. 3 (CR3),  PEF's spent  nuclear  fuel storage  facilities  will be
sufficient  to provide  storage  space for spent fuel  generated on PEF's system
through the expiration of the operating license for CR3.

See Note 23E and Note 18D to the PGN and PEC Consolidated  Financial Statements,
respectively,  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 Note 6D for a
discussion of PEC and PEF's nuclear decommissioning costs.

                                       13
<PAGE>

ENVIRONMENTAL

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 2005
through 2007 are included in the "Capital Expenditures"  discussion for Progress
Energy under PART II, ITEM 7, "Liquidity and Capital Resources."

The provisions of the  Comprehensive  Environmental  Response,  Compensation and
Liability  Act of 1980,  as amended  (CERCLA),  authorize the EPA to require the
cleanup of hazardous  waste sites.  This statute imposes  retroactive  joint and
several  liabilities.  Some states,  including  North and South  Carolina,  have
similar  types of  legislation.  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  that  may  require   investigation   and/or
remediation.

There are presently several sites, including manufactured gas plant (MGP) 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 a
potentially  responsible  party (PRP).  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 determine the total costs that
may be incurred  in  connection  with all sites at this time.  See Note 22 for a
discussion of the Company's environmental matters.

EMPLOYEES

As  of  February  28,  2005,  Progress  Energy  and  its  subsidiaries  employed
approximately  15,700 full-time  employees.  Of this total,  approximately 2,400
employees at PEF are represented by the International  Brotherhood of Electrical
Workers  (IBEW).  The  three-year  labor  contract with IBEW expires in December
2005.

The Company and some of its subsidiaries have a noncontributory  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.

On  February  28,  2005,  as  part of a  previously  announced  cost  management
initiative,   the  executive  officers  of  the  Company  approved  a  workforce
restructuring. The restructuring will result in a reduction of approximately 450
positions  and is expected to be completed in September of 2005.  In addition to
the workforce restructuring, the cost management initiative includes a voluntary
enhanced retirement program. See Note 24 for more information.

As of February 28, 2005, PEC employed approximately 5,100 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,
2004,  PEC had a total  summer  generating  capacity  (including  jointly  owned
capacity) of approximately 12,482 MW.

PEC  distributes  and  sells  electricity  in 56 of the 100  counties  in  North
Carolina and 14 counties in northeastern  South Carolina.  The service territory
covers 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.  At December  31,  2004,  PEC was

                                       14
<PAGE>

providing electric services,  retail and wholesale, to approximately 1.4 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,
the SCPSC and the NRC. No single  customer  accounts  for more than 10% of PEC's
revenues.

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               2004           2003            2002
          Residential                  38%            36%             36%
          Commercial                   25%            24%             24%
          Industrial                   19%            18%             19%
          Wholesale                    16%            20%             19%
          Other retail                  2%             2%              2%

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

FUEL AND PURCHASED POWER

Sources of Generation

PEC's consumption of various types of fuel depends on several factors,  the most
important  of which are the  demand  for  electricity  by PEC's  customers,  the
availability of various  generating units, the availability and cost of fuel and
the  requirements of federal and state regulatory  agencies.  PEC's total system
generation  (including  jointly owned capacity) by primary energy source,  along
with  purchased  power for the last three years is  presented  in the  following
table:

                             ENERGY MIX PERCENTAGES

                                           2004        2003        2002
         Coal                               47%         46%         46%
         Nuclear                            43%         44%         42%
         Purchased power                     6%          7%          8%
         Oil/Gas                             3%          2%          3%
         Hydro                               1%          1%          1%

PEC is generally  permitted to pass the cost of 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.  See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND
QUALITATIVE  DISCLOSURES  ABOUT  MARKET RISK and "Risk  Factors."  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)

                                            2004        2003        2002
         Coal                              $ 2.17      $ 2.00      $ 1.93
         Nuclear                             0.42        0.43        0.43
         Oil                                 6.78        6.69        5.48
         Gas                                 8.29        8.32        5.31
         Hydro                               -           -           -
         Weighted-average                    1.57        1.43        1.38

                                       15
<PAGE>

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

PEC anticipates a requirement of approximately 12.4 million to 13.0 million tons
of coal in 2005.  Almost all of the coal will be supplied from  Appalachian coal
sources in the United States and is primarily delivered by rail.

For 2005, PEC has short-term, intermediate and long-term agreements from various
sources for  approximately  102% of its burn requirements of its coal units. All
of these  contracts are at fixed prices  adjusted  annually.  The contracts have
expiration  dates ranging from 2005 to 2009. PEC will continue to sign contracts
of various  lengths,  terms and quality to meet its expected burn  requirements.
All the coal to be  purchased  for PEC 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.

PEC has sufficient uranium, conversion,  enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement  needs. PEC's nuclear fuel contracts
typically  have terms ranging from five to ten years.  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 all four 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

Oil and natural gas 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  and gas 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 4.0 million MWh, 4.5 million MWh and 5.2 million MWh
of its system energy requirements during 2004, 2003 and 2002, respectively,  and
had available  1,498 MW, 1,810 MW and 1,737 MW of firm purchased  capacity under
contract at the time of peak load during 2004, 2003 and 2002, respectively.  PEC
may acquire  additional  purchased power capacity in the future to accommodate a
portion of its system load needs.

COMPETITION

Electric Industry Restructuring

PEC continues to monitor  developments  that may occur toward a more competitive
environment and actively  participates  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.

                                       16
<PAGE>

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.  On
December 22, 2004, the FERC, citing superseding events, voted to close a portion
of the  GridSouth  docket.  The GridSouth  Companies  asked the FERC for further
clarification as to the portions of the GridSouth docket it intended to address.
On March 2, 2005, the FERC affirmed that it only intended to close the mediation
portion of the GridSouth docket.

See Note 8D for additional discussion of current developments of GridSouth RTO.

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.  The general  effect of these  franchises is to provide for the
manner  in  which  PEC  occupies   rights-of-way   in   incorporated   areas  of
municipalities  for the purpose of  constructing,  operating and  maintaining an
energy transmission and distribution  system. 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

General

PEC is subject to the  jurisdiction of the NCUC and SCPSC with respect to, among
other  things,  rates and service  for  electric  energy sold at retail,  retail
service  territory and issuances of securities.  In addition,  PEC 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 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.

The Clean  Smokestacks  Act  enacted  in North  Carolina  in 2002 (NC Clean Air)
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  Note 22 and  Note 8B to the PGN and PEC  Consolidated  Financial
Statements, respectively, for further discussion of PEC's rate freeze.

See Note 8B and Note 6B to the PGN and PEC  Consolidated  Financial  Statements,
respectively,  for further  discussion of PEC's retail rate developments  during
2004.

                                       17
<PAGE>

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.

See PART I, ITEM 1, "General," under Competition for further  discussion of FERC
screens for assessing generation market power.

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 a
certain  portion 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.

NUCLEAR MATTERS

PEC is 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. At the Brunswick  Plant,
Unit 1 increased  its capacity by 52 MW in 2002 and by 66 MW in 2004.  Brunswick
Unit 2 increased its capacity by 89 MW in 2003,  and an  additional  increase is
planned for 2005.  The total  increased  generation  from all these  projects is
estimated to be approximately 300 MW. See PART I, ITEM 1, "Nuclear Matters," for
further discussion of these and other nuclear matters.

ENVIRONMENTAL MATTERS

In the areas of air quality,  water  quality,  control of toxic  substances  and
hazardous and solid wastes and other  environmental  matters,  PEC is subject to
regulation by various federal, state and local authorities. PEC 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  PEC's  existing  fossil
facilities  that it expects to incur from 2005  through 2007 are included in the
"Capital Expenditures"  discussion under PART II, ITEM 7, "Liquidity and Capital
Resources."

The provisions of the Comprehensive  Environmental Response,  CERCLA,  authorize
the EPA to require the cleanup 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  nine
former MGP sites and a number of other sites with  respect to which PEC has been
notified by the EPA or the State of North  Carolina of its potential  liability,
as a PRP.  Although  PEC may incur  costs at the sites  about  which it has been
notified, based upon the current status of these sites, PEC cannot determine the
total costs that may be incurred in connection  with all sites at this time. See
Notes  22  and  17  to  the  PGN  and  PEC  Consolidated  Financial  Statements,
respectively, for a discussion of PEC's environmental matters.

                                       18
<PAGE>

ELECTRIC - PEF

GENERAL

PEF,  incorporated in Florida in 1899, is an operating public utility engaged in
the generation, transmission,  distribution and sale of electricity. At December
31, 2004, PEF had a total summer generating  capacity  (including  jointly owned
capacity) of approximately 8,544 MW.

PEF provided electric service during 2004 to an average of 1.5 million customers
in west central  Florida.  Its service  territory  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 21
municipal and 9 rural electric cooperative systems.  Major wholesale power sales
customers include Seminole  Electric  Cooperative,  Inc.,  Florida Power & Light
Company,  Tampa Electric  Company and the City of Bartow.  PEF is subject to the
rules and  regulations  of the FERC,  the FPSC and the NRC.  No single  customer
accounts for more than 10% of PEF's revenues.

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               2004           2003            2002
        Residential                  53%            55%             55%
        Commercial                   25%            24%             24%
        Industrial                    8%             7%              7%
        Other retail                  6%             6%              6%
        Wholesale                     8%             8%              8%

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.

FUEL AND PURCHASED POWER

Sources of Generation

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 total system
generation  (including  jointly owned capacity) by primary energy source,  along
with  purchased  power for the last three years is  presented  in the  following
table:

                             ENERGY MIX PERCENTAGES

        Fuel Type                   2004         2003          2002
        Coal (a)                     32%          36%           33%
        Oil                          16%          16%           16%
        Nuclear                      16%          14%           15%
        Gas                          16%          13%           15%
        Purchased Power              20%          21%           21%

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

PEF is generally  permitted to pass the cost of 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

                                       19
<PAGE>

complete  certainty.  See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND
QUALITATIVE  DISCLOSURES  ABOUT  MARKET RISK and "Risk  Factors."  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)

                                       2004           2003            2002
        Coal (a)                     $ 2.30         $ 2.42          $ 2.43
        Oil                            4.67           4.38            3.77
        Nuclear                        0.49           0.50            0.46
        Gas                            6.41           5.98            4.06
        Weighted-average               3.21           3.07            2.60

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

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 million tons of coal
in  2005.  Approximately  70%  of the  coal  is  expected  to be  supplied  from
Appalachian coal sources in the United States and 30% supplied from coal sources
in South America.  Approximately  67% 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 2005,  Progress Fuels has medium-term  and long-term  contracts with various
sources for  approximately  115% of the burn  requirements  of PEF's coal units.
Supply  disruption  caused by recent  hurricanes  has made it necessary to build
inventories back to the traditional level of 45 days. These contracts have price
adjustment  provisions  and have  expiration  dates  ranging  from 2005 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

Oil and natural gas 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 and
gas for the reasonably  foreseeable future.  PEF's natural gas transportation is
purchased under term firm  transportation  contracts with interstate  pipelines.
PEF purchases capacity on a seasonal basis from numerous shippers and interstate
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's nuclear fuel contracts
typically  have terms ranging from five to ten years.  For a discussion of PEF's
plans with respect to spent fuel storage, see PART I, ITEM I, "Nuclear Matters."

                                       20
<PAGE>

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, 2004,  PEF had a
variety of purchase power agreements for the purchase of approximately  1,498 MW
of firm power. These agreements include (1) long-term contracts for the purchase
of  about  484  MW of  purchased  power  with  other  investor-owned  utilities,
including a contract with The Southern Company for approximately 414 MW, and (2)
approximately  821 MW of capacity  under contract with certain QFs. The capacity
currently available from QFs represents about 9% of PEF's total installed system
capacity.

COMPETITION

Electric Industry Restructuring

PEF continues to monitor developments toward a more competitive  environment and
actively  participates 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 Florida Department of
Environment and Protection  (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, Florida Power & Light Company and Tampa Electric
Company  (collectively,  the Applicants)  filed with the FERC in October 2000 an
application  for  approval of a  GridFlorida  RTO. The  GridFlorida  proposal is
pending before both the FERC and the FPSC. The FERC  provisionally  approved the
structure and  governance of  GridFlorida.  In December  2003,  the FPSC ordered
further state proceedings and established a collaborative workshop process to be
conducted  during 2004. In June 2004,  the workshop  process was abated  pending
completion of a cost-benefit study currently scheduled to be presented at a FPSC
workshop on May 25, 2005,  with  subsequent  action by the FPSC to be thereafter
determined.  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 Note 8D for a
discussion of current developments of GridFlorida RTO.

Franchises

PEF holds franchises with varying  expiration dates in 108 of the municipalities
in which it distributes electric energy. PEF also serves 13 other municipalities
and in all its unincorporated  areas without franchise  agreements.  The general
purpose 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  39% of  PEF's  total  utility  revenues  for 2004  were  from the
incorporated  areas  of the 108  municipalities  that had  franchise  ordinances
during the year. Since 2000, PEF has renewed 34 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 27 of the  existing  franchises  cover a  30-year  period  from the date
enacted.  The  exceptions  are 23  franchises,  each with a term of 10 years and
expiring  between 2005 and 2013; two franchises each with a term of 15 years and
expiring in 2017;  one 30-year  franchise  that was extended in 1999 for 5 years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 108  franchises,  46 expire between  January 1, 2005, and December 31, 2015,
and 62 expire between January 1, 2016, 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.

                                       21
<PAGE>

Wholesale Competition

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

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.

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 Note 8C.

In January  2005,  in  anticipation  of the  expiration  of the  Agreement,  PEF
notified  the FPSC that it intends to request  an  increase  in its base  rates,
effective  January 1, 2006.  In its notice,  PEF  requested  the FPSC to approve
calendar year 2006 as the projected test period for setting new base rates.  The
request  for  increased  base  rates is based  on the  fact  that PEF has  faced
significant  cost  increases  over the past decade and  expects its  operational
costs to continue to increase.  These costs  include the costs  associated  with
completion of the Hines 3 generation  facility,  extraordinary  hurricane damage
costs including capital costs which are not expected to be directly recoverable,
the need to replenish the depleted storm reserve and the expected infrastructure
investment  necessary  to meet  high  customer  expectations,  coupled  with the
demands placed on PEF as a result of strong customer  growth.  Related risks are
described in more detail in the "Risk Factors" section.

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 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  FPSC's  annual  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.

                                       22
<PAGE>

In  accordance  with a regulatory  order,  PEF accrues $6 million  annually to a
storm damage reserve and is allowed to defer losses in excess of the accumulated
reserve for major  storms.  Under the order,  the storm  reserve is charged with
operation and maintenance expenses related to storm restoration and with capital
expenditures  related to storm  restoration  that are in excess of  expenditures
assuming normal operating conditions.

As of December 31, 2004, $291 million of hurricane  restoration  costs in excess
of the previously recorded storm reserve of $47 million had been classified as a
regulatory  asset  recognizing  the probable  recoverability  of these costs. On
November 2, 2004,  PEF filed a petition with the FPSC to recover $252 million of
storm  costs plus  interest  from  retail  ratepayers  over a  two-year  period.
Hearings on PEF's  petition  for  recovery of $252  million of storm costs filed
with the FPSC are scheduled to begin on March 30, 2005 (See Note 3).

PEF's  January  2005 notice to the FPSC of its intent to file for an increase in
its base rates effective January 1, 2006,  anticipates the need to replenish the
depleted storm reserve balance and adjust the annual $6 million accrual in light
of recent  storm  history to restore  the  reserve to an  adequate  level over a
reasonable time period.

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 that are also
anticipated to incur  investigation  and  remediation  costs.  At this time, PEF
cannot  determine  the total costs that may be incurred in  connection  with the
remediation  of  all  sites.  See  Note  22  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 oil and gas products,  blend and
transload  coal, mine coal and produce a solid  coal-based  synthetic fuel. This
product has been classified as a synthetic fuel within the meaning of Section 29
of the Internal  Revenue  Service Code  (Section  29).  Sales of synthetic  fuel
therefore qualify for tax credits, as more fully described below.

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

o    Natural gas properties in Texas and Louisiana  producing  approximately  22
     Bcf equivalent per year;
o    Five terminals on the Ohio River and its tributaries, part of the trucking,
     rail and barge network for coal delivery;
o    Two active coal-mining complexes,  expected to produce approximately 3 to 5
     million tons per year:
o    Four wholly owned synthetic fuel entities,  a majority owned synthetic fuel
     entity and a minority  interest in one  synthetic  fuel entity,  capable of
     producing up to 16 million tons per year;
o    Majority-ownership  in a barge  partnership  that  transports coal products
     from the mouth of the Mississippi  River to PEF's Crystal River 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
Note 5B).

In December 2004, the Company sold certain gas-producing  properties and related
assets owned by  Winchester  Production,  a wholly owned  subsidiary of Progress
Fuels Corporation (See Note 4A).

                                       23
<PAGE>

SYNTHETIC FUELS TAX CREDITS

The  Company  has  substantial  operations  associated  with the  production  of
coal-based  synthetic fuels. The production and sale of these products qualifies
for federal  income tax credits so long as certain  requirements  are satisfied.
These operations are subject to numerous risks.

Although the Company  believes that it operates its synthetic fuel facilities in
compliance with applicable legal requirements for claiming the credits, its four
Earthco  facilities are under audit by the IRS. IRS field auditors have taken an
adverse  position  with respect to the  Company's  compliance  with one of these
legal  requirements,  and if the Company  fails to prevail  with respect to this
position it could incur  significant  liability and/or lose the ability to claim
the  benefit  of tax  credits  carried  forward  or  generated  in  the  future.
Similarly,  the Financial  Accounting  Standards  Board may issue new accounting
rules that would require that uncertain tax benefits  (such as those  associated
with the Earthco  plants) be probable of being sustained in order to be recorded
on the financial  statements;  if adopted,  this provision could have an adverse
financial impact on the Company.

The Company's  ability to utilize tax credits is dependent on having  sufficient
tax  liability.   Any  conditions  that  negatively  impact  the  Company's  tax
liability, such as weather, could also diminish the Company's ability to utilize
credits,  including  those  previously  generated,  and  the  synthetic  fuel is
generally not economical to produce absent the credits. Finally, the tax credits
associated with synthetic fuels may be phased out if market prices for crude oil
exceed certain prices.

The Company's  synthetic fuel operations and related risks are described in more
detail in Note 23E and in the "Risk Factors" section.

COMPETITION

Fuels'  synthetic  fuel  operations and coal  operations  compete in the eastern
United States steam and 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 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 Note 22 for a discussion of Fuels' environmental matters.

COMPETITIVE COMMERCIAL OPERATIONS (CCO)

The CCO business  segment is responsible  for marketing  energy in the wholesale
market  outside  the  realm  of  retail  regulation.   CCO  currently  owns  six
electricity  generation  facilities  with  approximately  3,100 MW of generation
capacity,  and it has contractual rights to an additional 2,500 MW of generation
capacity from mixed fuel  generation  facilities  through its agreements with 16
Georgia  electric  membership  cooperatives  (EMCs).  CCO has  contracts for its
combined  production  capacity of approximately 77% for 2005,  approximately 81%
for 2006 and approximately 75% for 2007.

The energy CCO markets is sold under both term contracts and in the spot market.
CCO  purchases  fuel,  such as oil and natural gas for use in the  generation of
electricity.  The Company  believes that there are adequate  sources of fuel for
CCO's expected fuel requirements.  CCO also uses financial instruments to manage
the risks  associated with  fluctuating  commodity  prices to hedge the economic
value of its portfolio of assets.

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.  In 2004, PVI
executed wholesale  power-supply  agreements with 15 Georgia electric membership
cooperatives (EMCs) to serve their electricity needs through 2010.

                                       24
<PAGE>

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  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 Track-work Services (ETS).

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 ETS  unit  focuses  on rail and  other  track
components, the infrastructure that 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.

In February  2005,  Progress  Energy  signed a definitive  agreement to sell its
Progress Rail  subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million.  Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.

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 Note
4C).

ENVIRONMENTAL MATTERS

See Note 22 for a discussion of Rail's environmental matters.

CORPORATE AND OTHER BUSINESS SEGMENT

GENERAL

The Corporate and Other Businesses segment includes the operations of PT LLC and
Strategic  Resource Solutions Corp. (SRS) and holding company  operations.  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 PT 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, PT LLC; Odyssey holds a
combined 45% ownership interest in PT LLC through EPIK and Caronet. The accounts
of PT LLC have been included in the Company's  Consolidated Financial Statements
since the transaction date.

                                       25
<PAGE>

PT 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. PT LLC markets wholesale  fiber-optic-based capacity
service in the Eastern United States to long-distance carriers, Internet service
providers and other  telecommunications  companies. PT LLC also markets wireless
structure  attachments  to wireless  communication  companies  and  governmental
entities.  At December 31, 2004,  PT LLC owned and managed more than 8,500 route
miles and more than 420,000 fiber miles of fiber-optic cable.

PT 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 Notes 7 and 10
to the PEC Consolidated Financial Statements.


                                       26
<PAGE>


ELECTRIC UTILITY REGULATED OPERATING STATISTICS - PROGRESS ENERGY

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------------------
                                                                                 Years Ended December 31
                                                               2004          2003         2002          2001         2000(d)
----------------------------------------------------------------------------------------------------------------------------
Energy supply (millions of kilowatt-hours)
  Generated - Steam                                           50,782        51,501       49,734        48,732        31,132
              Nuclear                                         30,445        30,576       30,126        27,301        23,857
              Combustion Turbines/Combined Cycle               9,695         7,819        8,522         6,644         1,337
              Hydro                                              802           955          491           245           441
  Purchased                                                   13,466        13,848       14,305        14,469         5,724
----------------------------------------------------------------------------------------------------------------------------
      Total energy supply (Company share)                    105,190       104,699      103,178        97,391        62,491
  Jointly owned share (a)                                      5,395         5,213        5,258         4,886         4,505
----------------------------------------------------------------------------------------------------------------------------
      Total system energy supply                             110,585       109,912      108,436       102,277        66,996
----------------------------------------------------------------------------------------------------------------------------
Average fuel cost (per million Btu)
  Fossil                                                 $      3.17    $     2.94   $     2.62    $     2.46     $    1.96
  Nuclear fuel                                           $      0.44    $     0.44   $     0.44    $     0.45     $    0.45
  All fuels                                              $      2.21    $     2.05   $     1.84    $     1.77     $    1.30
Energy sales (millions of kilowatt-hours)
Retail
   Residential                                                35,350        34,712       33,993        31,976        15,365
   Commercial                                                 24,753        24,110       23,888        23,033        12,221
   Industrial                                                 17,105        16,749       16,924        17,204        14,762
   Other Retail                                                4,475         4,382        4,287         4,149         1,626
Wholesale                                                     18,323        19,841       19,204        17,715        15,012
Unbilled                                                         449           189          275       (1,045)         1,098
----------------------------------------------------------------------------------------------------------------------------
      Total energy sales                                     100,455        99,983       98,571        93,032        60,084
      Company uses and losses                                  3,936         3,753        3,604         3,478         2,286
----------------------------------------------------------------------------------------------------------------------------
      Total energy requirements                              104,391       103,736      102,175        96,510        62,370
----------------------------------------------------------------------------------------------------------------------------
Electric revenues (in millions)
  Retail                                                 $     6,066    $    5,620   $    5,515    $    5,462     $   2,799
  Wholesale                                                      843           915          881           923           665
  Miscellaneous revenue                                          244           206          205           172            81
----------------------------------------------------------------------------------------------------------------------------
      Total electric revenues                            $     7,153    $    6,741   $    6,601    $    6,557     $   3,545
----------------------------------------------------------------------------------------------------------------------------
Peak demand of firm load (thousands of kW)
  System (b)                                                  19,711       19,876         20,365         19,166      18,874
  Company                                                     19,126       19,235         19,746         18,564      18,272
Total regulated capability at year-end (thousands of kW)
  Fossil plants                                               16,522       16,522         16,006         15,826 (e)  14,747
  Nuclear plants                                               4,286 (h)    4,220 (g)      4,127 (f)      4,008       4,008
  Hydro plants                                                   218          218            218            218         218
  Purchased                                                    2,852        2,826          2,929          2,890       2,278
----------------------------------------------------------------------------------------------------------------------------
      Total system capability                                 23,878       23,786         23,280         22,942      21,251
   Less jointly owned portion (c)                                714          698            682            668         662
----------------------------------------------------------------------------------------------------------------------------
      Total Company capability - regulated                    23,164       23,088         22,598         22,274      20,589
----------------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Amounts  represent  co-owner's  share of the energy  supplied  from the six
     generating facilities that are jointly owned.
(b)  Amounts  represent the combined summer  noncoincident  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 MDCs  were
     restated January 2004.
(h)  Amount includes power uprate for Brunswick 1; the MDC was restated  January
     2005.

                                       27
<PAGE>


REGULATED OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------------------
                                                                                 Years Ended December 31
                                                            2004            2003           2002          2001        2000
----------------------------------------------------------------------------------------------------------------------------
Energy supply (millions of kilowatt-hours)
  Generated - Steam                                          28,632         28,522        28,547         27,913      29,520
              Nuclear                                        23,742         24,537        23,425         21,321      23,275
              Combustion Turbines/Combined Cycle              1,926          1,344         1,934            802         733
              Hydro                                             802            955           491            245         441
  Purchased                                                   4,023          4,467         5,213          5,296       4,878
----------------------------------------------------------------------------------------------------------------------------
      Total energy supply (Company share)                    59,125         59,825        59,610         55,577      58,847
  Power Agency share (a)                                      4,794          4,670         4,659          4,348       4,505
----------------------------------------------------------------------------------------------------------------------------
      Total system energy supply                             63,919         64,495        64,269         59,925      63,352
----------------------------------------------------------------------------------------------------------------------------
Average fuel cost (per million Btu)
  Fossil                                                 $     2.52     $     2.29      $   2,16     $     1.91   $    1.83
  Nuclear fuel                                           $     0.42     $     0.43      $   0.43     $     0.44   $    0.45
  All fuels                                              $     1.57     $     1.43      $   1.38     $     1.26   $    1.21
Energy sales (millions of kilowatt-hours)
Retail
   Residential                                               16,003         15,283        15,239         14,372      14,091
   Commercial                                                13,019         12,557        12,468         11,972      11,432
   Industrial                                                13,036         12,749        13,089         13,332      14,446
   Other Retail                                               1,432          1,408         1,437          1,423       1,423
Wholesale                                                    13,221         15,518        15,024         12,996      14,582
Unbilled                                                         91           (44)           270          (534)         679
----------------------------------------------------------------------------------------------------------------------------
      Total energy sales                                     56,802         57,471        57,527         53,561      56,653
      Company uses and losses                                 2,323          2,354         2,083          2,016       2,194
----------------------------------------------------------------------------------------------------------------------------
      Total energy requirements                              59,125         59,825        59,610         55,577      58,847
----------------------------------------------------------------------------------------------------------------------------
Electric revenues (in millions)
  Retail                                                 $    2,953     $    2,824      $  2,796     $    2,666   $   2,609
  Wholesale                                                     575            687           651            634         577
  Miscellaneous revenue                                         100             78            92             44         122
----------------------------------------------------------------------------------------------------------------------------
      Total electric revenues                            $    3,628     $    3,589      $  3,539     $    3,344   $   3,308
----------------------------------------------------------------------------------------------------------------------------
Peak demand of firm load (thousands of kW) (g)
  System                                                     11,192         11,771        11,977         11,376      11,157
  Company                                                    10,607         11,130        11,358         10,774      10,555
Total regulated capability at year-end (thousands of kW)
  Fossil plants                                               8,816          8,816         8,816          8,648 (c)   7,569
  Nuclear plants                                              3,448 (f)      3,382 (e)     3,293 (d)      3,174       3,174
  Hydro plants                                                  218            218           218            218         218
  Purchased                                                   1,545          1,513         1,617          1,586         978
----------------------------------------------------------------------------------------------------------------------------
      Total system capability                                14,027         13,929        13,944         13,626      11,939
  Less Power Agency-owned portion (b)                           645            629           613            599         593
----------------------------------------------------------------------------------------------------------------------------
      Total Company capability                               13,382         13,300        13,331         13,027      11,346
----------------------------------------------------------------------------------------------------------------------------
</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.
(f)  Amount includes power uprate for Brunswick 1; the MDC was restated  January
     2005.
(g)  Amount is the summer peak demand.

                                       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, 2004,  PEC's 18  generating  plants  represent a flexible mix of
fossil,   nuclear,   hydroelectric,   combustion  turbines  and  combined  cycle
resources,  with a total summer generating capacity of 12,482 MW. Of this total,
Power  Agency owns  approximately  694 MW. On  December  31,  2004,  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, N.C.          2      1964-1971       Coal         100              392
Cape Fear            Moncure, N.C.          2      1956-1958       Coal         100              316
Lee                  Goldsboro, N.C.        3      1952-1962       Coal         100              407
Mayo                 Roxboro, N.C.          1         1983         Coal        83.83             745   (b)
Robinson             Hartsville, S.C.       1         1960         Coal         100              174
Roxboro              Roxboro, N.C.          4      1966-1980       Coal        96.32    (c)     2,462  (b)
Sutton               Wilmington, N.C.       3      1954-1972       Coal         100              613
Weatherspoon         Lumberton, N.C.        3      1949-1952       Coal         100              176
                                         --------                                           ---------------
                     Total                 19                                                   5,285
COMBINED CYCLE
Cape Fear            Moncure, N.C.          2         1969          Oil         100                84
Richmond             Hamlet, N.C.           1         2002        Gas/Oil       100              472
                                         --------                                           ---------------
                     Total                  3                                                     556
COMBUSTION TURBINES
Asheville            Skyland, N.C.          2      1999-2000      Gas/Oil       100              330
Blewett              Lilesville, N.C.       4         1971          Oil         100                52
Darlington           Hartsville, S.C.      13      1974-1997      Gas/Oil       100              812
Lee                  Goldsboro, N.C.        4      1968-1971        Oil         100                91
Morehead City        Morehead City, N.C.    1         1968          Oil         100                15
Richmond             Hamlet, N.C.           5      2001-2002      Gas/Oil       100              775
Robinson             Hartsville, S.C.       1         1968        Gas/Oil       100                15
Roxboro              Roxboro, N.C.          1         1968          Oil         100                15
Sutton               Wilmington, N.C.       3      1968-1969      Gas/Oil       100                64
Wayne County         Goldsboro, N.C.        4         2000        Gas/Oil       100              668
Weatherspoon         Lumberton, N.C.        4      1970-1971      Gas/Oil       100              138
                                         --------                                           ---------------
                     Total                 42                                                   2,975
NUCLEAR
Brunswick            Southport, N.C.        2      1975-1977      Uranium      81.67            1,838  (b)(d)
Harris               New Hill, N.C.         1         1987        Uranium      83.83             900   (b)
Robinson             Hartsville, S.C.       1         1971        Uranium       100              710
                                         --------                                           ---------------
                     Total                  4                                                   3,448
HYDRO
Blewett              Lilesville, N.C.       6         1912         Water        100               22
Marshall             Marshall, N.C.         2         1910         Water        100               5
Tillery              Mount Gilead, N.C.     4      1928-1960       Water        100               86
Walters              Waterville, N.C.       3         1930         Water        100              105
                                         --------                                           ---------------
                     Total                 15                                                    218

TOTAL                                      83                                                   12,482
-----------------------------------------------------------------------------------------------------------
</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 2004, a power uprate  increased the net summer  capability of Unit 1
     to 938 MW. The MDC was restated in January 2005.

                                       29
<PAGE>

At December 31, 2004,  including both the total generating capacity of 12,482 MW
and the total firm contracts for purchased power of approximately  1,545 MW, PEC
had total capacity resources of approximately 14,027 MW.

The Power Agency has 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, 2004, PEC had approximately  6,000 circuit miles of transmission
lines  including  300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230 kV
lines. PEC also had approximately 45,000 circuit miles of overhead  distribution
conductor  and  18,000   circuit  miles  of  underground   distribution   cable.
Distribution and transmission  substations in service had a transformer capacity
of  approximately  12,000,000   kilovolt-ampere  (kVA)  in  2,405  transformers.
Distribution line transformers numbered  approximately 509,700 with an aggregate
capacity of approximately 21,000,000 kVA.

ELECTRIC - PEF

At December 31, 2004,  PEF's 14  generating  plants  represent a flexible mix of
fossil,  nuclear,  combustion  turbine and combined cycle resources with a total
summer generating  capacity  (including  jointly owned capacity) of 8,544 MW. At
December 31, 2004, 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, Fla.             2      1974-1978    Gas/Oil      100           993
Bartow                  St. Petersburg, Fla.      3      1958-1963    Gas/Oil      100           444
Crystal River           Crystal River, Fla.       4      1966-1984     Coal        100          2,302
Suwannee River          Live Oak, Fla.            3      1953-1956    Gas/Oil      100           143
                                               --------                                    -----------------
                        Total                    12                                             3,882
COMBINED CYCLE
Hines                   Bartow, Fla.              2      1999-2003    Gas/Oil      100           998
Tiger Bay               Fort Meade, Fla.          1        1997         Gas        100           207
                                               --------                                    -----------------
                        Total                     3                                             1,205
COMBUSTION TURBINES
Avon Park               Avon Park, Fla.           2        1968       Gas/Oil      100           52
Bartow                  St. Petersburg, Fla.      4      1958-1972    Gas/Oil      100           187
Bayboro                 St. Petersburg, Fla.      4        1973         Oil        100           184
DeBary                  DeBary, Fla.             10      1975-1992    Gas/Oil      100           667
Higgins                 Oldsmar, Fla.             4      1969-1970    Gas/Oil      100           122
Intercession City       Intercession City,       14      1974-2000    Gas/Oil      100 (c)      1,041  (b)
                        Fla.
Rio Pinar               Rio Pinar, Fla.           1        1970         Oil        100           13
Suwannee River          Live Oak, Fla.            3        1980       Gas/Oil      100           164
Turner                  Enterprise, Fla.          4      1970-1974      Oil        100           154
University of           Gainesville, Fla.         1        1994         Gas        100           35
   Florida Cogeneration
                                               --------                                    -----------------
                        Total                    47                                             2,619
NUCLEAR
Crystal River           Crystal River, Fla.       1        1977       Uranium     91.78          838   (b)
                                               --------                                    -----------------
                        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.

At December 31, 2004, PEF had total capacity  resources of approximately  10,042
MW, including both the total generating  capacity of 8,544 MW and the total firm
contracts for purchased power of 1,498 MW.

                                       30
<PAGE>

Several  entities  have  acquired  undivided  ownership  interests in CR3 in the
aggregate amount of 8.22%. The joint ownership participants are: City of Alachua
- 0.08%,  City of  Bushnell  - 0.04%,  City of  Gainesville  - 1.41%,  Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New  Smyrna  Beach - 0.56%,  City of Ocala -  1.33%,  Orlando  Utilities
Commission  - 1.60% and Seminole  Electric  Cooperative,  Inc. - 1.70%.  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, 2004, PEF had approximately  5,000 circuit miles of transmission
lines including 200 miles of 500 kV lines and about 1,500 miles of 230 kV lines.
PEF also had  approximately,  22,000  circuit  miles  of  overhead  distribution
conductor  and  13,000   circuit  miles  of  underground   distribution   cable.
Distribution and transmission  substations in service had a transformer capacity
of  approximately   45,000,000  kVA  in  616  transformers.   Distribution  line
transformers  numbered  approximately  365,000  with an  aggregate  capacity  of
approximately 18,000,000 kVA.

FUELS

Progress Fuels controls, either directly or through subsidiaries,  coal reserves
located in eastern  Kentucky  and  southwestern  Virginia  of  approximately  46
million tons and controls,  through  mineral leases,  additional  estimated coal
reserves of  approximately  48 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. Progress Fuels' total production of coal
during 2004 was approximately 3.4 million tons.

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

The Fuels business  segment,  through its business units, has an interest in six
synthetic fuel entities.  Four of the entities are wholly owned, one is majority
owned and one is minority owned. These facilities are in six different locations
in West Virginia, Virginia and Kentucky.

Fuels' oil and gas production in 2004 was 30.4 Bcf equivalent. Fuels has oil and
gas leases in East Texas and Louisiana with total proven oil and gas reserves of
approximately 247 Bcf equivalent.

CCO

At December 31, 2004, 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, N.C.       1Q 2000             2Q 2001         Simple-Cycle, 3        459
Walton (c)               Monroe, Ga.         2Q 2000             2Q 2001         Simple-Cycle, 3        460
DeSoto Units            Arcadia, Fla.        2Q 2001             2Q 2002         Simple-Cycle, 2        320
Effingham                Rincon, Ga.         1Q 2001             3Q 2003        Combined-Cycle, 1       480
Rowan Phase II (b)     Salisbury, N.C.       4Q 2001             2Q 2003        Combined-Cycle, 1       466
Washington (c)          Sandersville,        2Q 2002             2Q 2003         Simple-Cycle, 4        600
                             Ga.
--------------------------------------------------------------------------------------------------------------
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  2,000  railcars  and  50
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.

In February  2005,  Progress  Energy  signed a definitive  agreement to sell its
Progress Rail  subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million.  Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.

PT LLC

PT  LLC  provides   wholesale   telecommunications   services   throughout   the
Southeastern United States. PT LLC incorporates more than 420,000 fiber miles of
fiber-optic cable in its network, including more than 189 Points-of-Presence, or
physical locations where a presence for network access exists.


                                       32
<PAGE>

ITEM 3.  LEGAL PROCEEDINGS

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

1.   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 Coast 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) an 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, in March 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.  Following  briefing and argument on a number of
dispositive motions on successive versions of Global's complaint,  on August 16,
2004, the Progress Affiliates answered the Fourth Amended Complaint by generally
denying  all  of  Global's   substantive   allegations  and  asserting  numerous
affirmative  defenses.  The parties are  currently  engaged in  discovery 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  appealed the Superior  court's  order staying the case. By
order dated September 7, 2004, the North Carolina Court of Appeals dismissed the
Progress Affiliates' appeal.

The Company  cannot predict the outcome of these  matters,  but will  vigorously
defend against the allegations.

2.   In  re  Progress  Energy,  Inc.  Securities  Litigation,  Master  File  No.
     04-CV-636 (JES)

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
by Gerber  Asset  Management  LLC in the United  States  District  Court for the
Southern District of New York and names Progress Energy,  Inc.'s former 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.

On March 31, 2004, a second class action  complaint was filed by Stanley  Fried,
Raymond X. Talamantes and Jacquelin Talamantes against William Cavanaugh III and
Progress  Energy,  Inc. in the United  States  District  Court for the  Southern
District of New York alleging  violations of federal securities laws arising out
of the  Company's  issuance of CVOs  nearly  identical  to those  alleged in the
February 3, 2004,  Gerber Asset  Management  complaint.  On April 29, 2004,  the
Honorable  John E.  Sprizzo  ordered  among other  things that (1) the two class
action cases be  consolidated,  (2) Peak6 Capital  Management LLC shall serve as
the lead plaintiff in the consolidated  action, and (3) the lead plaintiff shall
file a consolidated amended complaint on or before June 15, 2004.

                                       33
<PAGE>

The lead plaintiff filed a consolidated  amended  complaint on June 15, 2004. In
addition to the  allegations  asserted in the Gerber Asset  Management and Fried
complaints,  the consolidated  amended complaint alleges that the Company failed
to disclose that excess fuel credits could not be carried over from one tax year
into later years.  On July 30, 2004,  the Company  filed a motion to dismiss the
complaint;  plaintiff  submitted its opposition brief on September 14, 2004. The
Court heard oral  argument on the  Company's  motion to dismiss on November  15,
2004; it has not, to date, rendered a decision on this motion.

The  Company  cannot  predict the outcome of this  matter,  but will  vigorously
defend against the allegations.

For a discussion  of certain other legal  matters,  see Note 23E to the Progress
Energy Consolidated Financial Statements.

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

         NONE

                                       34
<PAGE>

                      EXECUTIVE OFFICERS OF THE REGISTRANTS

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Name                                Age                          Recent Business Experience

*Robert B. McGehee                  61    Chairman  and Chief  Executive  Officer,  Progress  Energy,  May 2004 and
                                          March 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                    60    Group President,  Energy Supply,  PEC and PEF,  November 2000 to present.
                                          (separating  from the  Company,  effective  April 1, 2005.) Mr.  Orser is
                                          responsible  for the  operation  of 38  utility  and  nonregulated  power
                                          plants of Progress  Energy.  He also oversees plant  construction and the
                                          organizations  that support those plants,  including 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 FPC 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                  51    President and Chief Operating Officer,  Progress Energy,  January 2005 to
                                          present;  Group President,  PEC, January 2005 to present;  Executive Vice
                                          President,  PEC and PEF,  November 2000 to present.  Mr. Johnson has been
                                          with Progress Energy  (formerly CP&L) since 1992 and most recently served
                                          as Group  President,  Energy Delivery,  Progress Energy,  January 2004 to
                                          December  2004.  Prior  to  that,  he was  President,  CEO and  Corporate
                                          Secretary,   Progress  Energy  Service  Company,  LLC,  October  2002  to
                                          December  2003.  He also served as 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                  55    President and Chief Executive  Officer,  Progress Energy Service Company,
                                          LLC,  January 2004 to present;  Executive  Vice  President,  PEC and PEF,
                                          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 president of Scott,
                                          Madden  &  Associates,   Inc.,  a  general  management   consulting  firm
                                          headquartered  in Raleigh,  N.C. that he founded in 1983. 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                  42    Executive Vice President and Chief Financial  Officer,  Progress  Energy,
                                          Inc.,  Progress Energy Service  Company,  LLC, 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, October 2003 to December 2003.

                                          Mr.  Chatas served in various  positions  with  American  Electric  Power
                                          (AEP), a multi-state energy holding company based in Columbus,  Ohio from
                                          1997 until he joined  Progress  Energy.  Mr. Chatas' last position at AEP
                                          was Senior Vice  President - Finance and  Treasurer  for AEP.  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.             50    Chief  Accounting  Officer and Controller,  Progress  Energy,  Inc., June
                                          2000 to  present;  Controller,  FPC and PEF,  November  2000 to  present;
                                          Chief Accounting Officer,  FPC, 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,
                                          Fla.

Donald K. Davis                     59    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

                                       36
<PAGE>

                                          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                      61    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.         62    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.

C. S. Hinnant                       60    Senior  Vice  President  and Chief  Nuclear  Officer,  PEC,  June 1998 to
                                          present.  Mr. Hinnant is also Senior Vice President,  PEF,  November 2000
                                          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.

*Jeffrey J. Lyash                   43    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,  N.C. His
                                          last position at Brunswick was as Director of site operations.

John R. McArthur                    49    Senior Vice President,  General Counsel and Secretary of Progress Energy,
                                          January  2004 to  present.  Mr.  McArthur  oversees  the Audit  Services,
                                          Corporate  Communications,  Legal,  Regulatory and Corporate  Relations -
                                          Florida, and State Public Affairs departments,  and the Environmental and
                                          Health and Safety  sections.  Mr.  McArthur is also Senior Vice President
                                          and Corporate  Secretary,  FPC 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,

                                       37
<PAGE>

                                          handling major policy initiatives as well as media and legal affairs.  He
                                          also directed  Governor  Easley's  transition  team after the election of
                                          2000.

                                          From November of 1997 until November of 2000, Mr. McArthur  handled state
                                          government  affairs in 10  southeastern  states for General  Electric Co.
                                          Prior to joining  General  Electric  Co.,  Mr.  McArthur  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                 56    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.

Lloyd M. Yates                      44    Senior  Vice  President,  PEC,  January  2005 to  present.  Mr.  Yates is
                                          responsible  for managing the four  regional  vice  presidents in the PEC
                                          organization.  He  served  PEC as  Vice  President  -  Transmission  from
                                          November  2003 to December  2004.  Mr. Yates  served as Vice  President -
                                          Fossil Generation for PEC from 1998 to 2003.

                                          Before  joining  the  Company in 1998,  Mr.  Yates was with PECO  Energy,
                                          where he had served in a number of engineering and management  roles over
                                          16 years. His last position with PECO was as general manager  -Operations
                                          in the Company's power operations group.
</TABLE>


*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, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES

Progress Energy

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

--------------------------------------------------------------------------------
2004                              High           Low          Dividends Declared
--------------------------------------------------------------------------------
First Quarter                  $ 47.95       $ 43.02             $0.575
Second Quarter                   47.50         40.09              0.575
Third Quarter                    44.32         40.76              0.575
Fourth Quarter                   46.10         40.47              0.590

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

The December 31 closing price of the Company's  Common Stock was $45.24 for 2004
and $45.26 for 2003.  As of March 4, 2005,  the  Company  had 67,160  holders of
record of Common Stock.

Neither  Progress  Energy's  Articles  of  Incorporation  nor  any of  its  debt
obligations  contain  any  restrictions  on the payment of  dividends.  Progress
Energy's  subsidiaries have provisions  restricting dividends in certain limited
circumstances (See Note 13B).

Issuer purchases of equity securities for fourth quarter of 2004 are as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------
                                     (a)             (b)                (c)                       (d)
                                                                                          Maximum Number (or
                                                               Total Number of Shares     Approximate Dollar
                               Total Number of     Average    (or Units) Purchased as    Value) of Shares (or
                                    Shares       Price Paid       Part of Publicly      Units) that May Yet Be
                                  (or Units)      Per Share      Announced Plans or       Purchased Under the
           Period                Purchased(1)     (or Unit)         Programs(1)          Plans or Programs(1)
----------------------------------------------------------------------------------------------------------------

October 1 - October 31(2)          191,436        $ 41.90              N/A                       N/A
----------------------------------------------------------------------------------------------------------------

November 1 - November 30               N/A          N/A                N/A                       N/A
----------------------------------------------------------------------------------------------------------------

December 1 - December 31               N/A          N/A                N/A                       N/A
----------------------------------------------------------------------------------------------------------------

Total:                             191,436        $ 41.90              N/A                       N/A
----------------------------------------------------------------------------------------------------------------
</TABLE>

(1)  As of  December  31,  2004,  Progress  Energy  does not  have any  publicly
     announced plans or programs to purchase shares of its common stock.
(2)  All  shares  were  purchased  in  open-market   transactions  by  the  plan
     administrator  to satisfy share  delivery  requirements  under the Progress
     Energy 401(k) Savings and Stock Ownership Plan (See Note 11A).

PEC

Since 2000, Progress Energy has owned all of PEC's common stock, and as a result
there is no established  public trading market for the stock. PEC has not issued
or repurchased any equity securities since becoming a wholly owned subsidiary of
Progress Energy.  For the past three years, PEC has paid quarterly  dividends to
Progress Energy totaling the amounts shown in the Statements of Common Equity in
the  PEC  Consolidated  Financial  Statements.  PEC has  provisions  restricting
dividends  in  certain  limited  circumstances  (See  Note 8 and  13 to the  PEC
Consolidated  Financial  Statements).  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>
(in millions, except per share data)
----------------------------------------------------------------------------------------------------------------------
Years Ended December 31                        2004           2003             2002           2001           2000(a)
----------------------------------------------------------------------------------------------------------------------
Operating results
  Operating revenues                        $   9,772      $   8,741        $   8,091       $   8,129      $   3,769
  Income from continuing
     operations before cumulative           $     753      $     811        $     552       $     541      $     478
     effect
  Net Income                                $     759      $     782        $     528       $     542      $     478

Per share data
  Basic earnings
  Income from continuing
     operations                             $    3.11      $    3.42        $    2.54       $    2.64      $    3.04
  Net income                                $    3.13      $    3.30        $    2.43       $    2.65      $    3.04

  Diluted earnings
  Income from continuing
     operations                             $    3.10      $    3.40        $    2.53       $    2.63      $    3.03
  Net income                                $    3.12      $    3.28        $    2.42       $    2.64      $    3.03

Assets (c)                                  $  25,993      $  26,093        $  24,272       $  23,701      $  22,875

Capitalization
  Common stock equity                       $   7,633      $   7,444        $   6,677       $   6,004      $   5,424
  Preferred stock of subsidiaries - not
     subject to mandatory redemption               93             93               93              93             93
  Minority interest                                36             30               18              12              -
  Long-term debt, net (b)                       9,521          9,934            9,747           8,619          4,904
  Current portion of long-term debt               349            868              275             688            184
  Short-term obligations                          684              4              695             942          4,959
---------------------------------------------------------------------------------------------------------------------
     Total capitalization and total debt    $  18,316      $  18,373        $  17,505       $  16,358      $  15,564
---------------------------------------------------------------------------------------------------------------------
  Dividends declared per common
     share                                  $    2.32      $    2.26        $    2.20       $    2.14      $    2.08
---------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  Operating results and balance sheet data include  information for FPC since
     November 30, 2000, the date of acquisition.
(b)  Includes long-term debt to affiliated trust of $270 million at December 31,
     2004, and 2003 (See Note 19).
(c)  All periods have been restated for the  reclassification of certain cost of
     removal amounts.

                                       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>
------------------------------------------------------------------------------------------------------------------
(in millions)
Years Ended December 31                       2004           2003             2002          2001          2000(a)
------------------------------------------------------------------------------------------------------------------
Operating results
  Operating revenues                      $  3,629      $   3,600        $   3,554       $  3,360       $   3,528
  Net income                              $    461      $     482        $     431       $    364       $     461
  Earnings for common stock               $    458      $     479        $     428       $    361       $     458

Assets (c)                                $ 10,787      $  10,938        $  10,442       $ 10,640       $  10,552

Capitalization
  Common stock equity                     $  3,072      $   3,237        $   3,089       $  3,095       $   2,852
  Preferred stock - not subject to
     mandatory redemption                       59             59               59             59              59
  Long-term debt, net                        2,750          3,086            3,048          2,698           3,134
  Current portion of long-term debt            300            300                -            600               -
  Short-term obligations (b)                   337             29              438            309             486
------------------------------------------------------------------------------------------------------------------
     Total capitalization and total debt  $  6,518      $   6,711        $   6,634       $  6,761       $   6,531
------------------------------------------------------------------------------------------------------------------
</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)  Includes notes payable to affiliated  companies,  related to the money pool
     program, of $116 million, $25 million and $48 million at December 31, 2004,
     2003 and 2001, respectively.
(c)  All periods have been restated for the  reclassification of certain cost of
     removal amounts.

                                       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

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,  which are located in Kentucky,
          West Virginia and Virginia; and
     o    Rail  Services  (Rail) - engaged in various  rail and  railcar-related
          services in 23 states, Mexico and Canada.

The Progress  Ventures  business  unit  consists of the Fuels and CCO  operating
segments.  The Corporate and Other category includes other businesses engaged in
other nonregulated business areas,  including  telecommunications,  primarily in
the eastern United States,  and energy  services  operations and holding company
results,  which do not meet the  requirements  for  separate  segment  reporting
disclosure.

In 2004,  the Company  realigned  its business  segments to no longer report the
other nonregulated  businesses as a reportable business segment. For comparative
purposes,  2003 and 2002 segment information has been restated to align with the
2004 reporting structure.

Strategy

Progress Energy is an integrated  energy company,  with its primary focus on the
end-use  and  wholesale  electricity  markets.  The  Company  operates in retail
utility markets in the southeastern United States and competitive markets in the
eastern United States.  The target is to develop a business mix of approximately
80% regulated and 20% nonregulated business. The Company is focused on achieving
the  following key goals:  restoring  balance  sheet  strength and  flexibility,
disciplined  capital and operations and maintenance  (O&M) management to support
earnings  and current  dividend  policy and  achieving  constructive  regulatory
frameworks in all three  regulated  jurisdictions.  A summary of the significant
financial   objectives  or  issues  impacting  Progress  Energy,  its  regulated
utilities and  nonregulated  operations is addressed more fully in the following
discussion.

PROGRESS ENERGY, INC.

Progress Energy has several key financial  objectives,  the first of which is to
achieve sustainable  earnings growth in its three core energy businesses,  which
include PEC Electric,  PEF and Progress Ventures (excluding synthetic fuels). In
addition,  the Company seeks to continue its track record of dividend growth, as
the Company has increased its dividend for 17 consecutive  years,  and 29 of the
last  30.  The  Company  also  seeks  to  restore  balance  sheet  strength  and
flexibility by reducing its debt to total  capitalization ratio through selected
asset  sales,  free cash flow  (defined  as cash from  operations  less  capital
expenditures and common  dividends) and increased equity from retained  earnings
and ongoing equity issuances.

                                       42
<PAGE>

In the  short-term,  the  Company's  ability to achieve its  objectives  will be
impacted by, among other  things,  its ability to recover  storm costs  incurred
during  2004,   cash  flow  available  to  reduce  debt  after  funding  capital
expenditures  and common  dividends,  obtaining a reasonable  rate  agreement in
Florida at the  expiration  of the current  agreement  in December  2005 and the
outcome of the ongoing  Internal  Revenue  Service  (IRS) audit of the Company's
synthetic fuel facilities. The Company's long-term challenges include escalating
nonfuel operating costs, the need for sufficient  earnings growth to sustain the
track record of dividend growth, and the scheduled  expiration of the Section 29
tax credit program for its synthetic fuels business at the end of 2007.

The Company's  ability to meet its financial  objectives is largely dependent on
the  earnings  and cash  flows of its two  regulated  utilities.  The  regulated
utilities   contributed  $797  million  of  net  income  and  produced  100%  of
consolidated  cash flow from operations in 2004. In addition,  Fuels contributed
$180 million of net income, of which $91 million represented  synthetic fuel net
income.  Partially  offsetting  the  net  income  contribution  provided  by the
regulated  utilities and Fuels was a loss of $236 million  recorded at Corporate
and Other, primarily related to interest expense on holding company debt.

While the Company's  synthetic fuel  operations  currently  provide  significant
earnings that are scheduled to expire at the end of 2007,  the  associated  cash
flow  benefits  from  synthetic  fuels are  expected  to come in the future when
deferred tax credits are ultimately  utilized.  Credits that have been generated
but not yet utilized are carried forward indefinitely as alternative minimum tax
credits and will provide positive cash flow when utilized. At December 31, 2004,
deferred credits were $745 million.  See Note 23E and the "Risk Factors" section
for additional  information on the Company's  synthetic fuel  operations and its
ability to utilize its current and future tax credits.

Progress Energy reduced its debt to total  capitalization  ratio to 57.6% at the
end of 2004 as  compared  to  58.8%  at the end of 2003.  The  Company  seeks to
continue to improve  this ratio as it plans to reduce  total debt with  proceeds
from asset sales,  free cash flow (defined as cash from  operations less capital
expenditures and common  dividends) and growth in equity from retained  earnings
and ongoing equity issuances.  The Company expects total capital expenditures to
be approximately $1.3 billion in both 2005 and 2006.

Progress  Energy's  ratings  outlook was changed to "negative"  from "stable" in
2004 by both Moody's and Standard & Poor's (S&P).  Both ratings  agencies  cited
the uncertainty  around the timing of storm cost recovery,  potential  delays in
the Company's  de-leveraging  plan,  uncertainty about the upcoming rate case in
Florida and  uncertainty  about the IRS audit of the  Company's  synthetic  fuel
partnerships in their ratings actions.  The change in outlook has not materially
affected  Progress  Energy's  access to liquidity or the cost of its  short-term
borrowings.  If Standard & Poor's  lowers  Progress  Energy's  senior  unsecured
rating  one  ratings  category  to BB+ from its  current  rating,  it would be a
noninvestment  grade rating.  The effect of a  noninvestment  grade rating would
primarily  be  to  increase  borrowing  costs.  The  Company's  liquidity  would
essentially  remain  unchanged as the Company believes it could borrow under its
revolving  credit  facilities  instead  of  issuing  commercial  paper  for  its
short-term  borrowing  needs.   However,   there  would  be  additional  funding
requirements of approximately  $450 million due to ratings triggers  embedded in
various contracts.  See "Guarantees"  Section under FUTURE LIQUIDITY AND CAPITAL
RESOURCES below and "Risk Factors" for more information  regarding the potential
impact on the Company's financial condition and results of operations  resulting
from a ratings downgrade.

REGULATED UTILITIES

The regulated utilities earnings and operating cash flows are heavily influenced
by weather,  including related storm damage, 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
forecasted to have income and population growth higher than the U.S. average. In
recent years,  lower  industrial sales mainly related to weakness in the textile
sector at PEC Electric have negatively  impacted  earnings  growth.  The Company
does not expect any  significant  improvement  in  industrial  sales in the near
term.  These combined  factors under normal  weather  conditions are expected to
contribute  approximately 2% annual retail  kilowatt-hour  (KWh) sales growth at
PEC Electric and approximately 3% annual retail kilowatt-hour (KWh) sales growth
at PEF through at least 2007. The utilities must continue to invest  significant
capital in new generation,  transmission and distribution  facilities to support
this load growth. Subject to regulatory approval, these investments are expected
to  increase  the  utilities'  rate base,  upon which  additional  return can be
realized that creates the basis for long-term financial growth in the utilities.
The  Company  will meet this load  growth  through  the two  previously  planned
approximately 500 MW combined-cycle  units at PEF's Hines Energy Complex in 2005
and 2007. The contribution from the utilities'  regulated  wholesale business is
expected to increase  slightly in 2005 and be relatively flat over the following
few years.

                                       43
<PAGE>

While the two  utilities  expect  retail  sales  growth in the future,  they are
facing rising costs. The Company began a cost-management initiative in late 2004
to permanently  reduce by $75-$100 million the projected growth in the Company's
annual  nonfuel O&M costs by the end of 2007. See "Cost  Management  Initiative"
under RESULTS OF OPERATIONS for more  information.  The utilities expect capital
expenditures to be approximately $1.1 billion in both 2005 and 2006. The Company
will  continue  an   approximate   $900  million   program  of  installing   new
emission-control  equipment at PEC's  coal-fired power plants in North Carolina.
Operating  cash flows are expected to be sufficient to fund capital  spending in
2005 and in 2006.

The costs  associated  with the  unprecedented  series of major  hurricanes that
impacted the Company's service  territories  significantly  impacted the utility
operations in 2004.  Restoration of the Company's systems from hurricane-related
damage  cost  almost  $400  million.  Although  PEF has  filed for  recovery  of
approximately  $252 million of these storm costs,  the timing of recovery is not
certain at this time.  See OTHER  MATTERS  below for more  information  on storm
costs incurred during 2004.

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.  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 an agreement not to seek a base retail
electric rate increase in South Carolina  through 2005. PEF is operating under a
retail  rate  agreement  in  Florida  through  2005.  PEF has  initiated  a rate
proceeding  in 2005  regarding  its future  base  rates.  See Note 8 for further
discussion of the utilities' retail rates.

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 2004,  CCO entered into  additional
wholesale  power   contracts  with   cooperatives  in  Georgia  and  will  serve
approximately  one-third of the Georgia cooperative market starting in 2005. CCO
completed  the  build  out of its  nonregulated  generation  assets  in 2003 and
currently  has total  capacity of 3,100 MW. The Company has no current  plans to
expand  its  portfolio  of  nonregulated   generating   plants.  CCO  short-term
challenges  include  absorbing the fixed costs  associated with these plants and
the general  weakness in wholesale  power markets.  Three  above-market  tolling
agreements for  approximately  1,200 MW of capacity  expired at the end of 2004.
CCO has replaced the expired  agreements with the increased  cooperative load in
Georgia. The increased  cooperative load in Georgia will significantly  increase
CCO's revenue and cost of sales from 2004 to 2005 with lower  margins  expected.
Currently CCO has contracts for its planned production capacity,  which includes
callable resources from the cooperatives, of approximately 77% for 2005, 81% for
2006 and 75% for 2007.  CCO will  continue  its  optimization  strategy  for the
nonregulated generation portfolio.

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  continue  its  presence  in natural  gas  markets  that will allow it to
provide attractive returns for the Company's shareholders.

The Company has begun exploring strategic alternatives regarding the Fuels' coal
mining business,  which could include divesting assets. As of December 31, 2004,
the  carrying  value of  long-lived  assets of the coal mining  business was $66
million.

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.  The  production  and sale of the
synthetic fuel from these facilities  qualifies for tax credits under Section 29
if certain  requirements  are satisfied.  These  facilities  have private letter
rulings  (PLRs) from the IRS with respect to their  synthetic  fuel  operations.
However,  these PLRs do not address  placed-in-service  date  requirements.  The
Company has resolved  certain  synthetic fuel tax credit issues with the IRS and

                                       44

is continuing to work with the IRS to resolve any remaining issues.  The Company
cannot predict the final resolution of any outstanding  matters. 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 8 to 12 million tons
of synthetic fuel in 2005.  Through December 31, 2004, the Company had generated
approximately  $1.5 billion of synthetic fuel tax credits to date (including FPC
prior to the acquisition by the Company). See additional discussion of synthetic
fuel tax credits in Note 23E and in the "Risk Factors" section.

In February  2005,  Progress  Energy  signed a definitive  agreement to sell its
Progress Rail  subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million.  Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.

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 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002

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.

Overview

For the year ended  December  31,  2004,  Progress  Energy's net income was $759
million or $3.13 per share  compared to $782  million or $3.30 per share for the
same  period in 2003.  The  decrease in net income as compared to prior year was
due primarily to:
o    Reduction in synthetic fuel earnings due to lower  synthetic fuel sales due
     to the impact of hurricanes during the year.
o    Lower off-system wholesale sales, primarily at PEC Electric.
o    Higher O&M expenses at PEC Electric.
o    Recording of litigation  settlement  reached in the civil suit by Strategic
     Resource Solutions (SRS).
o    Decreased  nonregulated  generation  earnings  due to receipt of a contract
     termination  payment on a tolling  agreement in 2003,  loss  recognized  on
     early  extinguishment  of debt in 2004 and higher  fixed costs and interest
     charges in 2004.
o    Reduction in revenues due to customer  outages in Florida  associated  with
     the hurricanes.
o    Increased  interest  charges due to the  reversal  of interest  expense for
     resolved tax matters in 2003.

Partially offsetting these items were:
o    Favorable weather in the Carolinas.
o    Reduction in revenue sharing provisions in Florida.
o    Favorable customer growth in both the Carolinas and Florida.
o    Increased margins as a result of the allowed return on the Hines 2 Plant in
     Florida.
o    Increased  earnings  for natural  gas  operations,  which  include the gain
     recorded  on the  disposition  of  certain  Winchester  Production  Company
     assets.
o    Increased earnings for Rail operations.
o    Unrealized gains recorded on contingent value obligations (CVOs).
o    Reduction  in  impairments   recorded  for  an  investment   portfolio  and
     long-lived assets.
o    Reduction in losses recorded for discontinued operations.
o    Reduction in losses recorded for changes in accounting principles.

For the year ended  December  31,  2003,  Progress  Energy's net income was $782
million,  or $3.30 per share,  compared to $528 million, or $2.43 per share, for
the same period in 2002. Income from continuing operations before the 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:

                                       45
<PAGE>

o    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 in the Carolinas.
o    Lower loss recorded in 2003 related to the sale of North  Carolina  Natural
     Gas  Company  (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.

Basic earnings per share  decreased in 2004 and increased in 2003 due in part to
the factors  outlined above.  Dilution  related to issuances under the Company's
Investor Plus and employee  benefit programs in 2004 also reduced basic earnings
per share by $0.06 in 2004.  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.

Beginning in the fourth quarter of 2003, the Company ceased  recording  portions
of the Fuels segment's  operations,  primarily  synthetic fuel  facilities,  one
month in arrears.  As a result,  earnings for the year ended  December 31, 2003,
included  13 months of  operations,  resulting  in a net income  increase  of $2
million for the year.

The Company's segments  contributed the following profit or loss from continuing
operations:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------------------
(in millions)
---------------------------------------------------------------------------------------------------------------
                                                     2004        Change        2003       Change       2002
---------------------------------------------------------------------------------------------------------------
PEC Electric                                       $  464       $  (51)      $   515      $    2      $ 513
PEF                                                   333           38           295         (28)       323
Fuels                                                 180          (55)          235          59        176
CCO                                                    (4)         (24)           20          (7)        27
Rail services                                          16           17            (1)         41        (42)
---------------------------------------------------------------------------------------------------------------
    Total segment profit (loss)                       989          (75)        1,064          67        997
Corporate and other                                  (236)          17          (253)        192       (445)
---------------------------------------------------------------------------------------------------------------
    Total income from continuing operations           753          (58)          811         259        552
Discontinued operations, net of tax                     6           14            (8)         16        (24)
Cumulative effect of changes in accounting
       principles                                       -           21           (21)        (21)         -
---------------------------------------------------------------------------------------------------------------
Net income                                         $  759       $  (23)      $   782      $  254      $ 528
---------------------------------------------------------------------------------------------------------------
</TABLE>

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

                                       46
<PAGE>

Cost Management Initiative

On  February  28,  2005,  as  part of a  previously  announced  cost  management
initiative,   the  executive  officers  of  the  Company  approved  a  workforce
restructuring. The restructuring will result in a reduction of approximately 450
positions  and is  expected  to be  completed  in  September  of 2005.  The cost
management  initiative is designed to permanently  reduce by $75-100 million the
projected growth in the Company's  annual operation and maintenance  expenses by
the end of 2007. In addition to the workforce restructuring, the cost management
initiative includes a voluntary enhanced retirement program.

In connection with the cost management initiative,  the Company expects to incur
one-time  pre-tax  charges of  approximately  $130  million.  Approximately  $30
million of that amount relates to payments for severance  benefits,  and will be
recognized  in the first  quarter  of 2005 and paid  over  time.  The  remaining
approximately  $100 million will be recognized in the second quarter of 2005 and
relates  primarily  to  postretirement  benefits  that will be paid over time to
those  eligible  employees who elect to  participate  in the voluntary  enhanced
retirement  program.  Approximately  3,500 of the Company's 15,700 employees are
eligible to participate in the voluntary enhanced retirement program.  The total
cost management initiative charges could change significantly depending upon how
many eligible  employees  elect early  retirement  under the voluntary  enhanced
retirement program and the salary,  service years and age of such employees (See
Note 24).

Energy Delivery Capitalization Practice

The Company has reviewed  its  capitalization  policies for its Energy  Delivery
business units in PEC and PEF. That review indicated that in the areas of outage
and emergency work not  associated  with major storms and allocation of indirect
costs,  both PEC and PEF should  revise the way that they estimate the amount of
capital  costs  associated  with such work.  The  Company has  implemented  such
changes effective January 1, 2005, which include more detailed classification of
outage and emergency work and result in more precise estimation and a process of
retesting accounting estimates on an annual basis. As a result of the changes in
accounting  estimates for the outage and emergency  work and indirect  costs,  a
lesser  proportion of PEC's and PEF's costs will be capitalized on a prospective
basis. The Company estimates that the combined impact for both utilities in 2005
will be that approximately $55 million of costs that would have been capitalized
under the previous  policies will be expensed.  Pursuant to SFAS No. 71, PEC and
PEF have informed the state  regulators  having  jurisdiction  over them of this
change and that the new estimation process will be implemented effective January
1, 2005. The Company has also requested a method change from the IRS.

Progress Energy Carolinas Electric

PEC Electric contributed segment profits of $464 million,  $515 million and $513
million in 2004, 2003 and 2002,  respectively.  The decrease in profits for 2004
as compared to 2003 is primarily  due to higher O&M charges and lower  wholesale
revenues partially offset by the favorable impact of weather, increased revenues
from customer growth and a reduction in investment losses and impairment charges
compared  to the prior  year.  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.

REVENUES

PEC  Electric's  electric  revenues  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                     2004       % Change       2003       % Change       2002
-------------------------------------------------------------------------------------------------
Residential                       $ 1,324         5.2      $ 1,259         1.5      $ 1,241
Commercial                            888         4.5          850         2.2          832
Industrial                            659         3.6          636        (1.4)         645
Governmental                           82         3.8           79         1.3           78
-------------------------------------------------------------------------------------------------
    Total retail revenues           2,953         4.6        2,824         1.0        2,796
Wholesale                             575       (16.3)         687         5.5          651
Unbilled                               10           -           (6)          -           15
Miscellaneous                          90         7.1           84         9.1           77
-------------------------------------------------------------------------------------------------
    Total electric revenues       $ 3,628         1.1      $ 3,589         1.4      $ 3,539
-------------------------------------------------------------------------------------------------
</TABLE>

                                       47
<PAGE>

PEC Electric's  electric  energy sales 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             2004       % Change        2003      % Change        2002
-------------------------------------------------------------------------------------------------
Residential                        16,003          4.7        15,283       0.3          15,239
Commercial                         13,019          3.7        12,557       0.7          12,468
Industrial                         13,036          2.3        12,749      (2.6)         13,089
Governmental                        1,431          1.6         1,408      (2.0)          1,437
-------------------------------------------------------------------------------------------------
    Total retail energy sales      43,489          3.6        41,997      (0.6)         42,233
Wholesale                          13,222        (14.8)       15,518       3.3          15,024
Unbilled                               91            -           (44)        -             270
-------------------------------------------------------------------------------------------------
    Total MWh sales                56,802          1.2        57,471      (0.1)         57,527
-------------------------------------------------------------------------------------------------
</TABLE>

PEC Electric's revenues, excluding recoverable fuel revenues of $933 million and
$901 million for 2004 and 2003, respectively, increased $7 million. The increase
in revenues was due primarily to increased  retail  revenues of $35 million as a
result of  favorable  weather,  with  cooling  degree days 16% above prior year.
Retail  customer  growth  contributed  an additional  $55 million in revenues in
2004. PEC Electric's retail customer base increased as approximately  26,000 new
customers  were  added in 2004.  The  increase  in retail  revenues  was  offset
partially by lower wholesale revenues.  Wholesale revenues decreased $86 million
when compared to $393 million in 2003. The decrease in PEC Electric's  wholesale
revenues in 2004 from 2003 is primarily the result of reduced excess  generation
sales. Revenues for 2003 included strong sales to the northeastern United States
as a result of  favorable  market  conditions.  In  addition,  lower  contracted
capacity  compared to 2003 further  reduced  wholesale  revenues.  The remaining
reduction in wholesale  revenues is  attributable  to an inelastic power market.
While the cost of fuel  continues  to rise,  the power  market  prices  have not
responded as quickly to the fuel increases.  The differential  between fuel cost
and market price  limited  opportunities  to enter the market.  PEC monitors its
wholesale contract  portfolio on a regular basis.  During 2003 and 2004, several
contracts  expired or were  renegotiated  at lower  prices.  Due to the slightly
depressed wholesale market and increased competition,  this trend could continue
as contracts are renewed in the upcoming years. The expiration and renegotiation
of wholesale  contracts is a normal business activity.  PEC actively manages its
portfolio by seeking to sign new contracts to replace expiring arrangements.

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 in 2003 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.

Downturns in the economy  during 2002 and 2003 impacted  energy usage within the
industrial customer class. Total industrial  revenues,  excluding fuel revenues,
declined  during  2003  when  compared  to  2002 by $13  million,  as  sales  to
industrial customers decreased due to a general industrial  slowdown.  Decreases
in the textile industry and the chemical  industry were among the largest.  This
declining trend leveled out in 2004 as industrial sales increased in the primary
and fabricated metal,  chemicals,  lumber and food industries.  Industrial sales
growth is expected to be flat or very low as expired textile quotas are expected
to lower textile sales and balance gains in other industries.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation,  which include
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery  clauses,  and, as such,  changes in these  expenses do not have a
material  impact on earnings.  The difference  between fuel and purchased  power
costs  incurred and  associated  fuel  revenues  that are subject to recovery is
deferred for future collection or refund to customers.

Fuel and purchased power expenses were $1.137 billion for 2004, which represents
a $16 million increase  compared to the same period in the prior year. Fuel used
in electric  generation  increased  $11 million to $836 million  compared to the
prior year.  This  increase is due to an increase in fuel used in  generation of
$78 million due to higher fuel costs and a change in generation mix. Higher fuel
costs are being  driven  primarily  by an  increase in coal  prices.  Outages at

                                       48
<PAGE>

several  nuclear  facilities  during the year  resulted in increased  combustion
turbine  generation,  which has a higher  average fuel cost. See Part I, Item I,
"Fuel and  Purchased  Power" of  Electric - PEC for a summary  of  average  fuel
costs.  The  increase in fuel used in  generation  is offset by a  reduction  in
deferred fuel expense as a result of the  under-recovery  of current period fuel
costs. Purchased power expenses increased $5 million to $301 million compared to
prior year.  The increase in purchased  power is due primarily to an increase in
price.

Fuel and purchased power expenses were $1.121 billion for 2003, which represents
a $22 million increase  compared to the same period in the prior year. Fuel used
in electric  generation  increased $73 million in 2003,  compared to prior year,
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 Part I, Item I, "Fuel and  Purchased  Power" of Electric -
PEC for a summary of average fuel costs.  Purchased power expense  decreased $51
million in 2003,  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.

Operations and Maintenance (O&M)

O&M  expenses  were $871  million  for 2004,  which  represents  an $89  million
increase  compared to 2003.  This increase is driven  primarily by higher outage
costs and storm  costs in 2004 than in the prior  year.  Outages  increased  O&M
costs by $29  million  primarily  due to an  increase in the number and scope of
nuclear plant outages in 2004. In addition,  costs  associated with  restoration
efforts after severe storms  increased O&M expense $18 million.  Storm costs for
2004 included costs related to an ice storm and  Hurricanes  Charley and Ivan in
the North Carolina service territory.  PEC Electric also incurred storm costs in
2003;  however,  the Company  requested and the NCUC approved  deferral of these
costs.  The Company did not seek to defer costs  associated  with the ice storm,
which hit the North Carolina service territory, and Hurricanes Charley and Ivan.
O&M expenses also increased $9 million due to higher salary- and benefit-related
expenditures. In addition, O&M charges in the prior year were favorably impacted
by $16 million related to the retroactive reallocation of Service Company costs.

O&M expenses were $782 million in 2003,  which represents a $20 million decrease
compared  to 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.

Depreciation and Amortization

Depreciation  and  amortization   expense  was  $570  million  for  2004,  which
represents  an  $8  million   increase   compared  to  2003.  This  increase  is
attributable  primarily  to the  impact  of the NC Clean  Air  legislation.  PEC
Electric  recorded the maximum  amortization  allowed under the  legislation  in
2004. NC Clean Air  amortization  increased $100 million to $174 million in 2004
compared to $74 million in 2003.  Depreciation expense also increased $9 million
for  assets  placed in  service.  These  increases  were  partially  offset by a
reduction in depreciation  expense related to depreciation  studies filed during
the year.  During 2004, PEC met the  requirements of both the NCUC and the SCPSC
for the  implementation  of  depreciation  studies  that  allowed the utility to
reduce the rates used to calculate depreciation expense. The annual reduction in
depreciation  expense  is  approximately  $82  million  compared  to  2003.  The
reduction is due primarily to extended lives at each of PEC's nuclear units. The
new rates became effective January 2004.

Depreciation  and amortization  increased $38 million in 2003,  compared to $524
million in 2002.  Depreciation and amortization increased $74 million related to
the 2003  impact of the NC Clean  Air  legislation  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 8B and 22. In  addition,  depreciation  increased  $19  million  due to
additional assets placed into service.

                                       49
<PAGE>

Taxes Other than on Income

Taxes other than on income were $173 million for 2004,  which  represents an $11
million  increase  compared to the prior year. This increase is due primarily to
an  increase  in gross  receipts  taxes of $8 million  related to an increase in
revenues and a 2004 adjustment related to the prior year. The remaining variance
in other  taxes is due to an  increase  in  property  taxes of $7 million due to
higher property  appraisals  partially offset by a reduction in payroll taxes of
$4 million.

Taxes  other than on income were $162  million in 2003,  which  represents  a $4
million increase  compared to prior year. This increase is due to an increase in
property taxes and payroll taxes of $2 million each.

Interest Expense

Net interest  expense was $192  million,  $197 million and $212 million in 2004,
2003 and 2002, respectively.  Declines in interest expense in 2003 resulted from
reduced  short-term  debt and  refinancing  certain  long-term  debt with  lower
interest rate debt.

Income Tax Expense

Income tax expense was $237 million, $238 million and $237 million in 2004, 2003
and 2002, respectively. In 2004, 2003 and 2002, $22 million, $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,  certain  holding  company tax  benefits are  allocated to
profitable subsidiaries. Other fluctuations in income taxes are primarily due to
changes in pre-tax income.

Progress Energy Florida

PEF contributed  segment profits of $333 million,  $295 million and $323 million
in  2004,  2003 and  2002,  respectively.  Profits  for  2004  increased  due to
favorable  customer  growth,  a reduction in the provision for revenue  sharing,
favorable wholesale revenues, the additional return on investment on the Hines 2
plant and reduced O&M expenses. These items were partially offset by unfavorable
weather,  a reduction in revenues related to the hurricanes,  increased interest
expense and increased  depreciation  expense from assets placed in service.  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.

In  2002,  PEF's  profits  were  affected  by  the  outcome  of  the  rate  case
stipulation, which included a one-time retroactive revenue refund, 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 8C).

REVENUES

PEF's electric revenues 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                          2004    % Change       2003      % Change      2002
-----------------------------------------------------------------------------------------------
Residential                           $ 1,806      6.8          $ 1,691     2.8        $ 1,645
Commercial                                853     15.3              740     1.2            731
Industrial                                254     16.0              219     3.8            211
Governmental                              211     16.6              181     4.6            173
Revenue sharing refund                   (11)       -               (35)     -              (5)
Retroactive retail rate refund              -       -                 -      -             (35)
------------------------------------------------        -----------------         -------------
    Total retail revenues               3,113     11.3            2,796     2.8          2,720
Wholesale                                 268     18.1              227    (1.3)           230
Unbilled                                    7       -                (2)     -              (3)
Miscellaneous                             137      4.6              131    13.9            115
------------------------------------------------        -----------------         -------------
    Total electric revenues           $ 3,525     11.8          $ 3,152     2.9        $ 3,062
-----------------------------------------------------------------------------------------------
</TABLE>


                                       50
<PAGE>

PEF's electric  energy sales 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                         2004    % Change      2003      % Change      2002
---------------------------------------------------------------------------------------------
Residential                           19,347     (0.4)         19,429     3.6         18,754
Commercial                            11,734      1.6          11,553     1.2         11,420
Industrial                             4,069      1.7           4,000     4.3          3,835
Governmental                           3,044      2.4           2,974     4.4          2,850
-----------------------------------------------        ----------------         -------------
    Total retail energy sales         38,194      0.6          37,956     3.0         36,859
Wholesale                              5,101     18.0           4,323     3.4          4,180
Unbilled                                 358       -              233      -               5
-----------------------------------------------        ----------------         -------------
    Total MWh sales                   43,653      2.6          42,512     3.6         41,044
---------------------------------------------------------------------------------------------
</TABLE>

PEF's revenues,  excluding  recoverable fuel and other pass-through  revenues of
$2.007 billion and $1.692 billion for 2004 and 2003, respectively, increased $58
million.  This increase was due primarily to favorable  customer  growth,  which
increased  revenues  $34 million.  PEF has 37,000  additional  retail  customers
compared to prior year.  Revenues were also favorably impacted by a reduction in
the provision for revenue  sharing of $24 million.  Results for 2003 included an
additional  refund of $18 million related to the 2002 revenue sharing  provision
as ordered by the FPSC in July  2003.  In  addition,  improved  wholesale  sales
increased revenues by $11 million.  Included in fuel revenues is the recovery of
depreciation  and  capital  costs  associated  with the Hines  Unit 2, which was
placed into service in December 2003 and  contributed  $36 million in additional
revenues in 2004. The recovery of the Hines Unit 2 costs through the fuel clause
is in accordance with the 2002 rate  stipulation  (See Note 8C). These increases
were partially  offset by the reduction in revenues  related to customer outages
for Hurricanes Charley,  Frances and Jeanne of approximately $12 million and the
impact of milder weather in the current year of $10 million.

PEF's revenues,  excluding  recoverable fuel and other pass-through  revenues of
$1.692 billion and $1.602 billion in 2003 and 2002, respectively, were unchanged
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 by $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 offset by the  negative  impact of the rate
settlement,  which decreased  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 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.

EXPENSES

Fuel and Purchased Power

Fuel and purchased power costs represent the costs of generation,  which include
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery  clauses,  and, as such,  changes in these  expenses do not have a
material  impact on earnings.  The difference  between fuel and purchased  power
costs  incurred and  associated  fuel  revenues  that are subject to recovery is
deferred for future collection or refund to customers.

Fuel and purchased power expenses were $1.742 billion in 2004,  which represents
a $306 million  increase  compared to 2003. This increase is due to increases in
fuel used in electric  generation  and purchased  power expenses of $305 million
and $1 million,  respectively.  Higher system  requirements  and increased  fuel
costs in the current  year  account for $87 million of the increase in fuel used
in electric  generation.  The remaining  increase is due to the recovery of fuel
expenses that were deferred in the prior year,  partially offset by the deferral
of current  year  under-recovered  fuel  expenses.  In November  2003,  the FPSC
approved  PEF's  request for a cost  adjustment in its annual fuel filing due to
the rising costs of fuel. The new rates became effective January 2004.

                                       51
<PAGE>

Fuel used in generation  and  purchased  power  expenses were $1.436  billion in
2003,  which  represents  an $87  million  increase  compared to the prior year.
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 resulted in a $229 million increase  partially offset by the deferral
of 2003 under-recovered fuel and purchased power expense of $142 million.

Operations and Maintenance (O&M)

O&M expenses were $630 million in 2004,  which represents a $10 million decrease
when compared to the prior year. This decrease is primarily related to favorable
benefit-related costs of $16 million, primarily due to lower pension costs which
resulted from improved pension asset performance.

O&M expenses were $640 million in 2003,  which represents a $49 million increase
when compared to the prior year. 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.

Depreciation and Amortization

Depreciation  and  amortization   expense  was  $281  million  for  2004,  which
represents a decrease of $26 million when compared to the prior year,  primarily
due to the amortization of the Tiger Bay regulatory asset in the prior year. The
Tiger Bay  regulatory  asset,  for contract  termination  costs,  was  recovered
pursuant to an agreement between PEF and the FPSC that was approved in 1997. The
amortization  of the regulatory  asset was calculated  using revenues  collected
under the fuel adjustment clause; as such,  fluctuations in this expense did not
have an impact on earnings. During 2003, Tiger Bay amortization was $47 million.
The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger
Bay  amortization  was partially  offset by additional  depreciation  for assets
placed in service,  including depreciation for Hines Unit 2, of approximately $9
million.  This  depreciation  expense is being  recovered  through the fuel cost
recovery  clause as allowed by the FPSC. See discussion of the return on Hines 2
in the revenues analysis above.

Depreciation  and  amortization  was $307 million in 2003,  which  represents an
increase of $12 million when compared to 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.

Taxes Other than on Income

Taxes  other than on income  were $254  million  in 2004,  which  represents  an
increase of $13 million  compared  to the prior  year.  This  increase is due to
increases in gross  receipts and  franchise  taxes of $8 million and $7 million,
respectively,  related to an increase  in  revenues  and an increase in property
taxes of $5 million  due to  increases  in  property  placed in service  and tax
rates.  These increases were partially offset by a reduction in payroll taxes of
$7 million.

Taxes  other than on income  were $241  million  in 2003,  which  represents  an
increase  of $13  million  compared  to prior  year.  This  increase  was due to
increases in payroll  taxes of $10 million and  increases in gross  receipts and
franchise taxes of $4 million combined.

Interest Expense

Interest charges, net were $114 million in 2004, which represents an increase of
$23 million compared to the prior year.  Interest charges,  net were $91 million
in 2003, which represents a $15 million decrease compared to the prior year. The
fluctuations  were  primarily  due to  interest  costs in 2003  being  favorably
impacted by the reversal of interest  expense due to the  resolution  of certain
tax matters.

Income Tax Expense

Income tax expense was $174 million, $147 million and $163 million in 2004, 2003
and 2002, respectively. In 2004, 2003 and 2002, $14 million, $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, certain holding company tax benefits are allocated to profitable
subsidiaries. Other fluctuations in income taxes are primarily due to changes in
pre-tax income.


                                       52
<PAGE>

Diversified Businesses

The  Company's  diversified  businesses  consist of the Fuels  segment,  the CCO
segment and the Rail Services segment.

Fuels

The Fuels' segment  operations  include synthetic fuels production,  natural gas
production,  coal  extraction and terminal  operations.  Beginning in the fourth
quarter  of 2003,  the  Company  ceased  recording  portions  of Fuels'  segment
operations,  primarily  synthetic fuel  facilities,  one month in arrears.  As a
result,  earnings for the year ended  December  31, 2003,  included 13 months of
operations, resulting in a net income increase of $2 million for the year.

The following summarizes Fuels' segment profits:

---------------------------------------------------------------------
(in millions)                           2004        2003        2002
---------------------------------------------------------------------
Synthetic fuel operations             $   91       $ 205       $ 156
Natural gas operations                    85          34          10
Coal fuel and other operations             4         (4)          10
---------------------------------------------------------------------
         Segment profits              $  180       $ 235       $ 176
---------------------------------------------------------------------

SYNTHETIC FUEL OPERATIONS

The production and sale of synthetic fuel generate operating losses, but qualify
for tax credits under Section 29 of the Code,  which more than offset the effect
of such losses (See Note 23E).

The operations resulted in the following losses (prior to tax credits):

-------------------------------------------------------------------------
(in millions)                                  2004       2003      2002
-------------------------------------------------------------------------
Tons sold                                       8.3       12.4      11.2

After-tax losses (excluding tax credits)     $ (124)    $ (141)   $ (135)
Tax credits                                     215        346       291
-------------------------------------------------------------------------
     Net profit                              $   91     $  205    $  156
-------------------------------------------------------------------------

The Company's  synthetic fuel production levels and the amount of tax credits it
can claim  each year are a  function  of the  Company's  projected  consolidated
regular  federal income tax liability.  Synthetic fuel  operations'  net profits
decreased  in 2004 as compared to 2003 due  primarily to a decrease in synthetic
fuel  production  and an increase in operating  expenses in 2004.  The Company's
total synthetic fuel production of  approximately  eight million tons in 2004 is
down compared to 2003 production  levels of  approximately  12 million tons as a
result of hurricane  costs,  which reduced the Company's  projected 2004 regular
tax  liability  and its  corresponding  ability to record tax  credits  from its
synthetic fuel production.  In addition,  earnings in 2003 include a $13 million
favorable tax credit true-up related to 2002.

As of  September  30,  2004,  the  Company  anticipated  an  ability  to  record
approximately  five  million  tons of synthetic  fuels  production  based on the
Company's projected regular tax liability for 2004. This estimate was based upon
the Company's projected casualty loss as a result of the storms.  Therefore, the
Company  recorded a charge of $79  million in the third  quarter for tax credits
associated  with  approximately  2.7 million  tons sold during the year that the
Company  anticipated it would not be able to use. On November 2, 2004, PEF filed
a petition  with the FPSC to recover $252  million of storm costs plus  interest
from  customers  over a two-year  period.  Based on a reasonable  expectation at
December 31, 2004, that the FPSC will grant the requested  recovery of the storm
costs, the Company's loss from the casualty is less than originally anticipated.
Accordingly,  as of  December  31,  2004,  the  Company's  anticipated  2004 tax
liability supported credits on approximately eight million tons. Therefore,  the
Company  recorded tax credits of $90 million for the quarter ended  December 31,
2004,  for tax credits  associated  with  approximately  three million tons sold
during the year that the Company now anticipates can be used. As of December 31,
2004,  the  Company  anticipates  that  approximately  $7 million of tax credits
associated with approximately 0.2 million tons sold during the year could not be
used (See Note 23E). The Company ceased operations at its Earthco facilities for
the last three  months of 2004 due to the  decrease in the  Company's  projected
2004 tax liability, and these facilities were restarted in January 2005.

                                       53
<PAGE>

The  Company  believes  its right to recover  storm  costs is well  established;
however, the Company cannot predict the timing or outcome of this matter. If the
FPSC should deny PEF's  petition for the recovery of storm costs in 2005,  there
could be a material  impact on the amount of 2005 synthetic fuel  production and
results of operations.

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 $13 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.

NATURAL GAS OPERATIONS

Natural gas  operations  generated  profits of $85 million,  $34 million and $10
million for the years ended  December  31,  2004,  2003 and 2002,  respectively.
Natural  gas  profits  increased  $51  million in 2004  compared  to 2003.  This
increase is  attributable  primarily to the gain  recognized  on the sale of gas
assets during the year. In December 2004, the Company sold certain gas-producing
properties  and related  assets owned by  Winchester  Production  Company,  Ltd.
(North Texas gas operations). Because the sale significantly altered the ongoing
relationship between capitalized costs and remaining proved reserves,  under the
full-cost  method of accounting the pre-tax gain of $56 million ($31 million net
of taxes) was recognized in earnings  rather than as a reduction of the basis of
the Company's  remaining  oil and gas  properties.  In addition,  an increase in
production, coupled with higher gas prices in 2004, contributed to the increased
earnings in 2004 as compared to 2003. Production levels increased resulting from
the acquisition of North Texas Gas in late February 2003 and increased  drilling
in 2004.  Volume and prices have increased 21% and 16%,  respectively,  for 2004
compared to 2003.

Natural gas profits  increased to $34 million in 2003 compared to $10 million in
2002. The increase in production and price  resulting from the  acquisitions  of
Westchester in 2002 (renamed  Winchester  Energy in 2004) and North Texas Gas in
the first quarter of 2003 drove increased  revenue and earnings in 2003 compared
to  2002.  In  October  2003,   the  Company   completed  the  sale  of  certain
gas-producing  properties owned by Mesa  Hydrocarbons,  LLC (Mesa). See Notes 5B
and 4D to the Progress Energy Consolidated  Financial Statements for discussions
of the North Texas Gas acquisitions and the Mesa disposition.

The following  table  summarizes  the production and revenues of the natural gas
operations by location:

------------------------------------------------------------------------------
                                                  2004       2003        2002
------------------------------------------------------------------------------
             Production in Bcf equivalent
East Texas/LA gas operations                        20         13           6
North Texas gas operations                          10          7           -
Mesa                                                 -          5           7
------------------------------------------------------------------------------
    Total production                                30         25          13
------------------------------------------------------------------------------
                 Revenues in millions
East Texas/LA gas operations                      $110       $ 65         $24
North Texas gas operations                          52         38           -
Mesa                                                 -         13          15
------------------------------------------------------------------------------
    Total revenues                                $162      $ 116         $39
------------------------------------------------------------------------------
                     Gross margin
In millions of $                                $  126       $ 91         $29
As a % of revenues                                 78%        78%         74%
------------------------------------------------------------------------------

COAL FUEL AND OTHER OPERATIONS

Coal fuel and other  operations  generated  profits of $4 million,  losses of $4
million and profits of $10 million for the years ended  December 31, 2004,  2003
and 2002,  respectively.  The increase in profits for 2004 is  primarily  due to
higher volumes and margins for coal fuel operations of $16 million after-tax. In
addition,  coal results in 2003  included  the  recording  of an  impairment  of
certain  assets at the  Kentucky May coal mine  totaling $11 million  after-tax.
This  favorability was offset by a reduction in profits of $7 million  after-tax
for fuel  transportation  operations  related to the  waterborne  transportation
ruling by the FPSC  (See Note 8C).  Profits  were also  negatively  impacted  by
higher corporate costs of $10 million in 2004. Corporate costs in the prior year
included $4 million of favorability related to the reduction of an environmental
reserve  (See Note 22).  The  remaining  unfavorability  in  corporate  costs is
attributable to increased interest expense related to unresolved tax matters and
higher professional fees.

                                       54
<PAGE>

Coal fuel and other operations  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.  The
decrease in profits is also due to the impact of the retroactive Service Company
allocation in 2003.

The Company is exploring strategic alternatives regarding the Fuels' coal mining
business,  which could include  divesting these assets. As of December 31, 2004,
the  carrying  value of  long-lived  assets of the coal mining  business was $66
million. The Company cannot currently predict the outcome of this matter.

Competitive Commercial Operations

CCO generates and sells  electricity to the wholesale  market from  nonregulated
plants.  These  operations  also include  marketing  activities.  The  following
summarizes the annual  revenues,  gross margin and segment  profits from the CCO
plants:

-------------------------------------------------------
(in millions)                  2004      2003     2002
-------------------------------------------------------
Total revenues                $ 240     $ 170     $ 92
Gross margin
   In millions of $           $ 158     $ 141     $ 83
   As a % of revenues           66%       83%      90%
Segment profits (losses)      $  (4)    $  20     $ 27
-------------------------------------------------------

CCO's  operations  generated  segment  losses of $4 million in 2004  compared to
segment profits of $20 million in 2003. Results for 2004 were favorably impacted
by increased gross margin,  which was more than offset by higher fixed costs and
costs associated with the  extinguishment of debt.  Revenues  increased for 2004
due to increased  revenues  from  marketing  and tolling  contracts  offset by a
termination  payment received on a marketing contract in 2003.  Expenses for the
cost of fuel and purchased power to supply marketing  contracts partially offset
the  increased  revenues  netting  to an  increase  in gross  margin for 2004 as
compared to 2003.  Fixed costs  increased  $16 million  pre-tax from  additional
depreciation  and amortization on plants placed into service in 2003 and from an
increase in interest expense of $13 million pre-tax due primarily to interest no
longer being  capitalized  due to the  completion of  construction  in the prior
year.  In addition,  plant  operating  expenses  increased  $12 million  pre-tax
primarily due to higher gas transportation service charges, which increased over
prior year due to a full  period of expenses  being  reflected  in current  year
results.  CCO  results  for 2004  also  include  losses of $15  million  pre-tax
associated  with the  extinguishment  of a debt  obligation.  CCO terminated the
Genco  financing  arrangement in December 2004. The $15 million  pre-tax loss is
comprised of a $9 million write-off of remaining unamortized debt issuance costs
and a $6 million  realized  loss on exiting  the  related  interest  rate hedge.
Expenses were favorably impacted by a reduction in Service Company  allocations.
Results for 2003 were  negatively  impacted by the  retroactive  reallocation of
Service Company costs of $3 million ($2 million after-tax).

CCO's  operations  generated  segment profits of $20 million in 2003 compared to
segment  profits of $27 million in 2002.  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 MW at December 31, 2002, to
3,100 MW 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  Electric  Membership  Corporation 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 Company has contracts for its planned  production  capacity,  which includes
callable  resources  from  the  cooperatives,  of  approximately  77% for  2005,
approximately 81% for 2006 and approximately 75% for 2007. The Company continues
to seek opportunities to optimize its nonregulated generation portfolio.

Rail Services

Rail Services' (Rail)  operations  represent the activities of Progress Rail and
include railcar and locomotive repair, track-work, rail parts reconditioning and
sales, scrap metal recycling, railcar leasing and other rail-related services.

                                       55
<PAGE>

Rail-contributed  segment  profits of $16 million for 2004 compared with segment
losses of $1 million and $42 million for the years ended  December 31, 2003, and
2002, respectively.  Results in 2004 were favorably impacted by the strong scrap
metal market in 2004.  Revenues were $1.131 billion in 2004, which represents an
increase of $284 million  compared to prior year. This increase is due primarily
to increased  volumes and higher prices in recycling  operations  and in part to
increased   production  and  sales  in  locomotive  and  railcar   services  and
engineering  and  track  services.   Tonnage  for  recycling  operations  is  up
approximately  35% on an  annualized  basis  compared to 2003.  The  increase in
tonnage,  coupled with an increase in the average  index price of  approximately
80%,  accounts  for the  significant  increase in revenues  year over year.  The
American  Metal Market index price for #1 railroad  heavy melt (which is used as
the index for  buying and  selling  of  railcars)  has  increased  to $191 as of
December  31, 2004,  from $106 as of December  31, 2003.  Cost of goods sold was
$990 million in 2004,  which  represents an increase of $252 million compared to
the prior year.  The increase in costs of goods sold is due to  increased  costs
for inventory,  labor and operations as a result of the increased  volume in the
recycling operations,  locomotive and railcar services and engineering and track
services.  In  addition,  results  in  2003  were  negatively  impacted  by  the
retroactive  reallocation of Service Company costs of $3 million after-tax.  The
favorability  related to the  reallocation  was offset by an increase in general
and administrative  costs in 2004 related primarily to higher  professional fees
associated with divestiture efforts. See discussion below.

Rail's  operations  generated  segment  losses of $1 million in 2003 compared to
segment  losses of $42 million in 2002. The reduction in losses in 2003 compared
to 2002 is due primarily to an impairment  charge recorded in 2002. 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 (See Note
4D). Excluding the impairment  recorded in 2002, profits for Rail were flat year
over year 2003 compared to 2002.

In February  2005,  Progress  Energy  signed a definitive  agreement to sell its
Progress Rail  subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million.  Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.

Corporate & Other

Corporate  and Other  consists  of the  operations  of Progress  Energy  Holding
Company  (the  holding  company),  Progress  Energy  Service  Company  and other
consolidating and nonoperating entities. Corporate and Other also includes other
nonregulated   business   areas   including  the   operations  of  SRS  and  the
telecommunication operations.

OTHER NONREGULATED BUSINESS AREAS

Progress  Energy's  other  business  areas include the operations of SRS and the
telecommunications  operations.  SRS was engaged in providing energy services to
industrial,  commercial and institutional  customers to help manage energy costs
primarily  in  the  southeastern  United  States.  During  2004,  SRS  sold  its
subsidiary,  Progress Energy Solutions  (PES).  With the disposition of PES, the
Company  exited  this  business  area.   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
telecommunication  subsidiaries  of Progress  Energy,  and EPIK,  a wholly owned
subsidiary  of  Odyssey,  contributed  substantially  all of  their  assets  and
transferred  certain liabilities to PT LLC, a subsidiary of PTC. The accounts of
PT LLC have been included in the  Company's  Consolidated  Financial  Statements
since the transaction date. See additional  discussion on the  telecommunication
business combination in Note 5A.

Other  nonregulated  business  areas  contributed  segment losses of $38 million
compared to losses of $24 million for the years ended  December  31,  2004,  and
2003, respectively.  SRS recorded a net loss of $27 million for 2004 compared to
a net loss of $6 million for 2003. The increased loss compared to the prior year
is due primarily to the recording of the litigation  settlement reached with San
Francisco United School District (the District) related to civil proceedings. In
June  2004,  SRS  reached  a  settlement  with the  District  that  settled  all
outstanding   claims  for   approximately   $43  million  pre-tax  ($29  million
after-tax). The reduction in earnings due to the settlement was offset partially
by a gain recognized on the sale of Progress Energy Solutions. Telecommunication
operations recorded a net loss of $5 million in 2004 compared to a net profit of
$2 million in 2003.  The increase in losses  compared to prior year is due to an
increase in fixed costs,  mainly  depreciation  expense,  and professional  fees
related  to  the   merger   with  EPIK.   The   increased   losses  at  SRS  and
telecommunication  operations were offset  partially by a reduction in losses at
the  nonutility   subsidiaries  of  PEC.  The  nonutility  subsidiaries  of  PEC
contributed  segment  losses of $6 million  and $18  million for the years ended
December 31, 2004, and 2003,  respectively.  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 (See Note 10B). A reduction
in investment losses accounted for the remaining  favorability compared to prior
year.

                                       56
<PAGE>

Other nonregulated  business areas contributed  segment losses of $24 million in
2003  compared to $250 million for the year ended  December  31, 2002.  The 2002
segment   losses   include  an  asset   impairment  and  other  charges  in  the
telecommunications  business  of  $225  million  after-tax.  See  discussion  of
impairments at Note 10 of the Consolidated Financial Statements.

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)
------------------------------------------------------------------------------------------------
                                         2004        Change      2003       Change      2002
------------------------------------------------------------------------------------------------
Other interest expense                  $ (270)      $  15     $ (285)      $ (10)    $ (275)
Contingent value obligations                 9          18         (9)        (37)        28
Tax reallocation                           (37)          1        (38)         18        (56)
Other income taxes                          102        (22)       124          11        113
Other income (expense)                      (2)         19        (21)        (16)        (5)
------------------------------------------------------------------------------------------------
     Segment loss                       $ (198)      $  31     $ (229)      $ (34)    $ (195)
------------------------------------------------------------------------------------------------
</TABLE>

The other interest  expense  decrease for 2004 compared to 2003 is partially due
to the  repayment of a $500  million  unsecured  note by the Holding  Company on
March 1, 2004,  which reduced  interest expense by $27 million pre-tax for 2004.
This  reduction  was offset by interest no longer being  capitalized  due to the
completion of construction in the CCO segment in 2003. Approximately $10 million
($6  million  after-tax)  was  capitalized  in 2003.  No  interest  expense  was
capitalized during 2004. 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 the construction of plants by CCO which was completed in 2003.

Progress  Energy  issued 98.6 million  contingent  value  obligations  (CVOs) in
connection with the acquisition of FPC in 2000. 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, 2004,  2003 and
2002, the CVOs had a fair market value of approximately $13 million, $23 million
and $14 million, respectively.  Progress Energy recorded unrealized losses of $9
million for 2003 and an  unrealized  gain of $9 million and $28 million for 2004
and 2002,  respectively,  to record the changes in fair value of CVOs, which had
average unit prices of $0.14,  $0.23 and $0.14 at December  31,  2004,  2003 and
2002, respectively.

Progress  Energy  and its  affiliates  file a  consolidated  federal  income tax
return.  The  consolidated  income  tax  of  Progress  Energy  is  allocated  to
subsidiaries in accordance with the Intercompany Income Tax Allocation Agreement
(Tax  Agreement).  The Tax  Agreement  provided an  allocation  that  recognizes
positive and negative  corporate taxable income.  The Tax Agreement provides for
an equitable method of apportioning the carryover 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
Public Utility Holding Company Act of 1935, as amended (PUHCA) order.

Other income taxes benefit  decreased for 2004 compared to 2003 due primarily to
increased  taxes  booked at the Holding  Company of $21  million.  Income  taxes
increased  an  additional  $9  million at the  Holding  Company as a result of a
reserve booked related to identified state tax deficiencies.  Other income taxes
benefit  decreased for 2003 compared to 2002 primarily for the tax allocation to
the profitable  subsidiaries.  Other  fluctuations in income taxes are primarily
due to changes in pre-tax income.

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. In September 2003, Progress
Energy  completed  the sale of NCNG and ENCNG for net proceeds of  approximately
$450  million  in  September   2003.   Progress  Energy  incurred  a  loss  from
discontinued  operations  of $8  million  for 2003  compared  with a loss of $24
million for 2002.  During the year ended December 31, 2004, the Company recorded
a reduction to the loss on the sale of NCNG of  approximately $6 million related
to deferred taxes (See Note 4E).

Cumulative Effect of Accounting Changes

In 2003,  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

                                       57
<PAGE>

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 2003 for $23 million after-tax (See Note 18A).

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

As discussed in Note 8, 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 rate-making 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 8 provides
additional  information  related  to the  impact of  utility  regulation  on the
Company.

Asset Impairments

As discussed in Note 10, 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). Fair value was determined  based
on discounted cash flows.  During 2002, the Company recorded pre-tax  long-lived
asset  impairments of $305 million related to its  telecommunications  business.
The fair  value of these  assets was  determined  considering  various  factors,
including  a  valuation  study  heavily  weighted  on  a  discounted  cash  flow
methodology and using market approaches as supporting information.

                                       58
<PAGE>

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 2003.  PEC also  recorded an impairment of $3 million
for a cost investment.  During 2002, the Company recorded pre-tax impairments to
its cost method  investment in Interpath of $25 million.  The fair value of this
investment was determined  considering  various  factors,  including a 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.

Under the  full-cost  method of  accounting  for oil and gas  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.  The ceiling test takes into
consideration  the prices of qualifying cash flow hedges as of the balance sheet
date. 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 2004, 2003 or 2002.

Goodwill

As  discussed in Note 9,  effective  January 1, 2002,  the Company  adopted FASB
Statement No. 142,  "Goodwill and Other Intangible  Assets," which requires that
goodwill be tested for  impairment at least  annually and more  frequently  when
indicators of impairment exist. 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  Company  performed  the annual  goodwill
impairment  test for the CCO segment in the first quarters of 2004 and 2003, and
the annual goodwill impairment test for the PEC Electric and PEF segments in the
second quarters of 2004 and 2003, each of which indicated no impairment.  If the
fair values for the utility  segments  were lower by  approximately  10%,  there
still would be no impact on the reported value of their  goodwill.  The carrying
amounts of goodwill at December 31, 2004 and 2003, for  reportable  segments PEC
Electric,  PEF and CCO,  are $1,922  million,  $1,733  million and $64  million,
respectively.  In December  2003, $7 million in goodwill was acquired as part of
Progress  Telecommunications  Corporation's  partial acquisition of EPIK and was
reported in the Corporate and Other segment. The Company revised the preliminary
EPIK  purchase  price  allocation  as of September  2004,  and the $7 million of
goodwill  was  reallocated  to certain  tangible  assets  acquired  based on the
results of valuations and appraisals.

Synthetic Fuels Tax Credits

As discussed in Note 23E, Progress Energy, through the Fuels business unit, owns
facilities  that produce  synthetic  fuel as defined under the Internal  Revenue
Code.  The  production  and sale of the  synthetic  fuels from these  facilities
qualifies  for  tax  credits  under  Section  29  if  certain  requirements  are
satisfied,   including  a   requirement   that  the   synthetic   fuels  differs
significantly  in  chemical  composition  from the  coal  used to  produce  such
synthetic fuels and that the fuel was produced from a facility placed in service
before  July 1, 1998.  The amount of  Section  29  credits  that the  Company is
allowed to claim in any calendar  year is limited by the amount of the Company's
regular federal income tax liability. Synthetic fuels tax credit amounts allowed
but not  utilized  are carried  forward  indefinitely  as  deferred  alternative
minimum tax credits on the Consolidated Balance Sheets. All of Progress Energy's
synthetic fuel  facilities have received PLRs from the IRS with respect to their
operations, although these do not address placed-in-service date determinations.
The PLRs do not limit the  production  on which  synthetic  fuel  credits may be
claimed.  The current  Section 29 tax credit program expires at the end of 2007.
These tax credits are subject to review by the IRS, and if Progress Energy fails
to  prevail  through  the  administrative  or legal  process,  there  could be a
significant tax liability owed for previously  taken Section 29 credits,  with a
significant impact on earnings and cash flows. Additionally,  the ability to use
tax  credits  currently  being  carried  forward  could be denied.  See  further
discussion in "OTHER MATTERS" below, Note 23E and in the "Risk Factors" section.

Pension Costs

As discussed in Note 17A,  Progress Energy maintains  qualified  noncontributory
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.

                                       59
<PAGE>

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
used to present value future benefit payments,  the Company lowered the discount
rate to 5.9% at December 31, 2004,  which will  increase the 2005 benefit  costs
recognized,  all other factors remaining constant. Plan assets performed well in
2004, with returns of  approximately  14%. That positive asset  performance will
result in decreased pension costs in 2005, all other factors remaining constant.
Evaluations  of the effects of these and other factors have not been  completed,
but the Company  estimates  that the total cost  recognized for pensions in 2005
will be  approximately  $12 to $20 million  higher  than the amount  recorded in
2004.

The  Company has pension  plan  assets with a fair value of  approximately  $1.8
billion at December 31, 2004.  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 adjust
that return only 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 and 2004. A 0.25% change in the expected rate of return for 2004
would have changed 2004 pension costs by approximately $4 million.

Another factor  affecting the Company's  pension costs,  and  sensitivity of the
costs 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 costs sooner under the fair value method than the five-year averaging
method,  and,  therefore,  pension costs tend to be more volatile using the fair
value method. For example, in 2004 the expected return for assets subject to the
averaging  method was 2% lower than in 2003,  whereas  the  expected  return for
assets  subject  to  the  fair  value  method  was  24%  higher  than  in  2003.
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. The  Company's  primary cash needs at the holding  company level are
its common stock  dividend and interest  expense and  principal  payments on its
$4.3  billion of senior  unsecured  debt.  The  ability  to meet these  needs is
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 the Company arise  primarily from the
capital-intensive nature of its electric utility operations and expenditures for
its diversified businesses, primarily those of the Fuels segment.

The Company relies upon its operating cash flow,  primarily generated by its two
regulated electric utility  subsidiaries,  commercial paper and bank facilities,
and its ability to access  long-term debt and equity capital markets for sources
of liquidity.

The majority of the Company's  operating  costs are related to its two regulated
electric  utilities,  and a significant portion of these costs is 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. A nonutility money pool allows Progress Energy's nonregulated  operations
to lend and borrow funds among each other. Progress Energy can lend money to the
utility and nonutility money pools but cannot borrow funds.

                                       60
<PAGE>

Cash from operations,  asset sales and the issuance of common stock are expected
to fund capital  expenditures  and common  dividends  for 2005.  Any excess cash
proceeds  would be used to reduce  debt.  To the  extent  necessary,  short- and
long-term debt may also be used as a source of liquidity.

The Company  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 the Company's liquidity and capital resources is on
a consolidated basis.

HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002

Cash Flows from Operations

Cash from  operations is the primary source used to meet operating  requirements
and  capital  expenditures.  Net cash  provided  by  operating  activities  from
continuing  operations  for the three years ending  December 31, 2004,  2003 and
2002 were $1.6 billion, $1.7 billion and $1.6 billion, respectively.

Cash from  operating  activities for 2004 when compared with 2003 decreased $117
million, as the net result of the impact of hurricane costs, partially offset by
the impact of an under-recovery of fuel costs in 2003. The increase in cash from
operating  activities  for 2003 when compared with 2002 is largely the result of
improved operating results at PEC.

During the third quarter of 2004, four hurricanes struck significant portions of
the Company's  service  territories,  with the most significant  impact on PEF's
territory.  Restoration of the Company's systems from storm-related  damage cost
an estimated $398 million.  PEC's cost totaled $13 million, of which $12 million
was charged to O&M and $1 million was  charged to  capital.  PEF's cost  totaled
$385 million, of which $338 million was charged to Storm Damage Reserve pursuant
to a  regulatory  order and $47 million  was charged to capital.  On November 2,
2004, PEF filed a petition with the Florida Public Service  Commission (FPSC) to
recover $252 million of storm costs plus interest from retail rate payers over a
two-year period (See Note 3).

Progress Energy is allowed to recover fuel costs incurred by PEC and PEF through
their respective fuel cost recovery  surcharges.  Fuel price volatility can lead
to over- or  under-recovery  of fuel  costs,  as changes in fuel  prices are not
immediately  reflected in fuel  surcharges  due to regulatory lag in setting the
surcharges.  As a result,  fuel price  volatility  can be both a source of and a
drag on  liquidity  resources,  depending  on what  phase of the  cycle of price
volatility the Company is experiencing. In addition, in 2004 PEF agreed with the
FPSC to use a two-year period to determine the surcharge for the  underrecovered
fuel costs incurred in 2004 (See Note 8C).

Investing Activities

Net cash used in investing  activities  for the three years ending  December 31,
2004,  2003  and  2002  were  $0.9  billion,  $1.5  billion  and  $2.2  billion,
respectively.

Utility property additions for the Company's  regulated electric operations were
$1.0 billion or approximately 75% of consolidated  capital  expenditures in 2004
and $1.0 billion or approximately  58% of consolidated  capital  expenditures in
2003,  excluding  proceeds  from  asset  sales.  Capital  expenditures  for  the
regulated electric operations are primarily for normal construction activity and
ongoing  capital  expenditures  related to  environmental  compliance  programs.
Capital  expenditures for the nonregulated  operations are primarily for natural
gas development activities and normal construction activity.

Excluding proceeds from sales of subsidiaries and other  investments,  cash used
in  investing  activities  decreased  approximately  $887  million  in 2004 when
compared  with 2003.  The  decrease is due  primarily  to the  acquisition  of a
nonregulated  generation  contract and acquisition of gas assets in 2003 and net
proceeds  from  short-term  investments  in 2004,  compared to net  purchases of
short-term investments in 2003.

Excluding proceeds from sales of subsidiaries and other  investments,  cash used
in  investing  activities  was $2.1  billion in 2003,  down  approximately  $119
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.

                                       61
<PAGE>

During 2004,  sales of subsidiaries  and other  investments  primarily  included
proceeds from the sale of Railcar Ltd. assets of  approximately  $75 million and
proceeds of approximately $251 million related to the sale of natural gas assets
in the Forth Worth basin of Texas.  Progress Energy used the proceeds from these
sales to reduce  indebtedness,  including  $241  million to pay off the Progress
Genco Ventures, LLC, bank facility.

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  in Colorado.  Progress  Energy used the proceeds from these sales to
reduce indebtedness, primarily commercial paper, then outstanding.

During 2003, the Company acquired  approximately 200 natural gas-producing wells
for a cash purchase price of $168 million. The Company also acquired a long-term
full-requirements  power  supply  agreement  with  Jackson  Electric  Membership
Corporation for a cash payment of $188 million.

During 2002, the Company purchased two electric  generation  projects for a cash
purchase price of $348 million.

Financing Activities

Net cash (used in) provided by financing  activities  for the three years ending
December 31, 2004,  2003 and 2002 were $(720),  $(192) million and $581 million,
respectively. See Note 13 for details of debt and credit facilities.

For 2004 and 2003,  cash from  operations  exceeded  net cash used in  investing
activities  by $735 million and $178  million,  respectively,  due  primarily to
asset  sales,  which  allowed for a net  decrease in cash  provided by financing
activities.  For 2002,  net cash used in investing  activity  exceeded cash from
operations by $574 million, which resulted in net cash from financing activities
of $581 million.

In  addition  to  the  financing  activities  discussed  under  "Overview,"  the
financing activities of the Company included:

2005

o    In January 2005,  the Company used proceeds from the issuance of commercial
     paper to pay off $260 million of revolving credit agreement (RCA) loans.

o    On January 31, 2005,  Progress Energy, Inc. entered into a new $600 million
     revolving credit agreement,  which expires December 30, 2005. This facility
     was added to provide  additional  liquidity  during 2005 due in part to the
     uncertainty  of the  timing of storm  restoration  cost  recovery  from the
     hurricanes in Florida during 2004. The credit agreement  includes a defined
     maximum  total debt to total  capital  ratio of 68% and a minimum  interest
     coverage  ratio of 2.5 to 1. The credit  agreement  also  contains  various
     cross-default and other acceleration provisions.  On February 4, 2005, $300
     million was drawn under the new facility to reduce commercial paper and pay
     off the remaining amount of RCA loans outstanding.

o    In March 2005,  Progress  Energy,  Inc.'s  five-year  credit  facility  was
     amended to increase the maximum  total debt to total capital ratio from 65%
     to 68% in  anticipation  of the  potential  impacts of proposed  accounting
     rules for uncertain tax positions. See Notes 2 and 23E.

2004

o    During the fourth quarter of 2004, Progress Energy and its subsidiaries PEC
     and PEF borrowed a net total of $475 million under certain revolving credit
     facilities.  The borrowed  funds were used to pay off  maturing  commercial
     paper and for  other  cash  needs.  A  summary  of RCA loans and  available
     capacity as of December 31, 2004, is as follows:

                                       62
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
--------------------------------------------------------------------------------------------------------------
(in millions)
 Company                          Description                       Total        Outstanding     Available
--------------------------------------------------------------------------------------------------------------
Progress Energy, Inc.             5-Year (expiring 8/5/09)       $ 1,130          $ 160          $ 970
Progress Energy Carolinas, Inc.   364-Day (expiring 7/27/05)         165             90             75
Progress Energy Carolinas, Inc.   3-Year (expiring 7/31/05)          285              -            285
Progress Energy Florida, Inc.     364-Day (expiring 3/29/05)         200            170             30
Progress Energy Florida, Inc.     3-Year (expiring 4/01/06)          200             55            145
Less:  amounts reserved(a)                                             -              -           (574)
--------------------------------------------------------------------------------------------------------------
Total credit facilities                                          $ 1,980          $ 475          $ 931
--------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  To the extent  amounts are reserved for  commercial  paper  outstanding  or
     backing   letters  of  credit,   they  are  not  available  for  additional
     borrowings.

o    On December 17, 2004,  the Company used  proceeds  from the sale of natural
     gas assets to extinguish  Progress Genco Ventures,  LLC's $241 million bank
     facility (See Note 13D).

o    Progress Energy took advantage of favorable  market  conditions and entered
     into a new $1.1 billion five-year line of credit, effective August 5, 2004,
     and expiring August 5, 2009. This facility  replaced Progress Energy's $250
     million  364-day  line of credit and its  three-year  $450  million line of
     credit, which were both scheduled to expire in November 2004.

o    On July 28, 2004,  PEC  extended  its $165 million  364-day line of credit,
     which was  scheduled  to expire on July 29,  2004.  The line of credit will
     expire on July 27, 2005.

o    On July 1, 2004, PEF paid at maturity $40 million 6.69%  Medium-Term  Notes
     Series B with commercial paper proceeds and cash from operations.

o    On April 30,  2004,  PEC  redeemed  $35 million of  Darlington  County 6.6%
     Series Pollution  Control Bonds at 102.5% of par, $2 million of New Hanover
     County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million
     of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with
     cash from operations.

o    On March 1, 2004, Progress Energy used available cash and proceeds from the
     issuance of  commercial  paper to pay at maturity $500 million 6.55% senior
     unsecured notes. Cash and commercial paper capacity for this retirement was
     created primarily from proceeds of the sale of assets in 2003.

o    On February 9, 2004, Progress Capital Holdings,  Inc., paid at maturity $25
     million 6.48% medium term notes with available cash from operations.

o    On January  15,  2004,  PEC paid at  maturity  $150  million  5.875%  First
     Mortgage Bonds with commercial paper proceeds.  On April 15, 2004, PEC also
     paid at maturity $150 million 7.875% First  Mortgage Bonds with  commercial
     paper proceeds and cash from operations.

o    For 2004, the Company issued  approximately  1 million shares of its common
     stock for  approximately $73 million in net proceeds from its Investor Plus
     Stock Purchase Plan and its employee benefit and stock option plans, net of
     purchases of restricted  shares.  For 2004,  the  dividends  paid on common
     stock were approximately $558 million.

2003

o    Progress Energy obtained a three-year financing order, allowing it to issue
     up to $2.8 billion of  long-term  securities,  $1.5  billion of  short-term
     debt,  and  $3  billion  in  parent  guarantees.   Progress  Energy  issued
     approximately  8  million  shares of common  stock for  approximately  $304
     million in net proceeds from its Investor Plus Stock  Purchase Plan and its
     employee  benefit plans, net of purchases of restricted  shares.  For 2003,
     the dividends paid on common stock were approximately $541 million.

o    PEC redeemed $250 million and issued $600 million in first mortgage bonds.

                                       63
<PAGE>

o    PEF redeemed  $250  million,  issued $950 million and paid at maturity $180
     million in first mortgage  bonds.  PEF also paid at maturity $35 million in
     medium-term notes.

o    Progress  Capital   Holdings,   Inc.,  paid  at  maturity  $58  million  in
     medium-term notes.

o    Progress Genco  Ventures,  LLC,  terminated its $50 million working capital
     credit facility.  Under its related construction facility,  Genco had drawn
     $241 million at December 31, 2003.

2002

o    Progress  Energy issued $800 million in senior  unsecured  notes.  Progress
     Energy issued approximately 2 million shares representing approximately $86
     million in proceeds  from its  Investor  Plus Stock  Purchase  Plan and its
     employee benefit plans.

o    PEC issued and redeemed  $500 million in senior  unsecured  notes and $48.5
     million in pollution  control  obligations.  PEC also redeemed $150 million
     and paid at maturity $100 million in first mortgage bonds.

o    PEF issued and redeemed $241 million in pollution  control  obligations and
     paid at maturity $30 million in medium-term notes.

o    Progress  Capital   Holdings,   Inc.,  paid  at  maturity  $50  million  in
     medium-term notes.

o    Progress  Genco  Ventures,  LLC,  obtained a $440  million  bank  facility,
     including $50 million for working capital. During the year, $130 million of
     the facility was terminated.  The amount  outstanding at December 31, 2002,
     was $225 million.

o    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.  For 2002,  the dividends paid on common
     stock were approximately $480 million.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

The Company's two electric  utilities  produced over 100% of  consolidated  cash
from  operations in 2004. 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 increase their operating cash
flows.

PEF  notified  the FPSC in January 2005 of its intent to file for an increase in
its base rates  effective  January 1, 2006. If approved by the FPSC, an increase
in PEF's base rates would increase  future  operating cash flows.  PEF has faced
significant  cost  increases  over the past decade and  expects its  operational
costs to continue to increase.  These costs  include the costs  associated  with
completion of the Hines 3 generation  facility,  extraordinary  hurricane damage
costs including capital costs not expected to be directly recoverable,  the need
to  replenish  the  depleted  storm  reserve  and  the  expected  infrastructure
investment  necessary  to meet  high  customer  expectations,  coupled  with the
demands placed on PEF as a result of strong  customer  growth.  If the FPSC does
not approve  PEF's  request to increase  base rates,  the  Company's  results of
operations and financial  condition  could be negatively  impacted.  The Company
cannot  predict the outcome of this matter.  Related risks are described in more
detail in the "Risk Factors" section.

In addition,  Fuels' synthetic fuel operations do not currently produce positive
operating  cash flow 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. See Note 23E for further discussion.

Capital Expenditures

Total cash from  operations  provided  the  funding  for the  Company's  capital
expenditures,  including  property  additions,  nuclear  fuel  expenditures  and
diversified  business property  additions during 2004,  excluding  proceeds from
asset sales of $366 million.

                                       64
<PAGE>

As shown in the table below, Progress Energy expects the majority of its capital
expenditures  to be  incurred  at its  regulated  operations.  See Note 8F for a
discussion of expected impacts on future capital  expenditures due to changes in
capitalization  practice for regulated  operations.  The Company anticipates its
regulated capital  expenditures will increase in 2005 due to increased  spending
on Clean Air initiatives.  Forecasted nonregulated expenditures relate primarily
to Progress Fuels and its gas operations, mainly for drilling new wells.


<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------
                                       Actual                     Forecasted
                                     -----------   -------------------------------------------
(in millions)                           2004            2005            2006             2007
----------------------------------------------------------------------------------------------
Regulated capital expenditures        $   998        $ 1,030          $ 1,040         $ 1,090
Nuclear fuel expenditures                 101            120               90             150
AFUDC - borrowed funds                     (6)           (10)             (10)            (10)
Nonregulated capital expenditures         236            190              180             190
----------------------------------------------------------------------------------------------
     Total                            $ 1,329        $ 1,330          $ 1,300         $ 1,420
----------------------------------------------------------------------------------------------
</TABLE>

Regulated  capital  expenditures  in the table above include total  expenditures
from 2005 through 2006 of  approximately  $65 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.

The Company also expects to incur expenditures of approximately $15 million ($10
million  at PEC and $5  million at PEF) from 2005  through  2007 and  additional
expenditures  of  approximately  $70 million to $100 million ($10 million to $20
million at PEC and $60 million to $80 million at PEF) from 2008 through 2009 for
compliance with the Section 316(b) requirements of the Clean Water Act (See Note
22).

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  $895 million by 2013. For the
years 2005 through 2007, the Company expects to incur approximately $475 million
of total capital costs  associated with this  legislation,  which is included in
the table above (See Note 22).

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.

Other Cash Needs

As of December 31, 2004, on a consolidated  basis,  the Company had $349 million
of  long-term  debt  maturing  in 2005.  Progress  Energy  expects  to pay these
maturities  using  funds  from  operations,  issuance  of  new  long-term  debt,
commercial paper borrowings and/or issuance of new equity securities.

In 2006, $800 million of Progress Energy senior unsecured notes will mature. The
Company  expects  to fund  the  maturity  using  proceeds  from  the sale of the
Progress Rail  subsidiary,  issuance of new  long-term  debt,  commercial  paper
borrowings and/or issuance of new equity securities.

During the fourth quarter of 2004, Progress Energy announced the launch of a new
cost management  initiative aimed at achieving nonfuel O&M expense reductions of
$75 million to $100 million annually by the end of 2007. In connection with this
cost  management  initiative,  the  Company  expects to incur  one-time  pre-tax
charges of approximately $130 million.  Approximately $30 million of that amount
relates to payments for  severance  benefits,  which will be  recognized  in the
first  quarter  of 2005 and paid over time.  The  remaining  approximately  $100
million will be recognized in the second  quarter of 2005 and relates  primarily
to  postretirement  benefits  that  will be paid  over  time to  those  eligible
employees who elect to participate in the voluntary enhanced  retirement program
(See Note 24).

Credit Facilities

At December 31, 2004, the Company and its  subsidiaries  had committed  lines of
credit  and  outstanding  balances  as shown in the table in Note 13. All of the
credit  facilities  supporting the credit were arranged through a syndication of
financial  institutions.  There are no bilateral contracts associated with these
facilities.

                                       65
<PAGE>

The Company's  financial policy precludes issuing  commercial paper in excess of
its  supporting  lines of credit.  At December  31,  2004,  the Company had $424
million of commercial  paper  outstanding,  $150 million reserved for backing of
letters of credit and an additional  $475 million drawn directly from the credit
facilities,  leaving  $931  million  available  for  issuance  or  drawdown.  In
addition,  the Company has requirements to pay minimal annual commitment fees to
maintain its credit facilities. At December 31, 2003, the Company had $4 million
of  commercial  paper  outstanding.  The  Company  expects  to  continue  to use
commercial  paper issuances as a source of liquidity as long as it maintains its
current short-term ratings.

All of the  credit  facilities  include a defined  maximum  total  debt-to-total
capital ratio (leverage) and coverage ratios.  The Company is in compliance with
these covenants at December 31, 2004. See Note 13 for a discussion of the credit
facilities'  financial covenants,  material adverse change clause provisions and
cross-default  provisions.  At December 31, 2004, the calculated  ratios for the
companies, pursuant to the terms of the agreements, are as disclosed in Note 13.

Both PEC and PEF plan to enter  into new  five-year  lines of  credit in 2005 to
replace their existing credit facilities.

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,
2004,  the Company had  approximately  $1.1 billion  available  under this shelf
registration.

Progress Energy and PEF each have an uncommitted  bank bid facility  authorizing
each of them to borrow and reborrow,  and have loans outstanding at any time, up
to $300 million and $100 million, respectively. At December 31, 2004, 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, 2004,  PEC and PEF could issue up to
$2.9 billion and $3.7  billion,  respectively,  based on property  additions and
$2.2 billion and $176 million, respectively, based upon retirements.

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

--------------------------------------------------------------------------------
                               Progress Energy                  PEC
                          -------------------------  ---------------------------
                             2004          2003         2004            2003
--------------------------------------------------------------------------------
Common stock                 41.7%         40.5%        47.1%           48.2%
Preferred stock and
   minority interest          0.7%          0.7%         0.9%            0.9%
Total debt                   57.6%         58.8%        52.0%           50.9%
--------------------------------------------------------------------------------

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.

                                       66
<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.
Outlook                                   Negative               Negative           Stable
Corporate credit rating                      n/a                   BBB                n/a
Senior unsecured debt                       Baa2                   BBB-              BBB-
Commercial paper                             P-2                   A-3                n/a
---------------------------------------------------------------------------------------------------
Progress Energy Carolinas, Inc.
Corporate credit rating                      n/a                   BBB                n/a
Commercial paper                             P-2                   A-3                F2
Senior secured debt                          A3                    BBB                A-
Senior unsecured debt                       Baa1                   BBB               BBB+
---------------------------------------------------------------------------------------------------
Progress Energy Florida, Inc.
Corporate credit rating                      n/a                   BBB                n/a
Commercial paper                             P-2                   A-3                F2
Senior secured debt                          A2                    BBB                A-
Senior unsecured debt                        A3                    BBB               BBB+
---------------------------------------------------------------------------------------------------
FPC Capital I
Preferred stock*                            Baa2                   BB+                n/a
--------------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Senior unsecured debt*                      Baa1                   BBB-               n/a
---------------------------------------------------------------------------------------------------
</TABLE>
*Guaranteed by Florida Progress Corporation.

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

On February 11, 2005, Moody's credit rating agency announced that it lowered the
ratings of PEF,  Progress  Capital  Holdings and FPC Capital Trust I and changed
their rating outlooks to stable from negative.  Moody's  affirmed the ratings of
Progress  Energy and PEC. The rating  outlooks  continue to be stable at PEC and
negative at Progress  Energy.  Moody's stated that it took this action primarily
due to declining  cash flow  coverages  and rising  leverage,  higher O&M costs,
uncertainty  regarding the timing of hurricane cost recovery,  regulatory  risks
associated   with  the  upcoming  rate  case  in  Florida  and  ongoing  capital
requirements to meet Florida's growing demand.

On October  19,  2004,  S&P changed  Progress  Energy's  outlook  from stable to
negative.  S&P cited the  uncertainties  regarding the timing of the recovery of
hurricane  costs,  the Company's debt  reduction  plans and the IRS audit of the
Company's  Earthco  synthetic fuels  facilities as the reasons for the change in
outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress
Energy,  PEC and PEF to A-3 from  A-2,  as a result of their  change in  outlook
discussed above.

On October 20, 2004, Moody's changed its outlook for Progress Energy from stable
to negative and placed the ratings of PEF under  review for possible  downgrade.
PEC's ratings were affirmed by Moody's.

Moody's cited the  following  reasons for its change in the outlook for Progress
Energy:  financial ratios that are weak for its current rating category;  rising
O&M,  pension,  benefit  and  insurance  costs;  and  delays  in  executing  its
deleveraging  plan.  With  respect to PEF,  Moody's  cited  declining  cash flow
coverages and rising  leverage  over the last several  years,  expected  funding
needs for a large capital expenditure program, risks with regard to its upcoming
2005 rate case and the timing of hurricane  cost recovery as reasons for putting
its ratings under review.

The changes by S&P and Moody's do not trigger any debt or  guarantee  collateral
requirements,  nor do they have any material impact on the overall  liquidity of
Progress Energy or any of its affiliates.  To date, Progress Energy's, PEC's and
PEF's access to the commercial paper markets has not been materially impacted by
the rating agencies' actions.  However,  the changes have increased the interest
rate incurred on its short-term borrowings by 0.25% to 0.875%.

                                       67
<PAGE>

If  Standard & Poor's  lowers  Progress  Energy's  senior  unsecured  rating one
ratings  category to BB+ from its current  rating,  it would be a  noninvestment
grade rating.  The effect of a noninvestment  grade rating would primarily be to
increase  borrowing  costs.  The Company's  liquidity would  essentially  remain
unchanged,  as the Company  believes it could borrow under its revolving  credit
facilities  instead of issuing  commercial  paper for its  short-term  borrowing
needs. However,  there would be additional funding requirements of approximately
$450  million due to ratings  triggers  embedded in various  contracts,  as more
fully described below under "Guarantees" and "Risk Factors."

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.  In  addition,  the Company and its  subsidiaries  have certain
contracts  that have  provisions  triggered  by a ratings  downgrade to a rating
below investment grade.  These contracts include  counterparty trade agreements,
derivative  contracts,  certain Progress Energy  guarantees and various types of
third-party purchase agreements.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

The Company's  off-balance  sheet  arrangements and contractual  obligations are
described below.

Guarantees

As a  part  of  normal  business,  Progress  Energy  and  certain  wholly  owned
subsidiaries  enter  into  various  agreements  providing  future  financial  or
performance  assurances to third parties that are outside the scope of Financial
Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting
and Disclosure  Requirements for Guarantees,  Including  Indirect  Guarantees of
Indebtedness  of  Others"  (FIN No.  45).  These  agreements  are  entered  into
primarily to support or enhance the  creditworthiness  otherwise  attributed  to
Progress Energy and subsidiaries on a stand-alone  basis,  thereby  facilitating
the extension of  sufficient  credit to accomplish  the  subsidiaries'  intended
commercial purposes.  The Company's  guarantees include performance  obligations
under power supply agreements, tolling agreements,  transmission agreements, gas
agreements,  fuel procurement  agreements and trading operations.  The Company's
guarantees also include  standby letters of credit,  surety bonds and guarantees
in support of nuclear  decommissioning.  At December 31,  2004,  the Company had
issued $1.3 billion of guarantees for future financial or performance assurance.
Management does not believe  conditions are likely for  significant  performance
under the guarantees of performance issued by or on behalf of affiliates.

The majority of contracts  supported by the guarantees  contain  provisions that
trigger  guarantee  obligations  based on downgrade  events to below  investment
grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or
payments and offset  provisions  in the event of a default.  The recent  outlook
changes  from S&P and Moody's do not trigger any  guarantee  obligations.  As of
December 31, 2004,  if the guarantee  obligations  were  triggered,  the maximum
amount of liquidity  requirements to support ongoing  operations within a 90-day
period,  associated with guarantees for the Company's nonregulated portfolio and
power supply agreements was $450 million. The Company would meet this obligation
with cash or letters of credit.

As of December  31, 2004,  Progress  Energy had  guarantees  issued on behalf of
third  parties of  approximately  $10 million.  See Note 23D for a discussion of
guarantees in accordance with FIN No. 45.

Market Risk and Derivatives

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.  See Note 18 and Item 7A,
"Quantitative  and Qualitative  Disclosures About Market Risk," for a discussion
of market risk and derivatives.

Contractual Obligations

The Company is party to numerous  contracts  and  arrangements  obligating it to
make  cash  payments  in  future  years.   These  contracts   include  financial
arrangements  such as debt  agreements and leases,  as well as contracts for the
purchase of goods and  services.  Amounts in the  following  table are estimated
based upon contractual  terms and actual amounts will likely differ from amounts
presented  below.  Further  disclosure   regarding  the  Company's   contractual
obligations  is  included  in the  respective  notes.  The  Company  takes  into
consideration  the future  commitments  when  assessing its liquidity and future
financing needs. The following table reflects Progress Energy's contractual cash
obligations  and other  commercial  commitments  at December  31,  2004,  in the
respective periods in which they are due:

                                       68
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------------------------------
                                                              Less than 1                            More than 5
(in millions)                                      Total         year       1-3 years   3-5 years       years
-------------------------------------------------------------------------------------------------------------------
Long-term debt (a) (See Note 13)                  $  9,942       $   349      $ 1,637    $ 1,387        $  6,569
Interest payments on long-term debt and
   interest rate derivatives (b)                     3,064           301          489        423           1,851
Capital lease obligations (See Note 23C)                50             4            8          7              31
Operating leases (See Note 23C)                        597            66          113        112             306
Fuel and purchased power (c) (See Note 23A)         13,010         2,692        3,088      1,346           5,884
Other purchase obligations (See Note 23A)              633           151          134         80             268
NC Clean Air capital
   commitments (See Note 22)                           764           170          297        143             154
Other commitments (d)(e)                               243            42           70         26             105
-------------------------------------------------------------------------------------------------------------------
Total                                             $ 28,303       $ 3,775      $ 5,836    $ 3,524        $ 15,168
-------------------------------------------------------------------------------------------------------------------
</TABLE>

a.   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 debt to total  capitalization
     leverage by one to two  percentage  points over the next few years  through
     selected  asset sales,  free cash flow and  increased  equity from retained
     earnings and ongoing equity issuances.
b.   Interest payments on long-term debt and interest rate derivatives are based
     on the interest  rate  effective  as of December  31,  2004,  and the LIBOR
     forward curve as of December 31, 2004, respectively.
c.   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.
d.   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.
e.   The Company has certain future  commitments  related to four synthetic fuel
     facilities  purchased  that  provide for  contingent  payments  (royalties)
     through 2007 (See Note 23B).

OTHER MATTERS

Synthetic Fuels Tax Credits

The  Company  has  substantial  operations  associated  with the  production  of
coal-based  synthetic fuels. The production and sale of these products qualifies
for federal  income tax credits so long as certain  requirements  are satisfied.
These operations are subject to numerous risks.

Although the Company  believes that it operates its synthetic fuel facilities in
compliance with applicable legal requirements for claiming the credits, its four
Earthco  facilities are under audit by the IRS. IRS field auditors have taken an
adverse  position  with respect to the  Company's  compliance  with one of these
legal  requirements,  and if the Company  fails to prevail  with respect to this
position,  it could incur significant liability and/or lose the ability to claim
the  benefit  of tax  credits  carried  forward  or  generated  in  the  future.
Similarly,  the Financial  Accounting  Standards  Board may issue new accounting
rules that would require that uncertain tax benefits  (such as those  associated
with the Earthco  plants) be probable of being sustained in order to be recorded
on the financial  statements;  if adopted,  this provision could have an adverse
financial impact on the Company.

The Company's  ability to utilize tax credits is dependent on having  sufficient
tax  liability.   Any  conditions  that  negatively  impact  the  Company's  tax
liability, such as weather, could also diminish the Company's ability to utilize
credits,  including  those  previously  generated,  and  the  synthetic  fuel is
generally not economical to produce absent the credits. Finally, the tax credits
associated with synthetic fuels may be phased out if market prices for crude oil
exceed certain prices.

The Company's  synthetic fuel operations and related risks are described in more
detail in Note 23E and in the "Risk Factors" section.

                                       69
<PAGE>

Hurricane Costs

Hurricanes Charley,  Frances, Ivan and Jeanne struck significant portions of the
Company's service  territories  during the third quarter of 2004,  significantly
impacting PEF's territory. As of December 31, 2004, restoration of the Company's
systems  from  hurricane-related  damage  was  estimated  at $398  million.  PEC
incurred  restoration costs of $13 million,  of which $12 million was charged to
operation  and  maintenance  expense  and $1  million  was  charged  to  capital
expenditures.  PEF had  estimated  total  costs of $385  million,  of which  $47
million was charged to capital expenditures, and $338 million was charged to the
storm damage reserve pursuant to a regulatory order.

In  accordance  with a regulatory  order,  PEF accrues $6 million  annually to a
storm damage reserve and is allowed to defer losses in excess of the accumulated
reserve for major  storms.  Under the order,  the storm  reserve is charged with
operation and maintenance expenses related to storm restoration and with capital
expenditures  related to storm  restoration  that are in excess of  expenditures
assuming normal operating  conditions.  As of December 31, 2004, $291 million of
hurricane  restoration costs in excess of the previously  recorded storm reserve
of $47  million  had been  classified  as a  regulatory  asset  recognizing  the
probable  recoverability  of these  costs.  On  November  2,  2004,  PEF filed a
petition with the FPSC to recover $252 million of storm costs plus interest from
retail  ratepayers  over a two-year  period.  Storm reserve costs of $13 million
were attributable to wholesale customers. The Company has received approval from
the FERC to amortize  these costs  consistent  with  recovery of such amounts in
wholesale rates. PEF continues to review the restoration cost invoices received.
Given that not all invoices have been received as of December 31, 2004, PEF will
update its petition  with the FPSC upon receipt and audit of all actual  charges
incurred. Hearings on PEF's petition for recovery of $252 million of storm costs
filed with the FPSC are scheduled to begin on March 30, 2005.

On November  17,  2004,  the  Citizens  of the State of Florida,  by and through
Harold McLean,  Public  Counsel,  and the Florida  Industrial  Power Users Group
(FIPUG), (collectively, Joint Movants), filed a Motion to Dismiss PEF's petition
to recover the $252 million in storm costs.  On November 24, 2004, PEF responded
in  opposition  to the motion,  which was also the FPSC staff's  position in its
recommendation  to the Commission on December 21, 2004,  that it should deny the
Motion to Dismiss.  On January 4, 2005, the Commission ruled in favor of PEF and
denied the Joint Movant's Motion to Dismiss.

PEF's  January  2005 notice to the FPSC of its intent to file for an increase in
its base rates effective January 1, 2006,  anticipates the need to replenish the
depleted storm reserve balance and adjust the annual $6 million accrual in light
of recent  storm  history to restore  the  reserve to an  adequate  level over a
reasonable time period.

PEC does not have an  ongoing  regulatory  mechanism  to  recover  storm  costs;
therefore,  hurricane  restoration  costs  recorded in the third quarter of 2004
were charged to  operations  and  maintenance  expenses or capital  expenditures
based on the nature of the work performed.  In connection with other storms, PEC
has  previously  sought and received  permission  from the NCUC and the SCPSC to
defer storm expenses and amortize them over a five-year period. PEC did not seek
deferral of 2004 storm costs from the NCUC (See Note 8B).

Regulatory Environment and Matters

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.

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.

The retail rate matters affected by the regulatory  authorities are discussed in
detail in Notes 8B and 8C.  This  discussion  identifies  specific  retail  rate
matters,  the status of the issues and the  associated  effects to the Company's
consolidated financial statements.

                                       70
<PAGE>

The regulatory  authorities continue to evaluate issues related to the formation
of Regional Transmission  Organizations.  The Company cannot predict the outcome
of  these  matters  on  the  Company's  earnings,  revenues  or  prices  or  the
investments in GridSouth and GridFlorida (See Note 8D).

A FERC  order  issued  in  November  2001  on  certain  unaffiliated  utilities'
triennial  market-based  wholesale  power rate  authorization  updates  required
certain  mitigation  actions  that  those  utilities  would  need  to  take  for
sales/purchases  within their control areas and required those utilities to post
information  on their Web sites  regarding  their power  systems'  status.  As a
result of a request for rehearing  filed by certain  market  participants,  FERC
issued an order delaying the effective date of the mitigation plan until after a
planned technical  conference on market power  determination.  In December 2003,
the FERC  issued a staff  paper  discussing  alternatives  and held a  technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale  electricity at market-based  rates. In the
first order,  the FERC adopted two new interim  screens for assessing  potential
generation  market power of applicants  for wholesale  market-based  rates,  and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens.  In July 2004, the FERC
issued an order on rehearing  affirming its  conclusions in the April order.  In
the second order, the FERC initiated a rulemaking to consider whether the FERC's
current  methodology for determining  whether a public utility should be allowed
to sell wholesale  electricity at  market-based  rates should be modified in any
way.  PEF does not have  market-based  rate  authority  for  wholesale  sales in
peninsular  Florida.  Given the difficulty  PEC believes it would  experience in
passing one of the interim  screens,  on August 12, 2004,  PEC notified the FERC
that it would  revise  its  Market-based  Rate  tariff to  restrict  it to sales
outside  PEC's  control area and file a new  cost-based  tariff for sales within
PEC's  control  area  that  incorporates  the  FERC's  default  cost-based  rate
methodologies for sales of one year or less. PEC anticipates  making this filing
in the first quarter of 2005.  Although the Company  cannot predict the ultimate
outcome of these  changes,  the  Company  does not  anticipate  that the current
operations  of PEC or PEF would be  impacted  materially  if they were unable to
sell power at market-based rates in their respective control areas.

Franchise Litigation

Three cities,  with a total of approximately  18,000 customers,  have litigation
pending  against  PEF in  various  circuit  courts  in  Florida.  As  previously
reported,  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.  The circuit courts
in those cases 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 the
cities to determine the value of PEF's electric  distribution  system within the
cities through arbitration.

Arbitration in one of the cases (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 (the City) at  approximately  $32 million,  not  including  separation  and
reintegration 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, which,  according to the award, decrease over time. 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. While the City has not yet definitively decided whether it
will acquire the system, on April 26, 2004, the City Commission voted to proceed
with the acquisition.  The City sought and received  wholesale power supply bids
and on June 24, 2004,  executed a wholesale  power supply  contract with PEF. On
May 12, 2004, the City  solicited bids to operate and maintain the  distribution
system and awarded a contract in January 2005.  The City has indicated  that its
goal is to begin  electric  operations in June 2005.  On February 10, 2005,  PEF
filed a petition  with the  Florida  Public  Service  Commission  to relieve the
Company of its statutory obligation to serve customers in Winter Park on June 1,
2005, or at such time when the City is able to provide retail  service.  At this
time, whether and when there will be further  proceedings  regarding the City of
Winter Park cannot be determined.

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 $2 million in stranded costs.

                                       71
<PAGE>

The Town has not yet  decided  whether it will  attempt to acquire  the  system;
however,  on January 18, 2005,  it issued a request for  proposals for wholesale
power supply and to operate and maintain the distribution system.  Proposals are
due in early March 2005. In February 2005, the Town Commission also voted to put
the issue of whether to acquire the distribution system to a voter referendum on
or before October 2, 2005. At this time,  whether and when there will be further
proceedings regarding the Town of Belleair cannot be determined.

Arbitration  in the remaining  city's  litigation  (the  1,500-customer  City of
Edgewood) has not yet been scheduled.  On February 17, 2005, the parties filed a
joint motion to stay the litigation for a 90-day period during which the parties
will discuss potential settlement.

A  fourth  city  (the   7,000-customer   City  of  Maitland)  is   contemplating
municipalization  and has  indicated its intent to proceed with  arbitration  to
determine  the value of PEF's  electric  distribution  system  within  the City.
Maitland's  franchise  expires in August  2005.  At this time,  whether and when
there will be  further  proceedings  regarding  the City of  Maitland  cannot be
determined.

As  part  of  the  above  litigation,  two  appellate  courts  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 filed an appeal  with the  Florida  Supreme  Court to resolve  the  conflict
between the two  appellate  courts.  On October  28,  2004,  the Court  issued a
decision  holding  that PEF must  collect  from its  customers  and remit to the
cities  franchise  fees during the interim  period when the city  exercises  its
purchase  option or executes a new franchise.  The Court's  decision  should not
have a material impact on the Company.

Legal

The Company is subject to federal, state and local legislation and court orders.
These matters are discussed in detail in Note 23E.  This  discussion  identifies
specific  issues,  the  status of the  issues,  accruals  associated  with issue
resolutions and the associated exposures to the Company.

Nuclear

Nuclear   generating   units  are   regulated  by  the  NRC.  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 (See Notes 6 and 23E).

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 22. This
discussion  identifies specific  environmental issues, the status of the issues,
accruals  associated with issue resolutions and the associated  exposures to the
Company.  The Company  accrues  costs to the extent they are probable and can be
reasonably  estimated.  It is reasonably possible that additional losses,  which
could be material, may be incurred in the future.

New Accounting Standards

See Note 2 for a discussion of the impact of new accounting standards.

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.

                                       72
<PAGE>

RESULTS OF OPERATIONS

The results of operations for the PEC  consolidated for the years ended December
31 are  summarized  in the table below.  The results of  operations  for the PEC
Electric segment are identical in all material respects 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 relate to the nonelectric operations, as summarized below:

--------------------------------------------------------------------------------
(in millions)                                         2004       2003      2002
--------------------------------------------------------------------------------
PEC Electric income before cumulative effect         $ 464      $ 515     $ 513
Caronet net income (loss)                                -          5       (79)
Other nonelectric net loss                              (6)       (18)       (6)
Cumulative effect of accounting change                   -        (23)        -
--------------------------------------------------------------------------------
Earnings for common stock                            $ 458      $ 479     $ 428
--------------------------------------------------------------------------------

Caronet's results of operations for 2002 includes  after-tax  impairments of $87
million for other-than-temporary  declines in the value of the assets of Caronet
and  Caronet's  investment  in  Interpath  (See Note 7A to the PEC  Consolidated
Financial Statements).  The stock of Caronet was sold in December 2003 (See Note
1A to the PEC Consolidated Financial Statements).

The other  nonelectric  subsidiaries  of PEC  contributed  segment  losses of $6
million  and $18  million  for the  years  ended  December  31,  2004 and  2003,
respectively.   The  Other  nonelectric  results  for  2003  include  investment
impairments of $6 million after-tax on the Affordable  Housing portfolio held by
the  nonutility  subsidiaries  of PEC.  (See  Note  7B to the  PEC  Consolidated
Financial  Statements.)  A reduction  in  investment  losses  accounted  for the
remaining favorability compared to prior year.

In 2003,  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 due primarily to the new FASB guidance
related to the  accounting  for the purchase power contract with Broad River LLC
(See Note 13A to the PEC Consolidated Financial Statements).

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

PEC has primarily used a combination of unsecured  notes,  first mortgage bonds,
pollution  control  bonds,  commercial  paper  facilities  and revolving  credit
agreements for liquidity needs in excess of cash provided by operations.

During 2004,  PEC  extended its $165 million  364-day line of credit to July 27,
2005 and PEC's three-year $285 million line of credit expires July 31, 2005.

As discussed  above in the Progress  Energy  "Overview,"  in October  2004,  S&P
reduced  the  short-term  debt rating of PEC to A-3 from A-2. As a result of the
impact of these actions on PEC's ability to access the commercial paper markets,
PEC has borrowed on its revolving  credit  agreements.  As of December 31, 2004,
the total amount of outstanding  borrowings on PEC's revolving credit agreements
was $90  million.  The borrowed  funds were used to pay off maturing  commercial
paper and for other cash needs.

The changes by S&P do not trigger any debt or guarantee collateral requirements,
nor do they have any material  impact on the overall  liquidity of PEC. To date,
PEC's access to the commercial paper markets has not been materially impacted by
the rating agencies' actions.  However,  the changes have increased the interest
rate incurred on its short-term borrowings by 0.25% to 0.875%.

                                       73
<PAGE>

PEC expects to have sufficient  resources to meet its future  obligations either
through internally  generated funds, its short term-term borrowing facilities or
through the issuance of long-term debt.

HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002

In 2004, cash provided by operating  activities decreased when compared to 2003.
The decrease was caused primarily by a $89 million  under-recovery of fuel costs
and a $76 million decrease in payables to affiliates.  In 2003, cash provided by
operating  activities  increased  when compared to 2002,  largely as a result of
improved operating results.

In 2004, cash used in investing activities decreased  approximately $257 million
in 2004 when compared with 2003.  The decrease is primarily to net proceeds from
short-term  investments in 2004, compared to net purchases in 2003. The decrease
is partially offset by an increase in capital expenditures, primarily related to
increased spending for NC Clean Air legislation, and an increase in nuclear fuel
additions.

See the discussion  above for Progress Energy under  "Financing  Activities" for
information regarding PEC's financing activities.

FUTURE LIQUIDITY AND CAPITAL RESOURCES

PEC's estimated  capital  requirements for 2005, 2006 and 2007 are $650 million,
$670 million and $680 million,  respectively, and primarily reflect construction
expenditures to support  customer growth,  add regulated  generation and upgrade
existing  facilities.  See Note 6E to the PEC Consolidated  Financial Statements
for a  discussion  of expected  impacts on future  capital  expenditures  due to
changes in  capitalization  practice  for PEC.  PEC  expects to fund its capital
requirements  primarily through internally generated funds. In addition, PEC has
$450 million in credit facilities that support 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.  PEC plans
to enter into a new five-year line of credit in 2005 that will replace these two
expiring facilities.

See Note 9 to the PEC Consolidated Financial Statements for information on PEC's
available credit facilities at December 31, 2004.

OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS

PEC's off-balance sheet  arrangements and contractual  obligations are described
below.

Market Risk and Derivatives

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.  See Note 13 and Item 7A,
"Quantitative  and Qualitative  Disclosures About Market Risk," for a discussion
of market risk and derivatives.

Contractual Obligations

PEC is party to numerous  contracts and arrangements  obligating it to make cash
payments in future years. These contracts include financial arrangements such as
debt  agreements and leases,  as well as contracts for the purchase of goods and
services.  Amounts in the following table are estimated  based upon  contractual
terms and will likely differ from amounts  presented below.  Further  disclosure
regarding PEC's  contractual  obligations is included in the respective notes to
the PEC Consolidated  Financial  Statements.  PEC takes into  consideration  the
future  commitments when assessing its liquidity and future financing needs. The
following table reflects  Progress  Energy's  contractual  cash  obligations and
other commercial  commitments at December 31, 2004, in the respective periods in
which they are due:

                                       74
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
--------------------------------------------------------------------------------------------------------
                                                             Less than                       More than
(in millions)                                       Total     1 year    1-3 years 3-5 years    5 years
--------------------------------------------------------------------------------------------------------
Long-term debt (a) (See Note 9)                     $ 3,069     $   300   $   200   $   700     $ 1,869
Interest payments on long-term debt
   and interest rate derivatives (b)                  1,342         150       285       207         700
Capital lease obligations (See Note 18B)                 35           2         4         4          25
Operating leases (See Note 18B)                         187          28        37        25          97
Fuel and purchased power (c) (See Note 18A)           3,427         786     1,098       431       1,112
Other purchase obligations (See Note 18A)                25          12         -         -          13
North Carolina clean air capital commitments
  (See Note  17)                                        764         170       297       143         154
Other commitments (d)                                   131           -         -        26         105
--------------------------------------------------------------------------------------------------------
Total                                               $ 8,980     $ 1,448   $ 1,921   $ 1,536     $ 4,075
--------------------------------------------------------------------------------------------------------
</TABLE>

a.   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 debt to total  capitalization
     leverage by one to two  percentage  points over the next few years  through
     selected  asset sales,  free cash flow and  increased  equity from retained
     earnings and ongoing equity issuances.
b.   Interest payments on long-term debt and interest rate derivatives are based
     on the interest  rate  effective  as of December  31,  2004,  and the LIBOR
     forward curve as of December 31, 2004, respectively.
c.   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.
d.   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.


                                       75
<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, 2004 and 2003,  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 for 2005-2009 and
thereafter and the fair value of the related hedges.  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
Note 18 for more information on interest rate derivatives.

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------------------------------------------
December 31, 2004                                                                                        Fair Value
                                                                                                        December 31,
(dollars in millions)              2005     2006      2007    2008      2009     Thereafter   Total          2004
-----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt          $ 349    $ 908    $ 674   $ 827      $ 400    $ 5,399     $ 8,557       $ 9,454
Average interest rate              7.38%    6.78%    6.41%   6.27%      5.95%      6.55%       6.54%
Variable rate long-term debt         -      $  55      -        -       $ 160    $   861     $ 1,076       $ 1,077
Average interest rate                -      2.95%      -        -       3.19%      1.70%       1.99%
Debt to affiliated trust(a)          -        -        -        -        -       $   309     $   309       $   312
Interest rate                        -        -        -        -        -         7.10%       7.10%
Interest rate derivatives:
    Pay variable /receive
    fixed                            -        -        -     $(100)      -       $   (50)    $  (150)      $     3
      Average pay rate               -        -        -       (b)       -          (b)        (b)
      Average receive rate           -        -        -     4.10%       -         4.65%       4.28%
    Interest rate forward
       contracts                   $ 200      -        -        -        -       $   131     $   331       $    (2)
      Average pay rate             3.07%      -        -        -        -         4.90%       3.79%
      Average receive rate          (c)       -        -        -        -          (b)       (b)(c)

-----------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  FPC Capital I - Quarterly Income Preferred Securities.
(b)  Rate is 3-month LIBOR, which was 2.56% at December 31, 2004.
(c)  Rate is 1-month LIBOR, which was 2.40% at December 31, 2004.

                                       76
<PAGE>

<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(a)           -        -         -       -         -      $   309     $   309      $    313
Interest rate                         -        -         -       -         -        7.10%       7.10%
Interest rate derivatives:
    Pay variable/receive
       fixed                          -        -      $(300)  $ (350)   $ (200)       -       $  (850)     $     (4)
      Average pay rate                                  (b)      (b)     (b)                    (b)
      Average receive rate                             2.75%   3.35%     2.93%                  3.04%
    Payer swaptions                   -        -         -       -      $  400        -       $   400      $      5
      Average pay rate                                                   4.75%
      Average receive rate                                               (b)
    Interest rate collars(c)       $  65       -         -    $  130       -          -       $   195      $    (11)
      Cap rate                     6.00%                       6.50%
      Floor rate                   4.13%                       5.13%
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

(a)  FPC Capital I - Quarterly Income Preferred Securities.
(b)  Rate is 3-month LIBOR, which was 1.15% at December 31, 2003.
(c)  Notional  amount is varying with a maximum of $195  million,  decreasing to
     $130 million after December 2004.

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 $1.044  billion  and $938  million at
December  31, 2004 and 2003,  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 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, 2004 and 2003, the fair value of these CVOs was $13 million and $23
million,  respectively.  A  hypothetical  10% decrease in the December 31, 2004,
market  price  would  result in a $1 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,  coal,  fuel oil,  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.  Each state  commission  allows  electric
utilities  to recover  certain of these  costs  through  various  cost  recovery
clauses to the extent the respective  commission  determines that such costs are
prudent.  Therefore, while there may be a delay in the timing between when these
costs are  incurred  and when these  costs are  recovered  from the  ratepayers,
changes  from year to year have no  material  impact on  operating  results.  In
addition,   many  of  the  Company's   long-term  power  sales  contracts  shift
substantially all fuel responsibility to the purchaser. The Company also has oil
price risk exposure related to synfuel tax credits. See discussion in Note 23E.

                                       77
<PAGE>

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 activity using natural gas and electricity financial instruments.

In 2004,  PEF entered  into  derivative  instruments  related to its exposure to
price fluctuations on fuel oil purchases.  At December 31, 2004, the fair values
of these  instruments  were a $2 million  long-term  derivative  asset  position
included  in other  assets  and  deferred  debits  and a $5  million  short-term
derivative  liability  position  included in other  current  liabilities.  These
instruments  receive  regulatory  accounting  treatment.  Gains are  recorded in
regulatory liabilities and losses are recorded in regulatory assets.

Refer  to  Note 18 for  additional  information  with  regard  to the  Company's
commodity contracts and use of derivative financial instruments.

The Company performs sensitivity analyses to estimate its exposure to the market
risk of its  commodity  positions.  A  hypothetical  10% increase or decrease in
quoted  market  prices in the near term on the  Company's  derivative  commodity
instruments  would not have had a material effect on the Company's  consolidated
financial position, results of operations or cash flows as of December 31, 2004.

PEC

PEC has certain market risks inherent in its financial instruments,  which arise
from transactions  entered into in the normal course of business.  PEC's primary
exposures  are changes in interest  rates,  with respect to  long-term  debt and
commercial paper, and fluctuations in the return on marketable securities,  with
respect to its nuclear decommissioning trust funds.

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

Interest Rate Risk

The  following  tables  provide  information  at about PEC's  interest rate risk
sensitive instruments:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------------------------------
December 31, 2004                                                                                            Fair Value
                                                                                                            December 31,
(dollars in millions)                2005    2006       2007    2008      2009    Thereafter     Total          2004
---------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt           $ 300       -      $ 200   $ 300     $ 400     $ 1,249      $ 2,449       $ 2,686
Average interest rate                7.50%      -      6.80%   6.65%     5.95%       6.13%        6.38%
Variable rate long-term debt           -        -         -        -        -      $   620      $   620       $   621
Average interest rate                  -        -         -        -        -        1.71%        1.71%
Interest rate forward contracts        -        -         -        -        -      $   131      $   131       $    (2)
      Average pay rate                                                               4.90%        4.90%
      Average receive rate                                                             (a)         (a)
---------------------------------------------------------------------------------------------------------------------------

(a)  Rate is 3-month LIBOR, which was 2.56% at December 31, 2004

--------------------------------------------------------------------------------------------------------------------------
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%
--------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                       78
<PAGE>

Commodity Price Risk

PEC is exposed to the  effects  of market  fluctuations  in the price of natural
gas, coal, fuel oil, 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.  Each
state  commission  allows  electric  utilities to recover certain of these costs
through  various cost recovery  clauses to the extent the respective  commission
determines that such costs are prudent. Therefore, while there may be a delay in
the  timing  between  when these  costs are  incurred  and when these  costs are
recovered from the ratepayers, changes from year to year have no material impact
on operating results.  PEC may engage in limited economic hedging activity using
natural gas and electricity financial  instruments.  Refer to Note 13 to the PEC
Consolidated  Financial  Statements  for additional  information  with regard to
PEC's commodity contracts and use of derivative financial instruments.

PEC performs sensitivity analyses to estimate its exposure to the market risk of
its  commodity  positions.  A  hypothetical  10%  increase or decrease in quoted
market prices in the near term on its derivative commodity instruments would not
have had a material effect on PEC's consolidated financial position,  results of
operations or cash flows as of December 31, 2004.

                                       79
<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.
Reports of Independent Registered Public Accounting Firm

Consolidated Financial Statements - Progress Energy, Inc.:

Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002                     83
Consolidated Balance Sheets at December 31, 2004 and 2003                                                  84-85
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002                 86
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2004,
   2003 and 2002                                                                                           87
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
   2003 and 2002                                                                                           87

Notes to the Consolidated Financial Statements

   Note 1  - Organization and Summary of Significant Accounting Policies                                   88
   Note 2  - New Accounting Standards                                                                      94
   Note 3  - Hurricane Related Costs                                                                       95
   Note 4  - Divestitures                                                                                  95
   Note 5  - Acquisitions and Business Combinations                                                        97
   Note 6  - Property, Plant and Equipment                                                                 99
   Note 7  - Current Assets                                                                               103
   Note 8  - Regulatory Matters                                                                           103
   Note 9  - Goodwill and Other Intangible Assets                                                         108
   Note 10 - Impairments of Long-Lived Assets and Investments                                             109
   Note 11 - Equity                                                                                       109
   Note 12 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption                        113
   Note 13 - Debt and Credit Facilities                                                                   113
   Note 14 - Fair Value of Financial Instruments                                                          117
   Note 15 - Income Taxes                                                                                 117
   Note 16 - Contingent Value Obligations                                                                 119
   Note 17 - Benefit Plans                                                                                119
   Note 18 - Risk Management Activities and Derivatives Transactions                                      123
   Note 19 - Related Party Transactions                                                                   125
   Note 20 - Financial Information by Business Segment                                                    126
   Note 21 - Other Income and Other Expense                                                               128
   Note 22 - Environmental Matters                                                                        128
   Note 23 - Commitments and Contingencies                                                                133
   Note 24 - Subsequent Events                                                                            141
   Note 25 - Consolidated Quarterly Financial Data (Unaudited)                                            142
</TABLE>

                                       80
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
Report of Independent Registered Public Accounting Firm

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

Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002                    144
Consolidated Balance Sheets at December 31, 2004 and 2003                                                 145
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003
   and 2002                                                                                               146
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2004, 2003
   and 2002                                                                                               147
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
    2003 and 2002                                                                                         147

Notes to the Consolidated Financial Statements
   Note 1  - Organization and Summary of Significant Accounting Policies                                  148
   Note 2  - New Accounting Standards                                                                     153
   Note 3  - Hurricane Related Costs                                                                      154
   Note 4  - Property, Plant and Equipment                                                                154
   Note 5  - Current Assets                                                                               157
   Note 6  - Regulatory Matters                                                                           157
   Note 7  - Impairments of Long-Lived Assets and Investments                                             160
   Note 8  - Equity                                                                                       160
   Note 9  - Debt and Credit Facilities                                                                   162
   Note 10 - Fair Value of Financial Instruments                                                          164
   Note 11 - Income Taxes                                                                                 164
   Note 12 - Benefit Plans                                                                                166
   Note 13 - Risk Management Activities and Derivatives Transactions                                      169
   Note 14 - Related Party Transactions                                                                   170
   Note 15 - Financial Information by Business Segment                                                    171
   Note 16 - Other Income and Other Expense                                                               172
   Note 17 - Environmental Matters                                                                        172
   Note 18 - Commitments and Contingencies                                                                175
   Note 19 - Subsequent Event                                                                             179
   Note 20 - Consolidated Quarterly Financial Data (Unaudited)                                            179

Report of Independent Registered Public Accounting Firm on Consolidated Financial
           Statement Schedule - Progress Energy, Inc.                                                     180
           Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.                           181

Consolidated Financial Statement Schedules for the Years Ended December 31, 2004, 2003 and 2002:

           II-Valuation and Qualifying Accounts - Progress Energy, Inc.                                   182
           II-Valuation and Qualifying Accounts - Carolina Power & Light Company
                  d/b/a Progress Energy Carolinas, Inc.                                                   183
</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 Notes to the Consolidated Financial Statements.

                                       81
<PAGE>

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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  (the Company) at December 31, 2004 and 2003, and the
related  consolidated  statements of income,  comprehensive  income,  changes in
common  stock  equity,  and cash flows for each of the three years in the period
ended December 31, 2004. 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 the standards of the Public  Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

In our opinion,  such consolidated  financial  statements present fairly, in all
material  respects,  the financial  position of the Company at December 31, 2004
and 2003,  and the results of their  operations and their cash flows for each of
the three years in the period  ended  December  31,  2004,  in  conformity  with
accounting principles generally accepted in the United States of America.

As discussed in Notes 1D and 18A to the consolidated  financial  statements,  in
2003, the Company adopted  Statement of Financial  Accounting  Standards No. 143
and Derivatives Implementation Group Issue C20.

We have also  audited,  in accordance  with the standards of the Public  Company
Accounting  Oversight Board (United States),  the effectiveness of the Company's
internal control over financial  reporting as of December 31, 2004, based on the
criteria  established in Internal  Control--Integrated  Framework  issued by the
Committee of Sponsoring Organizations of the Treadway Commission, and our report
dated March 7, 2005, expressed an unqualified opinion on management's assessment
of the effectiveness of the Company's internal control over financial  reporting
and an  unqualified  opinion  on the  effectiveness  of the  Company's  internal
control over financial reporting.

Deloitte & Touche LLP

                                       82
<PAGE>

Raleigh, North Carolina
March 7, 2005

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
-----------------------------------------------------------------------------------------------------
(in millions except per share data)
Years ended December 31                                               2004         2003         2002
-----------------------------------------------------------------------------------------------------
Operating Revenues
   Electric                                                        $ 7,153      $ 6,741      $ 6,601
   Diversified business                                              2,619        2,000        1,490
-----------------------------------------------------------------------------------------------------
      Total Operating Revenues                                       9,772        8,741        8,091
-----------------------------------------------------------------------------------------------------
Operating Expenses
Utility
   Fuel used in electric generation                                  2,011        1,695        1,586
   Purchased power                                                     868          862          862
   Operation and maintenance                                         1,475        1,421        1,390
   Depreciation and amortization                                       878          883          820
   Taxes other than on income                                          425          405          386
Diversified business
   Cost of sales                                                     2,288        1,748        1,410
   Depreciation and amortization                                       190          157          118
   Impairment of long-lived assets                                       -           17          364
   (Gain)/loss on the sale of assets                                  (57)            1            -
   Other                                                               218          195          145
-----------------------------------------------------------------------------------------------------
        Total Operating Expenses                                     8,296        7,384        7,081
-----------------------------------------------------------------------------------------------------
Operating Income                                                     1,476        1,357        1,010
-----------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                      14           11           15
   Impairment of investments                                             -          (21)         (25)
   Other, net                                                            8          (16)          27
-----------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                                    22          (26)          17
-----------------------------------------------------------------------------------------------------
Interest Charges
   Net interest charges                                                653          635          641
   Allowance for borrowed funds used during construction                (6)          (7)          (8)
-----------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                    647          628          633
-----------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax, Minority
   Interest, and Cumulative Effect of Changes in Accounting
   Principles                                                          851          703          394
Income Tax Expense (Benefit)                                           115        (111)        (158)
-----------------------------------------------------------------------------------------------------
Income from Continuing Operations before Minority Interest and
   Cumulative Effect of Changes in Accounting Principles               736          814          552
Minority Interest, Net of Tax                                          (17)           3            -
-----------------------------------------------------------------------------------------------------
Income from Continuing Operations Before Cumulative Effect of          753          811          552
   Change in Accounting Principles
Discontinued Operations, Net of Tax                                      6           (8)         (24)
Cumulative Effect of Changes in Accounting Principles,
   Net of Tax                                                            -          (21)           -
-----------------------------------------------------------------------------------------------------
Net Income                                                         $   759      $   782      $   528
-----------------------------------------------------------------------------------------------------
Average Common Shares Outstanding                                      242          237          217
-----------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
    Income from Continuing Operations before Cumulative Effect of
       Changes in Accounting Principles                            $  3.11      $  3.42      $  2.54
    Discontinued Operations, Net of Tax                                .02         (.03)        (.11)
    Cumulative Effect of Changes in Accounting Principles,
       Net of Tax                                                        -         (.09)           -
-----------------------------------------------------------------------------------------------------
    Net Income                                                     $  3.13      $  3.30      $  2.43
-----------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
    Income from Continuing Operations before Cumulative Effect of
       Changes in Accounting Principles                            $  3.10      $  3.40      $  2.53
    Discontinued Operations, Net of Tax                                .02         (.03)        (.11)
    Cumulative Effect of Changes in Accounting Principles,
       Net of Tax                                                        -         (.09)           -
-----------------------------------------------------------------------------------------------------
    Net Income                                                     $  3.12      $  3.28      $  2.42
-----------------------------------------------------------------------------------------------------
Dividends Declared per Common Share                                $  2.32      $  2.26      $  2.20
-----------------------------------------------------------------------------------------------------
</TABLE>

                                       83
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
See Notes to Consolidated Financial Statements.
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
----------------------------------------------------------------------------------------
(in millions)
December 31                                                      2004              2003
----------------------------------------------------------------------------------------
ASSETS
Utility Plant
  Utility plant in service                                  $  22,103        $   21,680
  Accumulated depreciation                                     (8,783)           (8,174)
----------------------------------------------------------------------------------------
        Utility plant in service, net                          13,320            13,506
  Held for future use                                              13                13
  Construction work in progress                                   799               559
  Nuclear fuel, net of amortization                               231               228
----------------------------------------------------------------------------------------
        Total Utility Plant, Net                               14,363            14,306
----------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                        62                47
  Short-term investments                                           82               226
  Receivables                                                   1,084             1,084
  Inventory                                                       982               907
  Deferred fuel cost                                              229               270
  Deferred income taxes                                           121                87
  Prepayments and other current assets                            175               268
----------------------------------------------------------------------------------------
        Total Current Assets                                    2,735             2,889
----------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                             1,064               598
  Nuclear decommissioning trust funds                           1,044               938
  Diversified business property, net                            2,010             2,095
  Miscellaneous other property and investments                    446               464
  Goodwill                                                      3,719             3,726
  Prepaid pension costs                                            42               462
  Intangibles, net                                                337               357
  Other assets and deferred debits                                233               258
----------------------------------------------------------------------------------------

        Total Deferred Debits and Other Assets                  8,895             8,898
----------------------------------------------------------------------------------------

           Total Assets                                     $  25,993        $   26,093
----------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
</TABLE>

                                       84
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (concluded)
------------------------------------------------------------------------------------------------------------
(in millions)
December 31                                                                          2004              2003
------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
------------------------------------------------------------------------------------------------------------
Common Stock Equity
  Common stock without par value, 500 million shares authorized,
      247 and 246 million shares issued and outstanding, respectively)          $   5,360        $    5,270
  Unearned restricted shares (1 and 1 million shares, respectively)                   (13)              (17)
  Unearned ESOP shares (3 and 4 million shares, respectively)                         (76)              (89)
  Accumulated other comprehensive loss                                               (164)              (50)
  Retained earnings                                                                 2,526             2,330
------------------------------------------------------------------------------------------------------------
        Total Common Stock Equity                                                   7,633             7,444
------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries - Not Subject to Mandatory
   Redemption                                                                          93                93
Minority Interest                                                                      36                30
Long-Term Debt, Affiliate                                                             270               270
Long-Term Debt, Net                                                                 9,251             9,664
------------------------------------------------------------------------------------------------------------
        Total Capitalization                                                       17,283            17,501
------------------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                                   349               868
  Accounts payable                                                                    742               635
  Interest accrued                                                                    219               228
  Dividends declared                                                                  145               140
  Short-term obligations                                                              684                 4
  Customer deposits                                                                   180               167
  Other current liabilities                                                           742               608
------------------------------------------------------------------------------------------------------------
        Total Current Liabilities                                                   3,061             2,650
------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Noncurrent income tax liabilities                                                   599               701
  Accumulated deferred investment tax credits                                         176               190
  Regulatory liabilities                                                            2,654             2,879
  Asset retirement obligations                                                      1,282             1,271
  Accrued pension and other benefits                                                  562               508
  Other liabilities and deferred credits                                              376               393
------------------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                                5,649             5,942
------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 22 and 23)
------------------------------------------------------------------------------------------------------------
           Total Capitalization and Liabilities                                 $  25,993        $   26,093
------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
</TABLE>

                                       85
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                                             2004            2003           2002
------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                       $   759         $   782        $   528
Adjustments to reconcile net income to net cash provided by operating
activities
      (Income) loss from discontinued operations                                      (6)              8             24
      Net (gain) loss on sale of operating assets                                    (57)              1              -
      Impairment of long-lived assets and investments                                  -              38            389
      Cumulative effect of changes in accounting principles                            -              21              -
      Depreciation and amortization                                                1,181           1,146          1,099
      Deferred income taxes                                                          (74)           (276)          (402)
      Investment tax credit                                                          (14)            (16)           (18)
      Deferred fuel credit                                                           (19)           (133)           (37)
      Cash provided (used) by changes in operating assets and liabilities
         Receivables                                                                 (35)           (158)           (50)
         Inventory                                                                  (108)              8            (66)
         Prepayments and other current assets                                        (18)             39            (24)
         Accounts payable                                                             33              37            100
         Other current liabilities                                                    82             121             56
         Regulatory assets and liabilities                                          (284)            (21)            46
         Other                                                                       167             127            (18)
------------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                 1,607           1,724          1,627
------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions                                                    (998)           (972)        (1,169)
Diversified business property additions                                             (236)           (584)          (558)
Nuclear fuel additions                                                              (101)           (117)           (81)
Proceeds from sales of subsidiaries and other investments                            366             579             43
Acquisition of businesses, net of cash                                                 -               -           (365)
Purchases of short-term investments                                               (2,108)         (2,813)        (2,962)
Proceeds from sales of short-term investments                                      2,252            2,587         2,962
Acquisition of intangibles                                                            (1)           (200)           (10)
Other                                                                                (46)            (26)           (61)
------------------------------------------------------------------------------------------------------------------------
          Net Cash Used in Investing Activities                                     (872)         (1,546)        (2,201)
------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net                                                         73             304            687
Issuance of long-term debt, net                                                      421           1,539          1,783
Net increase (decrease) in short-term indebtedness                                   680            (696)          (247)
Retirement of long-term debt                                                      (1,353)           (810)        (1,157)
Dividends paid on common stock                                                      (558)           (541)          (480)
Other                                                                                 17              12             (5)
------------------------------------------------------------------------------------------------------------------------
           Net Cash (Used in) Provided by Financing Activities                     (720)            (192)           581
------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                  15             (14)             7
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year                                        47              61             54
------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                         $    62         $    47        $    61
------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                 $   657         $   643        $   651
                            income taxes (net of refunds)                        $   189         $   177        $   219
------------------------------------------------------------------------------------------------------------------------
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
     5D).
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 5A).
------------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.


                                       86
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
---------------------------------------------------------------------------------------------------------------------------
                                                                                      Accumulated                  Total
                                             Common Stock      Unearned   Unearned       Other                     Common
                                             Outstanding      Restricted    ESOP     Comprehensive    Retained     Stock
(in millions except per share data)         Shares    Amount    Shares     Shares    Income (Loss)    Earnings     Equity
---------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2002                      219    $ 4,121    $  (14)    $ (114)         $  (32)     $ 2,043    $ 6,004
Net income                                                                                                 528        528
Other comprehensive loss                                                                     (206)                   (206)
                                                                                                                -----------
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
Other comprehensive income                                                                    188                     188
                                                                                                                -----------
Issuance of shares                              8        305                                                          305
Stock options exercised                                    4                                                            4
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
Net income                                                                                                 759        759
Other comprehensive loss                                                                     (114)                   (114)
                                                                                                                -----------
Issuance of shares                              1         62                                                           62
Stock options exercised                                   18                                                           18
Purchase of restricted stock                                        (7)                                                (7)
Restricted stock expense recognition                                 7                                                 7
Cancellation of restricted shares                         (4)        4                                                  -
Allocation of ESOP shares                                 14                   13                                      27
Dividends ($2.32 per share)                                                                               (563)      (563)
---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2004                    247    $ 5,360     $ (13)    $  (76)         $ (164)     $ 2,526    $ 7,633
---------------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                                             2004            2003           2002
------------------------------------------------------------------------------------------------------------------------
Net Income                                                                        $  759           $ 782         $ 528
Other Comprehensive Income (Loss)
      Changes in net unrealized losses on cash flow hedges (net of tax
       benefit of  $10, $7 and $18, respectively)                                    (18)            (12)          (28)
      Reclassification adjustment for amounts included in net income
       (net of tax expense of ($16), ($11) and ($10), respectively)                   26              19            16
      Reclassification of minimum pension liability to regulatory
       assets (net of tax expense of ($2))                                             4               -             -
      Minimum pension liability adjustment (net of tax benefit
       (expense) of $78, ($112) and $121, respectively)                             (130)            177          (192)
      Foreign currency translation and other                                           4               4            (2)
------------------------------------------------------------------------------------------------------------------------
             Other Comprehensive Income (Loss)                                    $ (114)          $ 188        $ (206)
------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                              $  645           $ 970        $  322
------------------------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

                                       87
<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.

     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 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.

     The consolidated  financial  statements of the Company and its subsidiaries
     include the  majority-owned  and  controlled  subsidiaries.  Noncontrolling
     interests in the  subsidiaries  along with the income or loss attributed to
     these interests are included in minority  interest in both the Consolidated
     Balance Sheets and in the Consolidated Statements of Income. The results of
     operations for minority  interest are reported on a net of tax basis if the
     underlying subsidiary is structured as a taxable entity.

     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. These investments are primarily in limited
     liability corporations and limited liability partnerships, and the earnings
     from these investments are recorded on a pre-tax basis (See Note 21). These
     equity method investments are included in miscellaneous  other property and
     investments in the  Consolidated  Balance Sheets.  At December 31, 2004 and
     2003,  the Company  has equity  method  investments  of  approximately  $27
     million and $36 million, respectively.

     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 as  available-for-sale  securities at fair value
     in accordance  with SFAS No. 115,  "Accounting  for Certain  Investments in
     Debt and Equity  Securities." These investments include investments held in
     trust funds,  pursuant to United States Nuclear Regulatory Commission (NRC)
     requirements,  to fund certain costs of decommissioning nuclear plants. The
     fair value of these  trust  funds was $1.044  billion  and $938  million at
     December 31, 2004 and 2003, respectively. The Company also actively invests
     available  cash  balances  in  various  financial   instruments,   such  as
     tax-exempt debt securities that have stated maturities of 20 years or more.
     These   instruments   provide  for  a  high  degree  of  liquidity  through
     arrangements  with banks that provide daily and weekly  liquidity and 7, 28
     and 35 day auctions that allow for the  redemption of the investment at its
     face  amount  plus  earned  income.  As the  Company  intends to sell these
     instruments  generally within 30 days from the balance sheet date, they are

                                       88
<PAGE>

     classified as current assets. At December 31, 2004 and 2003, the fair value
     of these investments was $82 million and $226 million, respectively.  Other
     investments  in debt and equity  securities  are included in  miscellaneous
     other  property and  investments in the  Consolidated  Balance  Sheets.  At
     December 31, 2004 and 2003, the fair value of these other  investments  was
     $39 million and $39 million, respectively.

     Other  investments  are  stated  principally  at cost.  These  cost  method
     investments are included in miscellaneous other property and investments in
     the  Consolidated  Balance  Sheets.  At December  31, 2004,  and 2003,  the
     Company has  approximately  $14 million and $14 million,  respectively,  of
     cost method investments.

     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 2003 and 2002 have been  reclassified to conform to the
     2004  presentation.   Reclassifications  include  the  reclassification  of
     instruments  used in  PEC's  cash  management  program  from  cash and cash
     equivalents to short-term investments of $226 million at December 31, 2003,
     in the Consolidated Balance Sheets. In the Consolidated  Statements of Cash
     Flow for each of the three years in the period  ended  December  31,  2004,
     total cash balances and total cash flows used in investing  activities were
     revised to reflect the  reclassification of these instruments from cash and
     cash equivalents to short-term investments.

     C. Consolidation of Variable Interest Entities

     The Company  consolidates  all voting interest  entities in which it owns a
     majority voting interest and all variable interest entities for which it is
     the primary  beneficiary in accordance  with FASB  Interpretation  No. 46R,
     "Consolidation of Variable Interest Entities - An Interpretation of ARB No.
     51"  (FIN  No.  46R).  The  Company  is  the  primary  beneficiary  of  and
     consolidates two limited  partnerships that qualify for federal  affordable
     housing and historic tax credits under  Section 42 of the Internal  Revenue
     Code (Code).  As of December 31, 2004, the total assets of the two entities
     were $37 million,  the majority of which are  collateral  for the entities'
     obligations  and are  included in other  current  assets and  miscellaneous
     other property and investments in the Consolidated Balance Sheets.

     The  Company  is the  primary  beneficiary  of a limited  partnership  that
     invests in 17 low-income housing  partnerships that qualify for federal and
     state tax credits.  The Company has  requested but has not received all the
     necessary  information to determine the primary  beneficiary of the limited
     partnership's  underlying 17 partnership  investments,  and has applied the
     information  scope  exception  in FIN  No.  46R,  paragraph  4(g) to the 17
     partnerships.  The  Company  has no  direct  exposure  to loss  from the 17
     partnerships; the Company's only exposure to loss is from its investment of
     less than $1 million in the consolidated limited  partnership.  The Company
     will  continue  its efforts to obtain the  necessary  information  to fully
     apply FIN No. 46R to the 17 partnerships.  The Company believes that if the
     limited  partnership is determined to be the primary  beneficiary of the 17
     partnerships,  the effect of consolidating the 17 partnerships would not be
     significant to the Company's Consolidated Balance Sheets.

     The Company has  variable  interests  in two power  plants  resulting  from
     long-term power purchase contracts. The Company has requested the necessary
     information  to  determine  if the  counterparties  are  variable  interest
     entities or to identify the primary  beneficiaries.  Both entities declined
     to provide the Company with the necessary  financial  information,  and the
     Company  has  applied  the  information  scope  exception  in FIN No.  46R,
     paragraph 4(g). The Company's only significant exposure to variability from
     these contracts  results from fluctuations in the market price of fuel used
     by the two entities'  plants to produce the power purchased by the Company.
     The Company is able to recover  these fuel costs  under PEC's fuel  clause.
     Total purchases from these  counterparties  were approximately $58 million,
     $53  million  and $53  million in 2004,  2003 and 2002,  respectively.  The
     Company will  continue its efforts to obtain the necessary  information  to
     fully  apply  FIN No.  46R to  these  contracts.  The  combined  generation
     capacity of the two  entities'  power plants is  approximately  880 MW. The
     Company believes that if it is determined to be the primary  beneficiary of
     these two entities,  the effect of consolidating  the entities would result
     in increases to total assets,  long-term  debt and other  liabilities,  but
     would have an  insignificant  or no impact on the  Company's  common  stock
     equity,  net earnings or cash flows.  However,  because the Company has not
     received  any  financial  information  from these two  counterparties,  the
     impact cannot be determined at this time.

     The Company also has interests in several other variable  interest entities
     for which the Company is not the primary  beneficiary.  These  arrangements
     include  investments  in  approximately  28 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,  2004,  that the  Company  could be required to record in its
     income statement as a result of these arrangements totals approximately $38
     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.

                                       89
<PAGE>

     D. 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."  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. These deferred fuel costs
     are  recognized  in  revenues  and fuel  expenses  as they are  billable to
     customers.

     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, 2004,  2003 and
     2002,  gross  receipts  tax,  franchise  taxes  and other  excise  taxes of
     approximately  $240 million,  $217 million and $212 million,  respectively,
     are  included  in utility  revenues  and taxes  other than on income in the
     Consolidated Statements of Income.

     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:

                                       90
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------------------
(in millions except per share data)                                      2004               2003          2002
---------------------------------------------------------------------------------------------------------------
Net income, as reported                                                $  759             $  782        $  528
Deduct: Total stock option expense determined under fair
     value method for all awards, net of related tax effects               10                 11             8
---------------------------------------------------------------------------------------------------------------
Pro forma net income                                                   $  749             $  771        $  520
---------------------------------------------------------------------------------------------------------------
Earnings per share
  Basic -   as reported                                                $ 3.13             $ 3.30        $ 2.43
  Basic -   pro forma                                                  $ 3.09             $ 3.25        $ 2.40
  Diluted - as reported                                                $ 3.12             $ 3.28        $ 2.42
  Diluted - pro forma                                                  $ 3.08             $ 3.24        $ 2.39
---------------------------------------------------------------------------------------------------------------
</TABLE>

     See Note 2 for a discussion of newly issued accounting  guidance related to
     stock-based compensation.

     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. Certain costs that would otherwise not be capitalized under GAAP are
     capitalized in accordance with regulatory  treatment.  The cost of renewals
     and  betterments is also  capitalized.  Maintenance and repairs of property
     (including  planned major  maintenance  activities),  and  replacements and
     renewals of items determined to be less than units of property, are charged
     to maintenance  expense as incurred,  with the exception of nuclear outages
     at PEF.  Pursuant to a  regulatory  order,  PEF accrues for nuclear  outage
     costs in advance of  scheduled  outages,  which occur every two years.  The
     cost of units of property replaced or retired,  less salvage, is charged to
     accumulated  depreciation.  Removal or disposal costs that do not represent
     SFAS No. 143, "Accounting for Asset Retirement Obligations," (SFAS No. 143)
     are charged to a regulatory liability.

     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 system 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.

     ASSET RETIREMENT OBLIGATIONS

     Effective January 1, 2003, the Company adopted the guidance in SFAS No. 143
     to account for legal obligations  associated with the retirement of certain
     tangible long-lived assets. The present value of retirement costs for which
     the Company has a legal  obligation  are  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.

     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 (See Note 8A). The
     North Carolina  Utilities  Commission (NCUC), the Public Service Commission
     of South Carolina (SCPSC) and the Florida Public Service  Commission (FPSC)
     issued orders to authorize  deferral of all prospective  effects related to
     SFAS No. 143 as a regulatory  asset or liability (See Note 8A).  Therefore,
     SFAS No. 143 has no impact on the income of the regulated entities.

     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 6A). Pursuant to their rate-setting  authority,
     the NCUC,  SCPSC and FPSC can also grant  approval to  accelerate or reduce
     depreciation and amortization of utility assets (See Note 8).

     Amortization   of  nuclear   fuel  costs  is  computed   primarily  on  the
     units-of-production   method.   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).

                                       91
<PAGE>

     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.

     INVENTORY

     The  Company  accounts  for  inventory  using  the   average-cost   method.
     Inventories are valued at the lower of average cost or market.

     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  Consolidated
     Balance Sheets as regulatory  assets and regulatory  liabilities  (See Note
     8A).

     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. For properties other than oil and gas properties, depreciation is
     computed  on  a  straight-line  basis  using  the  estimated  useful  lives
     disclosed  in Note 6B.  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 oil and gas
     properties.  Under the full-cost  method,  substantially all productive and
     nonproductive   costs   incurred  in  connection   with  the   acquisition,
     exploration and development of oil and gas reserves are capitalized.  These
     capitalized costs include the costs of all unproved properties and internal
     costs  directly  related to acquisition  and  exploration  activities.  The
     amortization base also includes the estimated future cost 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 on a country by country basis over the life of the Company's  proved
     reserves.   Accordingly,   all  property  acquisition,   exploration,   and
     development costs of proved oil and gas properties,  including the costs of
     abandoned properties, dry holes, geophysical costs and annual lease rentals
     are capitalized as incurred, including internal costs directly attributable
     to such  activities.  Related  interest  expense  incurred  during property
     development  activities  is  capitalized  as a cost of such  activity.  Net
     capitalized  costs of unproved property are reclassified as proved property
     and well costs when related proved reserves are found. Costs to operate and
     maintain wells and field equipment are expensed as incurred.  In accordance
     with Rule 4-10 of Regulation  S-X, sales or other  dispositions  of oil and
     gas properties are accounted for as adjustments to capitalized  costs, with
     no gain or loss recorded unless certain significance tests are met.

     GOODWILL AND INTANGIBLE ASSETS

     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. 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 are amortized over
     the terms of the debt issues. 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 (See Note 8A).

                                       92
<PAGE>

     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 as AMT credits to the
     extent they cannot be or have not been utilized in the annual  consolidated
     federal  income  tax  returns,  and are  included  in  income  tax  expense
     (benefit) in the Consolidated Statements of Income.

     DERIVATIVES

     The Company accounts for derivative instruments in accordance with 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,  unless the derivatives  meet the
     SFAS No.  133  criteria  for  normal  purchases  or  normal  sales  and are
     designated as such. The Company generally designates derivative instruments
     as normal  purchases or normal sales whenever the SFAS No. 133 criteria are
     met. If normal  purchase or normal sale  criteria  are not met, the Company
     will generally  designate the  derivative  instruments as cash flow or fair
     value  hedges if the related SFAS No. 133 hedge  criteria  are met.  During
     2003, the FASB  reconsidered an interpretation of SFAS No. 133. See Note 18
     for the effect of the interpretation and additional  information  regarding
     risk management activities and derivative transactions.

     ENVIRONMENTAL

     As  discussed  in Note 22, the Company  accrues  environmental  remediation
     liabilities   when  the   criteria   for  SFAS  No.  5,   "Accounting   for
     Contingencies" (SFAS No. 5), have been met. Environmental 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. Environmental expenditures that have future economic benefits are
     capitalized in accordance with the Company's asset capitalization policy.

     IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

     As  discussed  in Note  10,  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."

     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.

     Under the full-cost method of accounting for oil and gas 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. The ceiling test
     takes into  consideration  the prices of qualifying  cash flow hedges as of
     the balance sheet date. 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
     2004, 2003 or 2002.

                                       93
<PAGE>

     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 Staff  Accounting  Bulletin No.
     51, "Accounting for Sales of Stock by a Subsidiary."

2.   NEW ACCOUNTING STANDARDS

     FASB STAFF POSITION 106-2,  "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED
     TO THE MEDICARE  PRESCRIPTION  DRUG  IMPROVEMENT AND  MODERNIZATION  ACT OF
     2003"

     In  December  2003,  the  Medicare   Prescription  Drug,   Improvement  and
     Modernization Act of 2003 (Medicare Act) was signed into law. In accordance
     with guidance issued by the Financial  Accounting Standards Board (FASB) in
     FASB Staff Position 106-1,  "Accounting and Disclosure Requirements Related
     to the Medicare  Prescription  Drug  Improvement and  Modernization  Act of
     2003," (FASB Staff Position 106-1) the Company elected to defer  accounting
     for the effects of the  Medicare  Act due to  uncertainties  regarding  the
     effects of the  implementation  of the Medicare Act and the  accounting for
     certain  provisions  of the  Medicare  Act.  In May 2004,  the FASB  issued
     definitive  accounting guidance for the Medicare Act in FASB Staff Position
     106-2,  which was  effective  for the Company in the third quarter of 2004.
     FASB  Staff  Position  106-2  results  in the  recognition  of lower  other
     postretirement  employment  benefit  (OPEB)  costs to reflect  prescription
     drug-related  federal subsidies to be received under the Medicare Act. As a
     result  of the  Medicare  Act,  the  Company's  accumulated  postretirement
     benefit  obligation as of January 1, 2004, was reduced by approximately $83
     million,   and  the  Company's  2004  net  periodic  cost  was  reduced  by
     approximately $13 million.

     SFAS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R)

     In December  2004,  the FASB issued SFAS No. 123R,  which  revises SFAS No.
     123, "Accounting for Stock-Based  Compensation," and supersedes  Accounting
     Principles  Board (APB)  Opinion No. 25,  "Accounting  for Stock  Issued to
     Employees."  The key  requirement  of SFAS  No.  123R is that  the  cost of
     share-based  awards to employees  will be measured based on an award's fair
     value  at  the  grant  date,  with  such  cost  to be  amortized  over  the
     appropriate  service period.  Previously,  entities could elect to continue
     accounting  for such awards at their grant date  intrinsic  value under APB
     Opinion No. 25, and the Company made that  election.  The  intrinsic  value
     method resulted in the Company recording no compensation  expense for stock
     options granted to employees (See Note 11).

     SFAS No.  123R will be  effective  for the  Company  on July 1,  2005.  The
     Company  intends to  implement  the standard  using the  required  modified
     prospective method. Under that method, the Company will record compensation
     expense  under SFAS No.  123R for all awards it grants  after July 1, 2005,
     and it will record  compensation  expense (as previous  awards  continue to
     vest) for the unvested  portion of  previously  granted  awards that remain
     outstanding  at July 1, 2005.  In 2004,  the Company  made the  decision to
     cease  granting  stock  options  and intends to replace  that  compensation
     program with other programs.  Therefore, the amount of stock option expense
     expected  to be  recorded  in 2005 is below the amount that would have been
     recorded if the stock option program had continued.  The Company expects to
     record  approximately  $3 million of pre-tax  expense for stock  options in
     2005.

     PROPOSED FASB INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES"

     In July 2004, the FASB stated that it plans to issue an exposure draft of a
     proposed  interpretation  of SFAS No. 109,  "Accounting  for Income  Taxes"
     (SFAS No.  109),  that would  address  the  accounting  for  uncertain  tax
     positions.  The FASB has indicated  that the  interpretation  would require
     that  uncertain  tax  benefits be probable of being  sustained  in order to
     record such benefits in the consolidated financial statements. The exposure
     draft is  expected to be issued in the first  quarter of 2005.  The Company
     cannot  predict  what  actions  the FASB will take or how any such  actions
     might  ultimately  affect the  Company's  financial  position or results of
     operations,  but such changes could have a material impact on the Company's
     evaluation and recognition of Section 29 tax credits (See Note 23E).

                                       94
<PAGE>

3.   HURRICANE RELATED COSTS

     Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of
     the  Company's  service  territories  during  the  third  quarter  of 2004,
     significantly   impacting  PEF's  territory.   As  of  December  31,  2004,
     restoration  of the  Company's  systems from  hurricane-related  damage was
     estimated at $398 million.  PEC incurred  restoration costs of $13 million,
     of which $12 million was charged to operation and  maintenance  expense and
     $1 million was charged to capital  expenditures.  PEF had  estimated  total
     costs  of $385  million,  of which  $47  million  was  charged  to  capital
     expenditures,  and $338  million  was charged to the storm  damage  reserve
     pursuant to a regulatory order.

     In accordance with a regulatory order, PEF accrues $6 million annually to a
     storm  damage  reserve  and is  allowed  to defer  losses  in excess of the
     accumulated reserve for major storms. Under the order, the storm reserve is
     charged  with  operation  and   maintenance   expenses   related  to  storm
     restoration and with capital expenditures related to storm restoration that
     are in excess of expenditures assuming normal operating  conditions.  As of
     December 31, 2004, $291 million of hurricane restoration costs in excess of
     the previously recorded storm reserve of $47 million had been classified as
     a regulatory asset recognizing the probable  recoverability of these costs.
     On November  2, 2004,  PEF filed a petition  with the FPSC to recover  $252
     million of storm costs plus interest from retail ratepayers over a two-year
     period.  Storm reserve costs of $13 million were  attributable to wholesale
     customers.  The Company  has  received  approval  from the FERC to amortize
     these costs  consistent  with recovery of such amounts in wholesale  rates.
     PEF continues to review the restoration cost invoices received.  Given that
     not all  invoices  have been  received as of December  31,  2004,  PEF will
     update  its  petition  with the FPSC upon  receipt  and audit of all actual
     charges  incurred.  Hearings on PEF's petition for recovery of $252 million
     of storm  costs  filed  with the FPSC are  scheduled  to begin on March 30,
     2005.

     On November 17, 2004, the Citizens of the State of Florida,  by and through
     Harold McLean, Public Counsel, and the Florida Industrial Power Users Group
     (FIPUG),  (collectively,  Joint  Movants),  filed a Motion to Dismiss PEF's
     petition to recover the $252 million in storm costs.  On November 24, 2004,
     PEF responded in opposition to the motion,  which was also the FPSC staff's
     position in its recommendation to the Commission on December 21, 2004, that
     it should deny the Motion to Dismiss.  On January 4, 2005,  the  Commission
     ruled in favor of PEF and denied Joint Movant's Motion to Dismiss.

     PEF's January 2005 notice to the FPSC of its intent to file for an increase
     in its base  rates  effective  January  1,  2006,  anticipates  the need to
     replenish  the  depleted  storm  reserve  balance  and adjust the annual $6
     million  accrual in light of recent storm history to restore the reserve to
     an adequate level over a reasonable time period (See Note 8C).

     PEC does not have an ongoing  regulatory  mechanism to recover storm costs;
     therefore,  hurricane  restoration  costs  recorded in the third quarter of
     2004 were  charged  to  operations  and  maintenance  expenses  or  capital
     expenditures based on the nature of the work performed.  In connection with
     other storms,  PEC has previously  sought and received  permission from the
     NCUC  and the  SCPSC to defer  storm  expenses  and  amortize  them  over a
     five-year  period.  PEC did not seek  deferral of 2004 storm costs from the
     NCUC (See Note 8B).

4.   DIVESTITURES

     A. Sale of Natural Gas Assets

     In December  2004,  the Company sold certain  gas-producing  properties and
     related assets owned by Winchester  Production  Company,  Ltd.  (Winchester
     Production),  an  indirectly  wholly  owned  subsidiary  of Progress  Fuels
     Corporation  (Progress Fuels),  which is included in the Fuels segment. Net
     proceeds of  approximately  $251 million were used to reduce debt.  Because
     the sale significantly altered the ongoing relationship between capitalized
     costs  and  remaining  proved  reserves,  under  the  full-cost  method  of
     accounting,  the pre-tax  gain of $56 million  was  recognized  in earnings
     rather than as a reduction of the basis of the Company's  remaining oil and
     gas  properties.  The pre-tax gain has been included in  (gain)/loss on the
     sale of assets in the Consolidated Statements of Income.

                                       95
<PAGE>

     B. Divestiture of Synthetic Fuel Partnership Interests

     In June 2004, the Company through its subsidiary,  Progress Fuels, sold, in
     two transactions,  a combined 49.8% partnership  interest in Colona Synfuel
     Limited   Partnership,   LLLP,  one  of  its  synthetic  fuel   facilities.
     Substantially all proceeds from the sales will be received over time, which
     is  typical  of such  sales in the  industry.  Gain from the sales  will be
     recognized  on a cost  recovery  basis.  The  Company's  book  value of the
     interests sold totaled approximately $5 million. The Company received total
     gross  proceeds of $10 million in 2004.  Based on projected  production and
     tax credit levels,  the Company  anticipates  receiving  approximately  $24
     million  in 2005,  approximately  $31  million in 2006,  approximately  $32
     million in 2007, and approximately $8 million through the second quarter of
     2008.  In the event that the  synthetic  fuel tax  credits  from the Colona
     facility are reduced,  including an increase in the price of oil that could
     limit or  eliminate  synthetic  fuel tax  credits,  the amount of  proceeds
     realized from the sale could be significantly impacted.

     C. 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.  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 10A).  In March 2003,  the  Company  signed a letter of intent to
     sell the majority of Railcar Ltd.  assets to The  Andersons,  Inc., and the
     transaction   closed  in  February  2004.   Proceeds  from  the  sale  were
     approximately   $82  million   before   transaction   costs  and  taxes  of
     approximately  $13 million.  In July 2004,  the Company sold the  remaining
     assets  classified as held for sale to a third-party for net proceeds of $6
     million.  The assets of Railcar  Ltd.  were grouped as assets held for sale
     and were  included  in other  current  assets on the  Consolidated  Balance
     Sheets at December 31, 2003, at approximately $75 million,  which reflected
     the Company's  estimates of the fair value expected to be realized from the
     sale of these assets less costs to sell.

     D. 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. 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.

     E. 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  approximately  $443
     million were used to reduce debt.

     The  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 and $16 million for
     the  years  ended  December  31,  2003  and  2002,  respectively,  has been
     allocated  to  discontinued  operations  based on the net  assets  of NCNG,
     assuming a uniform  debt-to-equity  ratio across the Company's  operations.
     The Company ceased recording  depreciation  effective October 1, 2002, upon
     classification  of  the  assets  as  discontinued   operations.   After-tax
     depreciation expense recorded by NCNG for the year ended December 31, 2002,
     was $9 million. Results of discontinued operations for years ended December
     31 were as follows:

                                       96
<PAGE>


<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------
(in millions)                                                    2004        2003        2002
----------------------------------------------------------------------------------------------
Revenues                                                         $  -       $ 284       $ 300
----------------------------------------------------------------------------------------------
Earnings before income taxes                                     $  -       $   6       $   9
Income tax expense                                                  -           2           4
----------------------------------------------------------------------------------------------
Net earnings from discontinued operations                           -           4           5
----------------------------------------------------------------------------------------------
Gain/(Loss) on disposal of discontinued operations,
       including  applicable  income tax  benefit / (expense) of
       $6, $1 and $3, respectively                                  6         (12)        (29)
----------------------------------------------------------------------------------------------
Earnings (loss) from discontinued operations                     $  6       $  (8)      $ (24)
----------------------------------------------------------------------------------------------
</TABLE>

     During 2004, the Company  recorded an additional tax gain of  approximately
     $6 million due to final tax adjustments related to the divestiture of NCNG.

     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  Consolidated
     Statements of Income for the year ended December 31, 2003.

5.   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 (PT 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, PT LLC.  Odyssey  holds a combined  45%  ownership  interest  in PT LLC
     through EPIK and Caronet.  The accounts of PT LLC have been included in the
     Company's Consolidated Financial Statements since the transaction date.

     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.  No gain or
     loss was  recognized  on the  transaction.  The  EPIK  purchase  price  was
     initially allocated as follows: property and equipment - $27 million; other
     current  assets  - $9  million;  current  liabilities  - $21  million;  and
     goodwill - $7 million.  During 2004, PT LLC developed a restructuring  plan
     to exit certain leasing arrangements of EPIK and finalized its valuation of
     acquired assets and liabilities. Management considered a number of factors,
     including  valuations  and  appraisals,  when making these  determinations.
     Based on the results of these  activities,  the preliminary  purchase price
     allocation  for EPIK was revised as follows at December 31, 2004:  property
     and equipment - $36 million; other current assets - $7 million;  intangible
     assets - $1 million; current liabilities - $18 million; and exit costs - $4
     million.  The exit costs consist primarily of lease  termination  penalties
     and  noncancelable  lease payments made after certain leased properties are
     vacated.  The pro forma results of operations  reflecting  the  acquisition
     would not be materially  different than the reported  results of operations
     for 2003 or 2002.

     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.  The pro forma results of operations  reflecting  the  acquisition
     would not be materially  different from the reported  results of operations
     for the years ended December 31, 2003 and 2002.

                                       97
<PAGE>

     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 9). 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 open market purchases and
     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. Westchester Acquisition

     In April 2002,  Progress Fuels, a subsidiary of Progress  Energy,  acquired
     100% of Westchester Gas Company (Westchester).  During 2004 the name of the
     company was changed to Winchester Energy Co. Ltd.. 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 relates to customer  contracts (See Note
     9). 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 from the reported results of
     operations for the year ended December 31, 2002.

     E. 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 $228  million,  $56 million and $64 million,  respectively
     (See Note 9). 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 $23 million was  assigned to  interconnection  contracts.
     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 from the reported  results of operations for the year
     ended December 31, 2002.

                                       98
<PAGE>

6.   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)                                2004             2003
-------------------------------------------------------------------------
Production plant  (7-33 years)             $ 11,966         $ 12,044
Transmission plant  (30-75 years)             2,282            2,167
Distribution plant  (12-50 years)             6,749            6,432
General plant and other  (8-75 years)         1,106            1,037
-------------------------------------------------------------------------
Utility plant in service                   $ 22,103         $ 21,680
-------------------------------------------------------------------------

     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 7.2% in 2004,
     4.0% in 2003 and 6.2% in 2002,  respectively.  The composite AFUDC rate for
     PEF's electric utility plant was 7.8% in 2004, 2003 and 2002.

     Depreciation   provisions  on  utility  plant,  as  a  percent  of  average
     depreciable  property other than nuclear fuel,  were 2.2%, 2.5% and 2.6% in
     2004, 2003 and 2002,  respectively.  The depreciation provisions related to
     utility  plant were $463  million,  $517  million and $488 million in 2004,
     2003 and 2002,  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 6D),  regulatory  approved
     expenses (See Note 8 and Note 22) and NC Clean Air Legislation amortization
     (See Note 8B).

     During 2004,  PEC met the  requirements  of both the NCUC and the SCPSC for
     the implementation of two depreciation  studies that allowed the utility to
     reduce  the  rates  used to  calculate  depreciation  expense.  The  annual
     reduction  in  depreciation  expense  is  approximately  $82  million.  The
     reduction  is due  primarily  to  extended  lives at each of PEC's  nuclear
     units. The new depreciation rates were effective January 1, 2004.

     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,  for the years ended December 31,
     2004,  2003 and 2002 were $140  million,  $143  million  and $141  million,
     respectively,  and are included in fuel used for electric generation in the
     Consolidated Statements of Income.

     B. Diversified Business Property

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

                                       99
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------
(in millions)                                                       2004         2003
-------------------------------------------------------------------------------------------
Equipment (3-25 years)                                          $     383      $   246
Nonregulated generation plant and equipment (3-40 years)            1,302        1,299
Land and mineral rights                                               107           93
Buildings and plants (5-40 years)                                     131          125
Oil and gas properties (units-of-production)                          336          412
Telecommunications equipment (5-20 years)                              80           63
Rail equipment (3-20 years)                                            29          125
Marine equipment (3-35 years)                                          87           83
Computers, office equipment and software (3-10 years)                  36           36
Construction work in progress                                          26           13
Accumulated depreciation                                             (507)        (400)
-------------------------------------------------------------------------------------------
Diversified business property, net                              $   2,010      $ 2,095
-------------------------------------------------------------------------------------------
</TABLE>

     The synthetic fuel facilities are being  depreciated  through 2007 when the
     Section 29 tax credits will expire. The Company's  nonregulated  businesses
     capitalize  interest costs under SFAS No. 34,  "Capitalization  of Interest
     Costs."  During  the  years  ended  December  31,  2004,   2003  and  2002,
     respectively,  the  Company  capitalized  $7  million,  $20 million and $38
     million,  respectively,  of its interest cost of $660 million, $655 million
     and $679 million. Capitalized interest for 2004 is related to the expansion
     of Fuels' gas operations.  Capitalized interest in 2003 and 2002 is 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 $148 million,  $120 million and $85 million for December 31, 2004, 2003
     and 2002, 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>
-----------------------------------------------------------------------------------------------------------------
2004                                                  Company                                    Construction
                                                     Ownership        Plant       Accumulated       Work in
    Subsidiary                 Facility               Interest     Investment     Depreciation     Progress
-----------------------------------------------------------------------------------------------------------------
PEC                Mayo Plant                          83.83%        $   516       $    249            $  1
PEC                Harris Plant                        83.83%          3,185          1,387              13
PEC                Brunswick Plant                     81.67%          1,624            888              28
PEC                Roxboro Unit 4                      87.06%            323            147               1
PEF                Crystal River Unit 3                91.78%            889            443               9
PEF                Intercession City Unit P11          66.67%             22              7               8
-----------------------------------------------------------------------------------------------------------------

-----------------------------------------------------------------------------------------------------------------
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          1,424               7
PEC                Brunswick Plant                     81.67%          1,611            885              21
PEC                Roxboro Unit 4                      87.06%            323            139               1
PEF                Crystal River Unit 3                91.78%            875            442              46
PEF                Intercession City Unit P11          66.67%             22              6               6
-----------------------------------------------------------------------------------------------------------------
</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).

                                      100
<PAGE>

     D. Asset Retirement Obligations

     At  December  31,  2004 and 2003,  the asset  retirement  costs  related to
     nuclear   decommissioning   of  irradiated   plant,   net  of   accumulated
     depreciation,  totaled $277 million and $354 million,  respectively.  Funds
     set aside in the  Company's  nuclear  decommissioning  trust  funds for the
     nuclear  decommissioning  liability totaled $1.044 billion and $938 million
     at December 31, 2004 and 2003,  respectively.  Net nuclear  decommissioning
     trust  unrealized  gains are included in regulatory  liabilities  (See Note
     8A).

     Decommissioning  cost  provisions,  which are included in depreciation  and
     amortization  expense,  were $31  million  in each of 2004,  2003 and 2002.
     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.  The Company's  expenses  recognized for the
     disposal  or  removal  of  utility  assets  that are not SFAS No. 143 asset
     removal  obligations,  which are included in depreciation  and amortization
     expense, were $160 million, $158 million and $149 million in 2004, 2003 and
     2002, respectively.

     The  utilities   recognize  removal,   nonirradiated   decommissioning  and
     dismantlement costs in regulatory  liabilities on the Consolidated  Balance
     Sheets (See Note 8A). At December 31, 2004,  such costs  consist of removal
     costs of $1.606 billion,  removal costs for nonirradiated  areas at nuclear
     facilities   of  $131  million  and  amounts   previously   collected   for
     dismantlement of fossil generation plants of $144 million.  At December 31,
     2003, such costs consist of removal costs of $1.846 billion,  removal costs
     for nonirradiated  areas at nuclear  facilities of $129 million and amounts
     previously  collected for dismantlement of fossil generation plants of $143
     million.  During 2004, PEC reduced its estimated removal costs to take into
     account the estimates used in the depreciation  studies  implemented during
     2004  (See  Note 6A).  This  resulted  in a  downward  revision  in the PEC
     estimated  removal costs and equal increase in accumulated  depreciation of
     approximately $345 million.

     PEC's most recent  site-specific  estimates of  decommissioning  costs were
     developed  in 2004,  using  2004  cost  factors,  and are  based on  prompt
     dismantlement  decommissioning,  which  reflects the cost of removal of all
     radioactive and other  structures  currently at the site, with such removal
     occurring after operating  license  expiration.  These  estimates,  in 2004
     dollars,  are $294  million  for  Robinson  Unit No.  2, $290  million  for
     Brunswick  Unit No.  1,  $313  million  for  Brunswick  Unit No. 2 and $359
     million for the Harris Plant.  The estimates are subject to change based on
     a variety  of factors  including,  but not  limited  to,  cost  escalation,
     changes in technology applicable to nuclear  decommissioning and changes in
     federal, state or local regulations. The cost estimates exclude the portion
     attributable  to North  Carolina  Eastern  Municipal  Power  Agency  (Power
     Agency),  which holds an undivided  ownership interest in the Brunswick and
     Harris nuclear  generating  facilities.  NRC operating licenses held by PEC
     currently  expire in December 2014 and September 2016 for Brunswick Units 2
     and 1,  respectively.  An application to extend these licenses 20 years was
     submitted in October 2004.  The NRC  operating  license held by PEC for the
     Shearon Harris Nuclear Plant (Harris  Plant)  currently  expires in October
     2026.  An  application  to extend  this  license 20 years is expected to be
     submitted  in the  fourth  quarter  of 2006.  On April  19,  2004,  the NRC
     announced  that it has renewed  the  operating  license for PEC's  Robinson
     Nuclear Plant (Robinson) for an additional 20 years through July 2030.

     PEF's most recent site-specific  estimate of decommissioning  costs for the
     Crystal  River  Nuclear  Plant (CR3) was  developed in 2000 based on prompt
     dismantlement  decommissioning.  The  estimate,  in 2000  dollars,  is $491
     million  and is subject to change  based on the same  factors as  discussed
     above  for  PEC's  estimates.   The  cost  estimate  excludes  the  portion
     attributable to other  co-owners of CR3. The NRC operating  license held by
     PEF for Crystal River Unit No. 3 (CR3) currently  expires in December 2016.
     An  application to extend this license 20 years is expected to be submitted
     in the first quarter of 2009.

     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 require retirement action only upon abandonment or
     cessation of use of the property for the specified purpose.  The ARO 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 would be recorded at that
     time.

     The Company's  nonregulated AROs relate to coal mine operations,  synthetic
     fuel  operations  and gas production of Progress  Fuels.  The related asset
     retirement costs, net of accumulated depreciation,  totaled $10 million and
     $5 million at December 31, 2004 and 2003, respectively.

                                      101
<PAGE>

     The following table shows the changes to the asset retirement  obligations.
     Additions  relate primarily to additional  reclamation  obligations at coal
     mine operations of Progress Fuels.  The deductions to regulated ARO related
     to PEC re-measuring the nuclear  decommissioning costs of irradiated plants
     to take into account updated  site-specific  decommissioning  cost studies,
     which are required by the NCUC every five years.

<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
Additions                                                          -               6
Accretion expense                                                 73               2
Deductions                                                       (63)             (7)
------------------------------------------------------------------------------------------
Asset retirement obligations as of December 31, 2004         $ 1,261            $ 21
------------------------------------------------------------------------------------------
</TABLE>

     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. 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.

     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 under
     NEIL,  following a 12-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 (71 weeks for CR3) 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 $29.3
     million with respect to the primary coverage, $32.4 million with respect to
     the  decontamination,  decommissioning  and excess property  coverage,  and
     $20.2 million for the incremental  replacement power costs coverage, in the
     event  covered  losses at insured  facilities  exceed  premiums,  reserves,
     reinsurance and other NEIL resources. Pursuant to regulations 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 $10.8 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 could possibly approve revisions to
     the Price Anderson Act during 2005 that could include  increased limits and
     assessments  per reactor owned.  The final outcome of this matter cannot be
     predicted at this time.

                                      102
<PAGE>

     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 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 Notes 3 and 8A).

7.   CURRENT ASSETS

     RECEIVABLES

     At December 31, receivables were comprised of:

----------------------------------------------------------------------------
(in millions)                                       2004           2003
----------------------------------------------------------------------------
Trade accounts receivable                         $   689        $   705
Unbilled accounts receivable                          271            293
Notes receivable                                       98             61
Other receivables                                      27             47
Unbilled other receivables                             28             10
Allowance for doubtful accounts receivable            (29)           (32)
----------------------------------------------------------------------------
Total receivables                                 $ 1,084        $ 1,084
----------------------------------------------------------------------------

     Income tax receivables and interest income  receivables are not included in
     this classification. These amounts are in prepaids and other current assets
     on the Consolidated Balance Sheet.

     INVENTORY

     At December 31, inventory was comprised of:

------------------------------------------------------------
(in millions)                       2004           2003
------------------------------------------------------------
Fuel for production               $  235         $  210
Inventory for sale                   230            167
Materials and supplies               517            530
------------------------------------------------------------
Total inventory                   $  982         $  907
------------------------------------------------------------

8.   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  that 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.

                                      103
<PAGE>


     At December 31, the balances of  regulatory  assets  (liabilities)  were as
     follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------
(in millions)                                                            2004             2003
---------------------------------------------------------------------------------------------------

Deferred fuel cost - current (Note 8B and 8C)                      $      229        $     270
---------------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 8B and 8C)                           107               47
Deferred impact of ARO - PEC (Note 1D)                                    305              291
Income taxes recoverable through future rates (Note 15)                    84               75
Loss on reacquired debt (Note 1D)                                          53               55
Deferred DOE enrichment facilities-related costs                           16               24
Storm deferral (Notes 3 and 8B)                                           316               21
Postretirement benefits (Note 17)                                          74                9
Other                                                                     109               76
---------------------------------------------------------------------------------------------------
     Total long-term regulatory assets                                  1,064              598
---------------------------------------------------------------------------------------------------
Deferred energy conservation cost - current                                (8)              (7)
---------------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 6D)                                      (1,881)          (2,118)
Deferred impact of ARO (Note 1D)                                         (221)            (212)
Net nuclear decommissioning trust unrealized gains (Note 6D)             (224)            (204)
Postretirement benefits (Note 17B)                                        (45)            (211)
Storm reserve (Note 3)                                                      -              (41)
Clean air compliance (Note 8B)                                           (248)             (74)
Other                                                                     (35)             (19)
---------------------------------------------------------------------------------------------------
     Total long-term regulatory liabilities                            (2,654)          (2,879)
---------------------------------------------------------------------------------------------------
         Net regulatory assets (liabilities)                       $   (1,369)       $  (2,018)
---------------------------------------------------------------------------------------------------
</TABLE>

     Except for portions of deferred  fuel costs and deferred  storm costs,  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. PEC Retail Rate Matters

     As of  December  31,  2004,  PEC's  North  Carolina  retail fuel costs were
     underrecovered  by $145  million.  This amount is comprised of $117 million
     eligible  for recovery in 2005 and $28 million  deferred  from a 2001 order
     from the NCUC that cannot be collected  during 2005, and has therefore been
     classified  as a long-term  asset.  PEC  intends to collect  this amount by
     October 31, 2007.

     On October 15, 2004,  the SCPSC  approved PEC's request to leave fuel rates
     unchanged.  The deferred fuel balance at December 31, 2004, is $23 million.
     This amount is eligible  for  recovery  in PEC's 2005 South  Carolina  fuel
     review.

     PEC   obtained   SCPSC  and  NCUC   approval  of  fuel  factors  in  annual
     fuel-adjustment  proceedings.  The NCUC approved an annual  increase of $62
     million,  $20 million and $46 million by orders  issued in September  2004,
     2003 and 2002,  respectively.  The SCPSC  approved PEC's petition each year
     and the changes were insignificant.

     PEC filed with the SCPSC seeking permission to defer expenses incurred from
     the first quarter 2004 winter storm.  The SCPSC  approved  PEC's request to
     defer the costs and  amortize  them  ratably  over five years  beginning in
     January 2005.  Approximately $9 million related to storm costs was deferred
     in 2004.

     In  October  2003,  PEC filed  with the NCUC  seeking  permission  to defer
     expenses  incurred  from  Hurricane  Isabel and the  February  2003  winter
     storms.  In December  2003,  the NCUC  approved  PEC's request to defer the
     costs  associated with Hurricane Isabel and the February 2003 ice storm and
     amortize them over a period of five years.  PEC charged  approximately  $24
     million in 2003 from  Hurricane  Isabel and from ice storms to the deferred
     account.  PEC recognized $5 million and $3 million of NC storm amortization
     during 2004 and 2003, respectively.

                                      104
<PAGE>

     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 2004 and 2003 and
     additional depreciation expense of approximately $53 million in 2002. Total
     accelerated  depreciation  recorded  through  December 31,  2004,  was $403
     million.

     The North  Carolina  Clean  Smokestacks  Act enacted in June 2002 (NC Clean
     Air),  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. The
     legislation  provides for  significant  flexibility in the amount of annual
     amortization  recorded,  which  allows  the  utilities  to vary the  amount
     amortized within certain limits.  This flexibility  provides a utility with
     the  opportunity to consider the impacts of other factors on its regulatory
     return on equity when setting the  amortization  amount for each year.  PEC
     recognized  $174 million and $74 million of clean air  amortization  during
     2004 and 2003,  respectively.  This legislation freezes PEC's base rates in
     North Carolina for five years, subject to certain conditions (See Note 22).

     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
     nonreal  time pricing  customers  in the amounts of $3 million in 2002,  $5
     million in 2003 and $6 million in both 2004 and 2005.

     In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek
     a base retail  electric rate increase in North  Carolina and South Carolina
     through  December  2004.  The agreement not to seek a base retail  electric
     rate  increase  in  South   Carolina  was  extended  to  December  2005  in
     conjunction with regulatory approval to form a holding company.

     C. PEF Retail Rate Matters

     On November 9, 2004, the FPSC approved PEF's  underrecovered  fuel costs of
     $156 million for 2004,  of which PEF plans to defer $79 million  until 2006
     to mitigate the impact on customers resulting from the need to also recover
     hurricane-related  costs. Therefore, $79 million of deferred fuel costs has
     been  classified  as a long-term  asset.  As of December 31, 2004,  PEF was
     underrecovered  in fuel costs by $168 million.  The  additional $12 million
     over and above the $156  million  approved  by the FPSC will be included in
     PEF's 2005 fuel filing.

     On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement,
     executed on April 29, 2004,  by PEF,  the Office of Public  Counsel and the
     Florida  Industrial  Power Users  Group.  The  stipulation  and  settlement
     resolved the issue pending  before the FPSC regarding the costs PEF will be
     allowed to  recover  through  its Fuel and  Purchased  Power Cost  Recovery
     clause in 2004 and beyond for waterborne  coal  deliveries by the Company's
     affiliated coal supplier,  Progress Fuels Corporation.  The settlement sets
     fixed per ton  prices  based on point of  origin  for all  waterborne  coal
     deliveries in 2004, and establishes a market-based  pricing methodology for
     determining  recoverable  waterborne  coal  transportation  costs through a
     competitive  solicitation  process  or  market  price  proxies  in 2005 and
     thereafter.  The settlement  reduces the amount that PEF will charge to the
     Fuel and Purchased Power Cost Recovery clause for waterborne transportation
     by approximately $11 million beginning in 2004.

     On November 3, 2004, the FPSC approved PEF's petition for  Determination of
     Need for the  construction  of a fourth unit at PEF's Hines Energy Complex.
     Hines  Unit  4 is  needed  to  maintain  electric  system  reliability  and
     integrity and to continue to provide adequate electricity to its ratepayers
     at a  reasonable  cost.  Hines Unit 4 will be a combined  cycle unit with a
     generating  capacity  of  461  MW  (summer  rating).  The  estimated  total
     in-service  cost of Hines Unit 4 is $286  million,  and the unit is planned
     for commercial  operation in December 2007. If the actual cost is less than
     the estimate,  customers  will receive the benefit of such cost  underruns.
     Any  costs  that  exceed  this  estimate  will  not be  recoverable  absent
     extraordinary circumstances as found by the FPSC in subsequent proceedings.

     See Note 3 for information on PEF's petition for storm cost recovery.

                                      105
<PAGE>

     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 2004, 2003 and 2002
     were $1.370 billion, $1.333 billion and $1.296 billion,  respectively,  and
     will  increase $37 million in 2005.  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 caps for 2004,
     2003 and 2002 were  $1.430  billion,  $1.393  billion  and $1.356  billion,
     respectively,  and will increase $37 million in 2005. Any amounts above the
     retail base revenue caps will be refunded  100% to  customers.  At December
     31,  2004,  $9 million  has been  accrued  and will be  refunded  to retail
     customers by March 2005.  The 2003 revenue  sharing amount was $18 million,
     and was refunded to customers by April 30, 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.  In 2004,  PEF  recovered  $36 million
     through this clause related to Hines Unit 2.

     In  addition,  PEF  suspended  retail  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.  No  accelerated  depreciation  expense was recorded
     during 2004 and 2003. In addition, PEF is authorized, at its discretion, to
     accelerate the amortization of certain  regulatory  assets over the term of
     the Agreement.

     Under the terms of the Agreement, PEF agreed to continue the implementation
     of its four-year Commitment to Excellence  Reliability Plan and expected to
     achieve  a 20%  improvement  in  its  annual  System  Average  Interruption
     Duration  Index by no later than 2004.  If this  improvement  level was not
     achieved for calendar  years 2004 or 2005, PEF would have provided 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.
     PEF achieved this improvement level in 2004.

     In January 2005, in  anticipation  of the expiration of its Stipulation and
     Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate
     case,  PEF  notified the FPSC that it intends to request an increase in its
     base rates,  effective  January 1, 2006.  In its notice,  PEF requested the
     FPSC to approve calendar year 2006 as the projected test period for setting
     new base rates.  The request for increased  base rates is based on the fact
     that PEF has faced  significant  cost  increases  over the past  decade and
     expects its operational costs to continue to increase.  These costs include
     the costs  associated with  completion of the Hines 3 generation  facility,
     extraordinary  hurricane damage costs including capital costs which are not
     expected to be directly  recoverable,  the need to  replenish  the depleted
     storm reserve and the expected infrastructure  investment necessary to meet
     high  customer  expectations,  coupled with the demands  placed on PEF as a
     result  of  strong  customer   growth.   On  February  7,  2005,  the  FPSC
     acknowledged   receipt  of  PEF's  notice  and  authorized  minimum  filing
     requirements and testimony to be filed May 1, 2005.

                                      106
<PAGE>

     D. Regional Transmission Organizations and Standard Market Design

     In 2000, the Federal Energy  Regulatory  Commission (FERC) issued Order No.
     2000 regarding regional  transmission  organizations (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  have  materially  altered  the manner in which
     transmission  and  generation  services are provided and paid for. In April
     2003, the FERC released a White Paper on the Wholesale Market Platform. The
     White Paper  provided an overview of what the FERC intended to include in a
     final rule in the SMD NOPR docket. The White Paper retained 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 GridSouth and  GridFlorida  proceedings  currently  ongoing  before the
     FERC. By order issued  December 22, 2004, the FERC  terminated a portion of
     the proceedings regarding GridSouth. The GridSouth Companies asked the FERC
     for further  clarification  as to the portions of the  GridSouth  docket it
     intended  to  address.  On March 2, 2005,  the FERC  affirmed  that it only
     intended to close the  mediation  portion of the  GridSouth  docket.  It is
     unknown  what  impact the  future  proceedings  will have on the  Company's
     earnings, revenues or prices.

     The Florida  Public Service  Commission  (FPSC) ruled in December 2001 that
     the formation of GridFlorida by the three major investor-owned utilities in
     Florida,  including  PEF, was prudent but ordered  changes in the structure
     and market design of the proposed organization. In September 2002, the FPSC
     set a hearing  for market  design  issues;  this order was  appealed to the
     Florida Supreme Court by the consumer advocate of the state of Florida.  In
     June  2003,  the  Florida   Supreme  Court  dismissed  the  appeal  without
     prejudice.  In September 2003, the FERC held a Joint  Technical  Conference
     with  the  FPSC to  consider  issues  related  to  formation  of an RTO for
     peninsular  Florida.  In December  2003,  the FPSC  ordered  further  state
     proceedings  and  established  a  collaborative   workshop  process  to  be
     conducted  during  2004.  In June 2004,  the  workshop  process  was abated
     pending  completion  of a  cost-benefit  study  currently  scheduled  to be
     presented at a FPSC workshop on May 25, 2005, with subsequent action by the
     FPSC to be thereafter determined.

     The  Company  has $33 million  and $4 million  invested  in  GridSouth  and
     GridFlorida,  respectively,  related to startup costs at December 31, 2004.
     The Company expects to recover these startup costs in conjunction  with the
     GridSouth and GridFlorida  original  structures or in conjunction  with any
     alternate combined transmission structures that emerge.

     E. FERC Market Power Mitigation

     A FERC order  issued in November  2001 on certain  unaffiliated  utilities'
     triennial  market-based wholesale power rate authorization updates required
     certain  mitigation  actions  that those  utilities  would need to take for
     sales/purchases  within their control areas and required those utilities to
     post  information on their Web sites regarding their power systems' status.
     As  a  result  of  a  request  for  rehearing   filed  by  certain   market
     participants,  FERC  issued an order  delaying  the  effective  date of the
     mitigation plan until after a planned technical  conference on market power
     determination.  In December 2003, the FERC issued a staff paper  discussing
     alternatives  and held a technical  conference  in January  2004.  In April
     2004,  the FERC  issued two orders  concerning  utilities'  ability to sell
     wholesale  electricity at market-based  rates. In the first order, the FERC
     adopted two new interim screens for assessing  potential  generation market
     power  of  applicants  for  wholesale  market-based  rates,  and  described
     additional  analyses and mitigation  measures that could be presented if an
     applicant  does not pass one of these interim  screens.  In July 2004,  the
     FERC issued an order on rehearing  affirming its  conclusions  in the April
     order.  In the second  order,  the FERC  initiated a rulemaking to consider
     whether the FERC's current  methodology  for  determining  whether a public
     utility  should be allowed to sell wholesale  electricity  at  market-based
     rates  should be modified in any way. PEF does not have  market-based  rate
     authority for wholesale sales in peninsular  Florida.  Given the difficulty
     PEC believes it would experience in passing one of the interim screens,  on
     August  12,  2004,   PEC  notified  the  FERC  that  it  would  revise  its
     Market-based Rate tariff to restrict it to sales outside PEC's control area
     and file a new  cost-based  tariff for sales within PEC's control area that
     incorporates the FERC's default  cost-based rate methodologies for sales of
     one year or less. PEC  anticipates  making this filing in the first quarter
     of 2005.  PEC does not  anticipate  that  the  current  operations  will be
     materially impacted by this change. Although the Company cannot predict the
     ultimate outcome of these changes, the Company does not anticipate that the
     current operations of PEC or PEF would be impacted  materially if they were
     unable to sell  power at  market-based  rates in their  respective  control
     areas.

                                      107
<PAGE>

     F. Energy Delivery Capitalization Practice

     The  Company  has  reviewed  its  capitalization  policies  for its  Energy
     Delivery  business units in PEC and PEF. That review  indicated that in the
     areas of outage and  emergency  work not  associated  with major storms and
     allocation of indirect  costs,  both PEC and PEF should revise the way that
     they estimate the amount of capital costs  associated  with such work.  The
     Company has  implemented  such  changes  effective  January 1, 2005,  which
     include  more  detailed  classification  of outage and  emergency  work and
     result in more precise  estimation  and a process of  retesting  accounting
     estimates  on an annual  basis.  As a result of the  changes in  accounting
     estimates for the outage and emergency  work and indirect  costs,  a lesser
     proportion  of PEC's and PEF's costs will be  capitalized  on a prospective
     basis. The Company estimates that the combined impact for both utilities in
     2005 will be that  approximately  $55 million of costs that would have been
     capitalized under the previous policies will be expensed.  Pursuant to SFAS
     No. 71, PEC and PEF have informed the state regulators having  jurisdiction
     over  them of this  change  and that  the new  estimation  process  will be
     implemented  effective  January 1, 2005.  The Company has also  requested a
     method change from the IRS.

9.   GOODWILL AND OTHER INTANGIBLE ASSETS

     The Company  performed the annual  goodwill  impairment  test in accordance
     with FASB Statement No. 142, Goodwill and Other Intangible  Assets, for the
     CCO  segment  in the  first  quarter  of  2004,  and  the  annual  goodwill
     impairment test for the PEC Electric and PEF segments in the second quarter
     of 2004, each of which indicated no impairment.

     The changes in the carrying amount of goodwill,  by reportable segment, are
     as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------------------------
                                                                                 Corporate
(in millions)                           PEC Electric        PEF            CCO     and Other      Total
-------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2003              $ 1,922        $ 1,733       $ 64          $ -        $ 3,719
Acquisitions                                     -              -          -            7              7
-------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2003            $ 1,922        $ 1,733       $ 64          $ 7        $ 3,726
Purchase accounting adjustment                   -              -          -           (7)            (7)
-------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2004            $ 1,922        $ 1,733       $ 64          $ -        $ 3,719
-------------------------------------------------------------------------------------------------------------
</TABLE>

     In  December  2003,  $7  million  in  goodwill  was  recorded  based  on  a
     preliminary   purchase   price   allocation   as  part   of  the   Progress
     Telecommunications Corporation partial acquisition of EPIK and was reported
     in the Other  segment.  As  discussed  in Note 5A, the Company  revised the
     preliminary EPIK purchase price allocation as of September 2004, and the $7
     million of goodwill was  reallocated to certain  tangible  assets  acquired
     based on the results of valuations and appraisals.

     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>
----------------------------------------------------------------------------------------------------------
                                                2004                                   2003
                                  ----------------------------------  ------------------------------------
                                  Gross Carrying     Accumulated        Gross Carrying     Accumulated
(in millions)                         Amount         Amortization           Amount         Amortization
----------------------------------------------------------------------------------------------------------
Synthetic fuel intangibles            $ 134             $ (80)               $ 140            $ (64)
Power agreements acquired               221               (39)                 221              (20)
Other                                   119               (18)                  93              (13)
----------------------------------------------------------------------------------------------------------
Total                                 $ 474             $(137)               $ 454            $ (97)
----------------------------------------------------------------------------------------------------------
</TABLE>

     In June 2004,  the Company  sold,  in two  transactions,  a combined  49.8%
     partnership  interest in Colona Synfuel Limited  Partnership,  LLLP, one of
     its synthetic fuel  operations.  Approximately $6 million in synthetic fuel
     intangibles  and  $3  million  in  related  accumulated  amortization  were
     included in the basis of the partnership interest sold.

     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 23E).  The  intangibles  related to
     power  agreements  acquired  are  being  amortized  based  on the  economic

                                      108
<PAGE>

     benefits of the  contracts  (See Notes 5C and 5D).  Other  intangibles  are
     primarily  acquired customer  contracts and permits that are amortized over
     their  respective  lives. Of the increase in other intangible  assets,  $24
     million resulted from the minimum pension liability  adjustment at December
     31, 2004 (See Note 17).

     Amortization  expense  recorded  on  intangible  assets for the years ended
     December  31,  2004,  2003 and 2002 was,  in  millions,  $42,  $37 and $33,
     respectively.  The estimated  annual  amortization  expense for  intangible
     assets for 2005 through 2009, in millions,  is approximately $35, $36, $36,
     $18 and $18, respectively.

10.  IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS

     The  Company  applies  SFAS No. 144 for the  accounting  and  reporting  of
     impairment or disposal of long-lived  assets. In 2003 and 2002, the Company
     recorded  pre-tax  long-lived  asset and investment  impairments  and other
     charges of approximately $38 million and $414 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 4C).

     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.

     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 May 2002, Interpath Communication, Inc., 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.

11.  EQUITY

     A. Common Stock

     At December 31, 2004,  the Company had  approximately  63 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.  During 2004,
     2003 and 2002, respectively,  the Company issued approximately 1 million, 8
     million  and 2  million  shares  under  these  plans  for net  proceeds  of
     approximately  $62  million,  $305  million  and $86  million.  The Company
     continues to meet the requirements of the restricted stock plan with issued
     and outstanding shares.

                                      109
<PAGE>

     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 5D).

     There are various provisions  limiting the use of retained earnings for the
     payment of dividends  under  certain  circumstances.  At December 31, 2004,
     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  nonbargaining  unit
     employees  and  certain  part-time   nonbargaining  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 PT LLC/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 that 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 3.5 million and 4.0 million ESOP suspense shares at December 31,
     2004 and 2003,  respectively,  with a fair value of $156  million  and $183
     million,  respectively.  ESOP shares allocated to plan participants totaled
     12.6 million and 13.1 million in December 31, 2004 and 2003,  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
     costs,  which  were  met and  will be met  with  shares  released  from the
     suspense account,  totaled  approximately $21 million,  $20 million and $20
     million for the years ended December 31, 2004, 2003 and 2002, respectively.
     Total matching and incentive cost totaled  approximately  $32 million,  $35
     million and $30 million for the years ended  December  31,  2004,  2003 and
     2002,  respectively.  The Company has a long-term note  receivable from the
     401(k) Trustee  related to the purchase of common stock from the Company in
     1989.  The  balance  of the note  receivable  from the  401(k)  Trustee  is
     included in the determination of unearned ESOP common stock,  which reduces
     common  stock  equity.  ESOP  shares  that  have not been  committed  to be
     released to participants'  accounts are not considered  outstanding for the
     determination  of earnings per common  share.  Interest  income on the note
     receivable and dividends on unallocated  ESOP shares are not recognized for
     financial statement purposes.

     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 10 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 2004, 2003 and 2002. The

                                      110
<PAGE>

     Company will begin expensing  stock options on July 1, 2005,  based on SFAS
     No. 123R (See Note 2). In 2004,  however,  the Company made the decision to
     cease  granting  stock  options  and intends to replace  that  compensation
     program with other programs.  Therefore, the amount of stock option expense
     expected  to be  recorded  in 2005 is below the amount that would have been
     recorded if the stock option program had continued.

     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>
  ---------------------------------------------------------------------------------------------
                                                                2004      2003       2002
  ---------------------------------------------------------------------------------------------
  Risk-free interest rate                                      4.22%      4.25%      4.14%
  Dividend yield                                               5.19%      4.75%      5.20%
  Volatility factor                                            20.30%    22.28%     24.98%
  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,  2004,  2003  and  2002  had a
     weighted-average  remaining  contractual  life of 7.6,  8.7 and 9.3  years,
     respectively,  and had  exercise  prices that ranged from $40.41 to $51.85.
     The tabular information for the option activity is as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------------
                                                     2004                      2003                   2002
                                           ---------------------------------------------------------------------------
                                                        Weighted-                Weighted-                 Weighted-
                                            Number of   Average      Number of   Average     Number of     Average
                                             Options    Exercise      Options    Exercise     Options      Exercise
(option quantities in millions)                           Price                   Price                     Price
----------------------------------------------------------------------------------------------------------------------
Options outstanding, January 1                 8.0       $ 43.54        5.2       $ 42.84       2.3        $ 43.49
Granted                                         -           -           3.0       $ 44.70       2.9        $ 42.34
Forfeited                                     (0.1)      $ 43.76       (0.1)      $ 43.64        -         $ 43.71
Canceled                                      (0.1)      $ 43.67       (0.1)      $ 43.62        -            -
Exercised                                     (0.4)      $ 42.82         -        $ 43.00        -            -
Options outstanding, December 31               7.4       $ 43.57        8.0       $ 43.54       5.2        $ 42.84
Options exercisable, December 31
   with a remaining contractual life of
    7.6 years                                  4.6       $ 43.35        2.4       $ 43.09       0.8        $ 43.49
Weighted-average grant date fair value
   of options granted during the year                       -                     $  7.16                  $  6.83
----------------------------------------------------------------------------------------------------------------------
</TABLE>

     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 active stock-based  compensation programs are the Performance Share
     Sub-Plan  (PSSP) and the Restricted  Stock Awards  program  (RSA),  both of
     which were established pursuant to the Company's 1997 Equity Incentive Plan
     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 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 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 and is reduced by any  forfeitures.
     Effective  January 1, 2005, new awards granted pursuant to the PSSP will be
     payable in Company common stock rather than in cash.

                                      111
<PAGE>

     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  $46.95,  $39.53 and $44.27 in
     2004, 2003 and 2002,  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:

--------------------------------------------------------------
                           2004       2003        2002
--------------------------------------------------------------
Beginning balance        944,883    950,180     674,511
Granted                  154,500    180,200     365,920
Vested                  (367,107)  (151,677)    (75,200)
Forfeited                (87,100)   (33,820)    (15,051)
--------------------------------------------------------------
Ending balance           645,176    944,883     950,180
--------------------------------------------------------------

     The total amount expensed for other stock-based  compensation plans was $10
     million, $27 million and $17 million in 2004, 2003 and 2002, 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 nonvested 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)                                   2004       2003       2002
---------------------------------------------------------------------------
Weighted-average common shares - basic         242.2      237.2      217.2
Restricted stock awards                           .8        1.0         .8
Stock options                                     .1          -         .2
---------------------------------------------------------------------------
Weighted-average shares - fully diluted        243.1      238.2      218.2
---------------------------------------------------------------------------

     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
     3.6 million,  4.1 million and 4.8 million for the years ended  December 31,
     2004, 2003 and 2002, respectively.  There were 3.0 million, 5.3 million and
     92 thousand stock options  outstanding at December 31, 2004, 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)                                           2004        2003
-----------------------------------------------------------------------------
Loss on cash flow hedges                              $  (28)      $ (36)
Minimum pension liability adjustments                   (142)        (16)
Foreign currency translation and other                     6           2
-----------------------------------------------------------------------------
Total accumulated other comprehensive loss            $ (164)      $ (50)
-----------------------------------------------------------------------------

                                      112
<PAGE>


12.  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, 2004 and 2003 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>

13.  DEBT AND CREDIT FACILITIES

     A. Debt and Credit Facilities

     At December 31, the  Company's  long-term  debt  consisted of the following
     (maturities and weighted-average interest rates at December 31, 2004):

                                      113
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------------------
(in millions)                                                          2004          2003
-----------------------------------------------------------------------------------------------
Progress Energy, Inc.
Senior unsecured notes, maturing 2006-2031                 6.90%      $ 4,300      $ 4,800
Draws on revolving credit agreement, expiring 2009         3.19%          160            -
Unamortized fair value hedge gain, net                                     12           19
Unamortized premium and discount, net                                     (23)         (27)
-----------------------------------------------------------------------------------------------
                                                                        4,449        4,792
-----------------------------------------------------------------------------------------------
Progress Energy Carolinas, Inc.
First mortgage bonds, maturing 2005-2033                   6.33%        1,600        1,900
Pollution control obligations, maturing 2017-2024          1.98%          669          708
Unsecured notes, maturing 2012                             6.50%          500          500
Medium-term notes, maturing 2008                           6.65%          300          300
Unamortized premium and discount, net                                     (19)         (22)
-----------------------------------------------------------------------------------------------
                                                                        3,050        3,386
-----------------------------------------------------------------------------------------------
Progress Energy Florida, Inc.
First mortgage bonds, maturing 2008-2033                   5.60%        1,330        1,330
Pollution control obligations, maturing 2018-2027          1.67%          241          241
Medium-term notes, maturing 2005-2028                      6.76%          337          379
Draws on revolving credit agreement, expiring 2006         2.95%           55            -
Unamortized premium and discount, net                                      (3)          (3)
-----------------------------------------------------------------------------------------------
                                                                        1,960        1,947
-----------------------------------------------------------------------------------------------
Florida Progress Funding Corporation (See Note 19)
Debt to affiliated trust, maturing 2039                    7.10%          309          309
Unamortized premium and discount, net                                     (39)         (39)
-----------------------------------------------------------------------------------------------
                                                                          270          270
-----------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2006-2008                      6.84%          140          165
Miscellaneous notes                                                         1            1
-----------------------------------------------------------------------------------------------
                                                                          141          166
-----------------------------------------------------------------------------------------------
Progress Genco Ventures, LLC
Variable rate project financing, maturing 2007                              -          241
-----------------------------------------------------------------------------------------------
Current portion of long-term debt                                        (349)        (868)
-----------------------------------------------------------------------------------------------
        Total long-term debt                                          $ 9,521      $ 9,934
-----------------------------------------------------------------------------------------------
</TABLE>

     At December 31,  2004,  the Company had  committed  lines of credit used to
     support its commercial  paper  borrowings.  The Progress  Energy  five-year
     credit  facility  and the PEF  three-year  credit  facility are included in
     long-term  debt.  All other credit  facilities  are included in  short-term
     obligations. At December 31, 2004, the Company had $260 million outstanding
     under its credit  facilities  classified  as  short-term  obligations  at a
     weighted-average  interest rate of 3.18%. No amount was  outstanding  under
     the Company's  committed  lines of credit at December 31, 2003. The Company
     is required to pay minimal  annual  commitment  fees to maintain its credit
     facilities.

     The following table summarizes the Company's credit facilities:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
   --------------------------------------------------------------------------------------------------------------
   (in millions)
    Company                          Description                       Total        Outstanding     Available
   --------------------------------------------------------------------------------------------------------------
   Progress Energy, Inc.             5-Year (expiring 8/5/09)       $ 1,130          $ 160          $ 970
   Progress Energy Carolinas, Inc.   364-Day (expiring 7/27/05)         165             90             75
   Progress Energy Carolinas, Inc.   3-Year (expiring 7/31/05)          285              -            285
   Progress Energy Florida, Inc.     364-Day (expiring 3/29/05)         200            170             30
   Progress Energy Florida, Inc.     3-Year (expiring 4/01/06)          200             55            145
   Less: amounts reserved(a)                                                                         (574)
   --------------------------------------------------------------------------------------------------------------
   Total credit facilities                                          $ 1,980          $ 475          $ 931
   --------------------------------------------------------------------------------------------------------------
</TABLE>
     (a)  To the extent amounts are reserved for commercial paper outstanding or
          backing  letters  of credit,  they are not  available  for  additional
          borrowings.

                                      114
<PAGE>

     At December 31, 2004 and 2003, the Company had $424 million and $4 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, 2004 and 2003 were 2.77% and
     2.25%,  respectively.  At December 31, 2004,  the Company has reserved $150
     million of its lines of credit for backing of letters of credit.

     Both  Progress  Energy  and  PEF  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, 2004.

     On January 31, 2005, Progress Energy, Inc., entered into a new $600 million
     revolving credit agreement,  which expires December 30, 2005. This facility
     was added to provide additional  liquidity during 2005 due in part to storm
     restoration  costs incurred in Florida  during 2004.  The credit  agreement
     includes a defined  maximum  total debt to total capital ratio of 68% and a
     minimum  interest  coverage  ratio of 2.5 to 1. The credit  agreement  also
     contains  various  cross-default  and  other  acceleration  provisions.  On
     February 4, 2005,  $300  million was drawn under the new facility to reduce
     commercial paper and bank loans outstanding.

     The combined  aggregate  maturities of long-term debt for 2005 through 2009
     are approximately $349 million,  $963 million,  $674 million,  $827 million
     and $560 million, respectively.

     B. Covenants and Default Provisions

     FINANCIAL COVENANTS

     Progress  Energy's,  PEC's and PEF's credit lines 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  include a defined maximum total debt to total
     capital ratio. At December 31, 2004, the maximum and calculated  ratios for
     the companies, pursuant to the terms of the agreements, are as follows:

-------------------------------------------------------------------------
Company                               Maximum Ratio    Actual Ratio (a)
-------------------------------------------------------------------------
Progress Energy, Inc.                      65%               60.7%
Progress Energy Carolinas, Inc.            65%               52.3%
Progress Energy Florida, Inc.              65%               50.8%
-------------------------------------------------------------------------
     (a)  Indebtedness  as  defined  by the  bank  agreements  includes  certain
          letters  of  credit  and  guarantees  that  are  not  recorded  on the
          Consolidated Balance Sheets.

     Progress  Energy's  364-day  credit  facility  and both PEF's  364-day  and
     three-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, 2004,  the ratios were 4.00 to 1 and 7.93 to 1 for the Company
     and PEF, respectively.

     In March 2005,  Progress  Energy,  Inc.'s  five-year  credit  facility  was
     amended to increase the maximum  total debt to total capital ratio from 65%
     to 68% in  anticipation  of the  potential  impacts of proposed  accounting
     rules for uncertain tax positions. See Notes 2 and 23E.

     MATERIAL ADVERSE CHANGE CLAUSE

     The credit facilities of Progress Energy,  PEC, and PEF include a provision
     under  which  lenders  could  refuse  to  advance  funds in the  event of a
     material  adverse  change  (MAC)  in the  borrower's  financial  condition.
     Pursuant to the terms of Progress Energy's five-year credit facility,  even
     in the event of a MAC, Progress Energy may continue to borrow funds so long
     as the proceeds are used to repay maturing commercial paper balances.

     CROSS-DEFAULT PROVISIONS

     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 applies only to Progress Energy and its significant  subsidiaries
     (i.e.,  PEC, Florida Progress,  PEF, Progress Capital Holdings,  Inc. (PCH)
     and Progress Fuels).

                                      115
<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 apply only 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. 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, 2004,  none of PEC's
     retained earnings was 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, 2004,  PEC's common
     stock equity was approximately 52.2% 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, 2004,  none of PEF's  retained  earnings
     was 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, 2004,  PEF's common
     stock equity was approximately 54.4% of total capitalization.

     C. Collateralized Obligations

     PEC's and PEF's first mortgage bonds are collateralized 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,
     2004,  PEC and PEF had a total  of  approximately  $3.84  billion  of first
     mortgage bonds  outstanding,  including those related to pollution  control
     obligations. Each mortgage allows the issuance of additional mortgage bonds
     upon the satisfaction of certain conditions.

     D. Progress Genco Ventures, LLC (Genco) Bank Facility

     In December 2004,  Genco repaid its bank facility and recorded a $9 million
     pre-tax loss ($6 million after-tax) in other, net on the extinguishment. At
     that time,  the related  $195  million  notional  amount of  interest  rate
     collars  in place to hedge  floating  interest  rate  exposure  on the bank
     facility  was  terminated  and  pre-tax  deferred  losses of $6 million ($4
     million after-tax) were reclassified into earnings in other, net due to the
     discontinuance  of  the  hedges.  The  facility  was  obtained  to be  used
     exclusively  for  expansion  of  its  nonregulated   generation  portfolio.
     Borrowings under this facility were secured by the assets in the generation
     portfolio.  The facility was for up to $260 million,  of which $241 million
     had been drawn at December 31,  2003.  Borrowings  under the facility  were
     restricted for the operations,  construction,  repayments and other related
     charges of the credit facility for the development projects.  Cash held and

                                      116
<PAGE>

     restricted  to  operations  was $24 million at December 31,  2003,  and was
     included in other current  assets.  Cash held and  restricted for long-term
     purposes  was $9  million  at  December  31,  2003,  respectively,  and was
     included in other assets and deferred  debits on the  Consolidated  Balance
     Sheets.

     E. Guarantees of Subsidiary Debt

     See Note 19 on related party  transactions  for a discussion of obligations
     guaranteed or secured by affiliates.

     F. 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 18.

14.  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, 2004, and 2003,  investments in company-owned
     life  insurance  and other benefit plan assets,  with  carrying  amounts of
     approximately $220 million and $210 million,  respectively, are included in
     miscellaneous  other property and investments in the  Consolidated  Balance
     Sheets  and  approximate  fair  value  due to  the  short  maturity  of the
     instruments.  Other  instruments,   including  short-term  investments, are
     presented at fair value in accordance with GAAP. The carrying amount of the
     Company's long-term debt, including current maturities,  was $9.870 billion
     and  $10.802  billion at  December  31,  2004 and 2003,  respectively.  The
     estimated  fair value of this debt,  as obtained  from quoted market prices
     for the same or similar issues,  was $10.843 billion and $11.917 billion at
     December 31, 2004 and 2003, respectively.

     External trust funds have been established to fund certain costs of nuclear
     decommissioning  (See Note 6D). 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.

15.  INCOME TAXES

     Deferred income taxes have been provided for temporary  differences.  These
     occur when there are differences  between 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.   To  the  extent  that  the
     establishment of deferred income taxes under SFAS No. 109,  "Accounting for
     Income  Taxes,"  (SFAS No. 109) 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.

                                      117
<PAGE>

     Accumulated deferred income tax assets (liabilities) at December 31 are:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------------
(in millions)                                                     2004        2003
-----------------------------------------------------------------------------------------
Current deferred tax asset
   Unbilled revenue                                            $     35         $ 18
   Other                                                             86           69
-----------------------------------------------------------------------------------------
 Total current deferred tax asset                                   121           87
-----------------------------------------------------------------------------------------
Noncurrent deferred tax asset (liability)
   Investments                                                       73            8
   Supplemental executive retirement plans                           31           30
   Other post-employment benefits (OPEB)                            126          119
   Other pension plans                                              (15)         (97)
   Goodwill                                                          34           46
   Accumulated depreciation and property cost differences        (1,374)      (1,436)
   Deferred costs                                                   (13)          26
   Deferred storm costs                                            (113)           -
   Deferred fuel                                                    (55)          31
   Federal income tax credit carry forward                          779          683
   State net operating loss carry forward                            47           42
   Valuation allowance                                              (47)         (42)
   Miscellaneous other temporary differences, net                    43          (16)
-----------------------------------------------------------------------------------------
Total noncurrent deferred tax liabilities                          (484)        (606)
-----------------------------------------------------------------------------------------
 Less amount included in other assets and deferred debits            10            9
-----------------------------------------------------------------------------------------
Net noncurrent deferred tax liabilities                        $   (494)    $   (615)
-----------------------------------------------------------------------------------------
</TABLE>

     Total  deferred  income tax  liabilities  were  $2,797  million  and $2,662
     million at December 31, 2004 and 2003, respectively.  Total deferred income
     tax assets were $2,434  million and $2,143 million at December 31, 2004 and
     2003,  respectively.   Total  noncurrent  income  tax  liabilities  on  the
     Consolidated  Balance  Sheets at December  31, 2004 and 2003  include  $105
     million and $86 million, respectively,  related to probable tax liabilities
     on which the  Company  accrues  interest  that  would be  payable  with the
     related tax amount in future years.

     The federal income tax credit carry forward at December 31, 2004,  consists
     of $749 million of alternative  minimum tax credit with an indefinite carry
     forward  period and $30  million of general  business  credit  with a carry
     forward period that will begin to expire in 2020.

     As of December 31, 2004,  the Company had a state net operating  loss carry
     forward of $79 million, which will begin to expire in 2007.

     The  Company  established  additional  valuation  allowances  of $5 million
     during 2004 and 2003 and $12 million during 2002, due to the uncertainty of
     realizing  certain  future state tax benefits.  The Company  believes it is
     more likely than not that the results of future  operations  will  generate
     sufficient  taxable  income to allow for the  utilization  of the remaining
     deferred tax assets.  Progress  Energy  decreased its 2004 beginning of the
     year  valuation  allowance  by $8  million  for a change  in  circumstances
     related to net operating losses.

     The  Company  establishes  accruals  for certain  tax  contingencies  when,
     despite  the  belief  that the  Company's  tax return  positions  are fully
     supported,  the Company  believes that certain  positions may be challenged
     and that it is probable the Company's positions may not be fully sustained.
     The Company is under continuous examination by the Internal Revenue Service
     and other tax authorities and accounts for potential losses of tax benefits
     in accordance with SFAS No. 5. At December 31, 2004 and 2003, respectively,
     the Company  had  recorded  $60 million and $56 million of tax  contingency
     reserves,  excluding accrued interest and penalties,  which are included in
     other current liabilities on the Consolidated  Balance Sheets.  Considering
     all tax contingency reserves, the Company does not expect the resolution of
     these matters to have a material impact on its financial position or result
     of operations.  All tax contingency  reserves relate to capitalization  and
     basis  issues  and do not  relate  to any  potential  disallowances  of tax
     credits from synthetic fuel production (See Note 23E).

                                      118
<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>
------------------------------------------------------------------------------------
                                                   2004         2003         2002
------------------------------------------------------------------------------------
Effective income tax rate                          13.5%      (15.8)%      (40.0)%
State income taxes, net of federal benefit         (6.9)       (3.3)        (8.2)
AFUDC amortization                                 (0.5)       (1.4)        (5.2)
Federal tax credits                                25.6        50.4         78.0
Investment tax credit amortization                  1.6         2.3          4.7
ESOP dividend deduction                             1.8         2.1          3.8
Other differences, net                             (0.1)        0.7          1.9
------------------------------------------------------------------------------------
Statutory federal income tax rate                  35.0%       35.0%        35.0%
------------------------------------------------------------------------------------

     Income  tax  expense  (benefit)  applicable  to  continuing  operations  is
     comprised of:

------------------------------------------------------------------------------------
(in millions)                                     2004          2003         2002
------------------------------------------------------------------------------------
Current  -  federal                              $ 127        $   127     $  195
            state                                   76             54         67
Deferred -  federal                                (84)          (255)      (379)
            state                                   10            (21)       (23)
Investment tax credit                              (14)           (16)       (18)
------------------------------------------------------------------------------------
      Total income tax expense (benefit)         $ 115        $  (111)    $ (158)
------------------------------------------------------------------------------------
</TABLE>

     The company has recognized tax benefits from state net operating loss carry
     forwards in the amount of $7 million during 2004 and $3 million during 2003
     and 2002.

     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 (See
     Note 23E).

16.  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  unrealized  loss/gain  recognized  due to these  market
     fluctuations is recorded in other,  net on the  consolidated  statements of
     income (See Note 21).  The  liability,  included in other  liabilities  and
     deferred  credits,  at December 31, 2004 and 2003,  was $13 million and $23
     million, respectively.

17.  BENEFIT PLANS

     A. Postretirement Benefits

     The Company and some of its  subsidiaries  have a  noncontributory  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.

                                      119
<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)                                            2004         2003        2002      2004     2003     2002
----------------------------------------------------------------------------------------------------------------------
Service cost                                          $      54   $     52  $       45   $     12 $     15 $     13
Interest cost                                               110        108         106         31       33       32
Expected return on plan assets                             (155)      (144)       (161)        (5)      (4)      (5)
Amortization of actuarial (gain) loss                        21         25           2          4        5        1
Other amortization, net                                       -          -           -          1        4        4
----------------------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit)                         $      30   $     41   $      (8)   $    43 $     53 $     45
Additional cost / (benefit) recognition (Note 17B)          (16)       (18)         (7)         2        2        2
----------------------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit) recognized              $      14   $     23   $     (15)   $    45 $     55 $     47
----------------------------------------------------------------------------------------------------------------------
</TABLE>

     The net periodic cost for other  postretirement  benefits  decreased during
     2004 due to the  implementation  of FASB Staff Position 106-2 (See Note 2).
     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
     five-year  averaging  method for a portion of its  pension  assets and fair
     value for the  remaining  portion.  The Company has  historically  used the
     five- 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)                                           2004         2003          2004          2003
--------------------------------------------------------------------------------------------------------
Projected benefit obligation at January 1           $    1,772   $    1,694    $      472    $      514
Service cost                                                54           52            12            15
Interest cost                                              110          108            31            33
Disposition of NCNG                                          -          (39)            -           (13)
Benefit payments                                           (98)         (94)          (23)          (24)
Plan amendment                                              21            -             -             -
Actuarial loss (gain)                                      102           51            46           (53)
--------------------------------------------------------------------------------------------------------
Obligation at December 31                                1,961        1,772           538           472
Fair value of plan assets at December 31                 1,774        1,631            70            65
--------------------------------------------------------------------------------------------------------
Funded status                                             (187)        (141)         (468)         (407)
Unrecognized transition obligation                           -             -           10            25
Unrecognized prior service cost                             24            4             6             7
Unrecognized net actuarial loss                            530          505            94            40
Minimum pension liability adjustment                      (470)         (23)            -             -
--------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net          $     (103)  $      345    $     (358)    $    (335)
    (Note 17B)
--------------------------------------------------------------------------------------------------------
</TABLE>

     The 2003 OPEB  obligation  information  above has been  restated due to the
     implementation of FASB Staff Position 106-2 (See Note 2).

                                      120
<PAGE>

     The net accrued  pension  cost of $103  million at December  31,  2004,  is
     recognized in the  Consolidated  Balance Sheets as prepaid  pension cost of
     $42 million and accrued benefit cost of $145 million,  which is included in
     accrued  pension and other  benefits.  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 accrued pension and other benefits. The
     defined  benefit  pension plans with  accumulated  benefit  obligations  in
     excess of plan assets had  projected  benefit  obligations  totaling  $1.72
     billion and $125 million at December 31, 2004 and 2003, respectively. Those
     plans had accumulated benefit  obligations  totaling $1.71 billion and $117
     million at December 31, 2004 and 2003, respectively,  $1.57 billion of plan
     assets at December 31, 2004,  and no plan assets at December 31, 2003.  The
     total  accumulated  benefit  obligation for pension plans was $1.90 billion
     and $1.72 billion at December 31, 2004 and 2003, respectively.  The accrued
     OPEB  cost is  included  in  accrued  pension  and  other  benefits  in the
     Consolidated Balance Sheets.

     A minimum  pension  liability  adjustment  of $470  million was recorded at
     December 31, 2004. This  adjustment  resulted in a charge of $24 million to
     intangible  assets, a $150 million charge to a  pension-related  regulatory
     liability  (See Note  17B),  a $67  million  charge to a  regulatory  asset
     pursuant  to a recent  FPSC order and a pre-tax  charge of $229  million to
     accumulated other comprehensive loss, a component of common stock equity. 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.

     Reconciliations of the fair value of plan assets are:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------
                                                                              Other Postretirement
                                                  Pension Benefits                  Benefits
                                              -----------------------------   ---------------------
(in millions)                                   2004            2003            2004         2003
---------------------------------------------------------------------------------------------------
Fair value of plan assets January 1             $ 1,631          $ 1,364        $  65         $ 52
Actual return on plan assets                        211              391            8           12
Disposition of NCNG                                   -              (35)           -            -
Benefit payments                                    (98)             (94)         (23)         (24)
Employer contributions                               30                5           20           25
---------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31        $ 1,774          $ 1,631        $  70         $ 65
---------------------------------------------------------------------------------------------------
</TABLE>

     In the table  above,  substantially  all employer  contributions  represent
     benefit  payments  made  directly  from Company  assets except for the 2004
     pension  amount.  The remaining  benefits  payments were made directly from
     plan  assets.  In  2004,  the  Company  made  a  required  contribution  of
     approximately $24 million directly to pension 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 2004 and 2003
     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       Target           Percentage of Plan
                            Allocations     Assets at Year End     Allocations        Assets at Year End
                            -------------  --------------------   --------------     ------------------------
Asset Category                  2005           2004        2003       2005              2004         2003
-------------------------------------------------------------------------------------------------------------
  Equity - domestic              48%            47%         49%        34%               34%             35%
  Equity - international         15%            21%         22%        11%               15%             16%
  Debt - domestic                12%             9%         11%        37%               35%             37%
  Debt - international           10%            11%         11%         7%                8%              7%
  Other                          15%            12%          7%        11%                8%              5%
-------------------------------------------------------------------------------------------------------------
  Total                         100%           100%        100%       100%              100%            100%
-------------------------------------------------------------------------------------------------------------
</TABLE>

     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.

                                      121
<PAGE>

     In 2005, the Company expects to make no 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 2005 through 2009 and in total for 2010-2014, in millions,
     are approximately $113, $110, $115, $124, $131 and $794, respectively.  The
     expected  benefit  payments  for the OPEB plan for 2005 through 2009 and in
     total for 2010-2014, in millions, are approximately $32, $34, $37, $39, $41
     and $230,  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 Company expects to begin
     receiving prescription drug-related federal subsidies in 2006 (See Note 2),
     and  the  expected  subsidies  for  2006  through  2009  and in  total  for
     2010-2014,  in  millions,  are  approximately  $3,  $3,  $3,  $4  and  $24,
     respectively.  The  expected  benefit  payments  above do not  reflect  the
     potential effects of a 2005 voluntary enhanced retirement program (See Note
     24).

     The  following  weighted-average  actuarial  assumptions  were  used in the
     calculation of the year-end obligation:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------------------
                                                                                   Other Postretirement
                                                          Pension Benefits               Benefits
                                                        ----------------------   ------------------------
(in millions)                                             2004       2003          2004         2003
---------------------------------------------------------------------------------------------------------
Discount rate                                               5.90%      6.30%        5.9%        6.30%
Rate of increase in future compensation
  Bargaining                                                3.50%      3.50%          -            -
  Supplementary plans                                       5.25%      5.00%          -            -
Initial medical cost trend rate for pre-Medicare
benefits                                                       -          -         7.25%        7.25%
Initial medical cost trend rate for post-Medicare
benefits                                                       -          -         7.25%        7.25%
Ultimate medical cost trend rate                               -          -         5.00%        5.25%
Year ultimate medical cost trend rate is achieved              -          -         2008         2009
---------------------------------------------------------------------------------------------------------
</TABLE>

     The Company's  primary  defined benefit  retirement plan for  nonbargaining
     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.  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
                                                      -----------------------------  ------------------------------
(in millions)                                          2004      2003      2002        2004      2003      2002
-------------------------------------------------------------------------------------------------------------------
Discount rate                                            6.30%     6.60%     7.50%       6.30%     6.60%     7.50%
Rate of increase in future compensation
  Bargaining                                             3.50%     3.50%     3.50%          -         -         -
  Nonbargaining                                             -      4.00%     4.00%          -         -         -
  Supplementary plans                                    5.00%     4.00%     4.00%          -         -         -
Expected long-term rate of return on plan assets         9.25%     9.25%     9.25%       8.50%     8.45%     8.20%
-------------------------------------------------------------------------------------------------------------------
</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 9.0% and
     9.5%. The Company has chosen to use an expected long-term rate of 9.25%.

     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 2004 would  increase by $1 million,  and
     the OPEB  obligation at December 31, 2004,  would  increase by $30 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
     2004 would decrease by $1 million,  and the OPEB obligation at December 31,
     2004, would decrease by $26 million.

                                      122
<PAGE>

     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  nonbargaining  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, 2004, and 2003 (See Note 8A). In addition,
     a portion of the prepaid  pension  cost  reflected in the table above has a
     corresponding  regulatory  liability  (See Note 8A).  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.

18.  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 Derivatives

     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
     original  liability of $38 million  associated  with the fair value loss is
     being  amortized  to  earnings  over the term of the related  contract.  At
     December 31, 2004 and 2003, the remaining liability was $26 million and $35
     million, respectively.

     ECONOMIC DERIVATIVES

     Derivative products,  primarily electricity and natural gas contracts,  are
     entered into 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  to  results of
     operations during 2004, 2003 or 2002, and the Company did not have material
     outstanding positions in such contracts at December 31, 2004 and 2003.

     In 2004, PEF entered into derivative instruments related to its exposure to
     price  fluctuations  on fuel oil purchases.  At December 31, 2004, the fair
     values of these  instruments were a $2 million  long-term  derivative asset
     position  included  in other  assets and  deferred  debits and a $5 million
     short-term   derivative   liability  position  included  in  other  current
     liabilities.  These instruments  receive regulatory  accounting  treatment.
     Gains are  recorded in  regulatory  liabilities  and losses are recorded in
     regulatory assets.

                                      123
<PAGE>

     CASH FLOW HEDGES

     Progress Energy's subsidiaries  designate a portion of commodity derivative
     instruments  as cash flow hedges  under SFAS No.  133.  The  objective  for
     holding these  instruments is to hedge  exposure to market risk  associated
     with fluctuations in the price of natural gas for the Company's  forecasted
     purchases and sales.  At December 31, 2004,  the maximum  period over which
     the Company is hedging exposures to the price variability of natural gas is
     10 years.

     The total fair value of commodity cash flow hedges at December 31, 2004 and
     2003 was as follows:

-----------------------------------------------
(millions of dollars)            2004     2003
-----------------------------------------------
Fair value of assets           $   -    $   -
Fair value of liabilities        (15)     (12)
-----------------------------------------------
Fair value, net                $ (15)   $ (12)
-----------------------------------------------

     The  ineffective  portion of commodity cash flow hedges was not material to
     the Company's results of operations for 2004, 2003 or 2002. At December 31,
     2004,  there were $9 million of after-tax  deferred  losses in  accumulated
     other  comprehensive  income  (OCI),  of which $5 million is expected to be
     reclassified   to  earnings  during  the  next  12  months  as  the  hedged
     transactions  occur.  Gains  and  losses  are  recorded  net  in  operating
     revenues.  As part of the  divestiture  of Winchester  Production  Company,
     Ltd.,  assets  in 2004,  $7  million  of  after-tax  deferred  losses  were
     reclassified  into earnings due to  discontinuance of the related cash flow
     hedges and recorded  against the gain on sale. Due to the volatility of the
     commodities  markets,  the value in OCI is subject  to change  prior to its
     reclassification into earnings.

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

     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.  Gains and losses are recorded
     in OCI and amounts  reclassified  to earnings  are included in net interest
     charges as the  hedged  transactions  occur.  The  Company  uses fair value
     hedging  strategies  to manage  its  exposure  to fixed  interest  rates on
     long-term debt. For interest rate fair value hedges, the change in the fair
     value of the hedging  derivative is recorded in net interest charges and is
     offset by the change in the fair value of the hedged item.

     The fair values of open position  interest rate hedges at December 31, 2004
     and 2003 were as follows:

-------------------------------------------------------
(in millions)                          2004    2003
-------------------------------------------------------
Interest rate cash flow hedges         $ (2)   $ (6)
Interest rate fair value hedges        $  3    $ (4)
-------------------------------------------------------

     CASH FLOW HEDGES

     The following table presents selected  information related to the Company's
     interest rate cash flow hedges  included in accumulated OCI at December 31,
     2004:

-----------------------------------------------------------------------------
  Accumulated Other Comprehensive
    Income/(Loss), net of tax(a)                Portion Expected to be
                                            Reclassified to Earnings during
       (millions of dollars)                     the Next 12 Months(b)
-----------------------------------------------------------------------------

               $ (19)                                    $ (4)
-----------------------------------------------------------------------------
     (a)  Includes amounts related to terminated hedges.
     (b)  Actual amounts that will be reclassified to earnings may vary from the
          expected  amounts  presented  above as a result of changes in interest
          rates.

                                      124
<PAGE>

     As of December 31, 2004, PEC had $110 million  notional amount of pay-fixed
     forward swaps to hedge its exposure to interest rates with regard to future
     issuances of debt  (pre-issue  hedges) and $21 million  notional  amount of
     pay-fixed  forward  starting  swaps to hedge its exposure to interest rates
     with regard to an upcoming  railcar lease. On February 4, 2005, PEC entered
     another $50 million notional amount of its pre-issue hedges.  All the swaps
     have a  computational  period of 10 years.  PEC held no interest  rate cash
     flow hedges at December 31, 2003. The ineffective  portion of interest rate
     cash flow hedges was not material to the  Company's  results of  operations
     for 2004 and 2003.

     In December 2004, Progress Ventures,  Inc. (PVI), a wholly owned subsidiary
     of Progress  Energy,  terminated  $195 million  notional amount of interest
     rate collars in place to hedge floating  interest rate exposure  associated
     with  variable-rate  long-term debt. The related debt was also extinguished
     in December 2004 (See Note 13).  Pre-tax  deferred losses of $6 million ($4
     million  after-tax) were  reclassified  into earnings in other,  net due to
     discontinuance of these cash flow hedges.

     At December 31, 2004 and 2003,  Progress  Energy,  Inc., held interest rate
     cash flow  hedges,  with a total  notional  amount of $200 million and $400
     million,  respectively,   related  to  projected  outstanding  balances  of
     commercial  paper.  The fair value of the hedges at December 31, 2004,  was
     not material to the Company's financial condition and at December 31, 2003,
     was $5 million.  The hedges  held at December  31,  2003,  were  terminated
     during the year. Amounts in accumulated other comprehensive  income related
     to these  terminated  hedges will be reclassified to earnings as the hedged
     interest payments occur.

     FAIR VALUE HEDGES

     As of December 31, 2004 and 2003, Progress Energy had $150 million notional
     amount and $850 million notional amount,  respectively,  of fixed rate debt
     swapped  to  floating  rate  debt by  executing  interest  rate  derivative
     agreements.  These  agreements  expire on various dates through March 2011.
     During 2004,  Progress Energy entered into $350 million notional amount and
     terminated $1.05 billion notional amount of interest rate swap agreements.

     At December 31, 2004 and 2003,  the Company had $9 million and $23 million,
     respectively,  of basis adjustments in long-term debt related to terminated
     interest rate fair value  hedges,  which are being  amortized  over periods
     ending in 2006 through 2011  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.

19.  RELATED PARTY TRANSACTIONS

     As a part of normal  business,  Progress  Energy and  certain  subsidiaries
     enter into various agreements providing financial or performance assurances
     to third parties. These agreements are entered into primarily to support or
     enhance the  creditworthiness  otherwise  attributed  to a subsidiary  on a
     stand-alone basis,  thereby facilitating the extension of sufficient credit
     to  accomplish  the  subsidiaries'  intended  commercial  purposes.  As  of
     December  31,  2004,  Progress  Energy  and  its  subsidiaries'  guarantees
     include:  $270 million supporting commodity  transactions,  $181 million to
     support  nuclear  decommissioning,  $536  million  related to power  supply
     agreements and $182 million for guarantees  supporting  other agreements of
     subsidiaries.  Progress  Energy also  purchased $92 million of surety bonds
     and  authorized  the  issuance  of standby  letters of credit by  financial
     institutions  of $50 million.  Florida  Progress also fully  guarantees the
     medium  term  notes  outstanding  for  Progress  Capital,  a  wholly  owned
     subsidiary  of  Florida  Progress  (See Note 13).  At  December  31,  2004,
     management   does  not  believe   conditions  are  likely  for  significant
     performance under these agreements.  To the extent liabilities are incurred
     as a result of the activities  covered by the guarantees,  such liabilities
     are included in the Balance Sheets.

     Progress  Fuels  sells  coal  to PEF  for an  insignificant  profit.  These
     intercompany   revenues  and  expenses  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 sales price through the  ratemaking  process is
     probable.  Sales,  net of  insignificant  profits,  of $331  million,  $346
     million and $329 million for the years ended  December  31, 2004,  2003 and
     2002, respectively, are included in fuel used in electric generation on the
     Consolidated Statements of Income.

     Florida  Progress  Funding  Corporation  (Funding Corp.) $309 million 7.10%
     Junior Subordinated  Deferrable Interest Notes (Subordinated Notes) are due
     to FPC  Capital  I (the  Trust).  The Trust  was  established  for the sole
     purpose of issuing $300 million Preferred Securities and using the proceeds
     thereof to purchase from Funding Corp. its Subordinated Notes due 2039. The
     Company has fully and unconditionally guaranteed the obligations of Funding
     Corp. under the Subordinated Notes (the Notes Guarantee).  In addition, the
     Company 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

                                      125
<PAGE>

     (Preferred  Securities  Guarantee).  The  Preferred  Securities  Guarantee,
     considered  together  with  the  Notes  Guarantee,  constitutes  a full and
     unconditional guarantee by the Company of the Trust's obligations under the
     Preferred  Securities.  The Subordinated  Notes and the Notes Guarantee are
     the sole assets of the Trust. The Subordinated Notes may be redeemed at the
     option of Funding  Corp.  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.  The
     yearly interest expense is $21 million and is reflected in the Consolidated
     Statements of Income.

     The Company sold NCNG to Piedmont  Natural Gas  Company,  Inc. on September
     30,  2003 (See Note 4E).  Prior to  disposition,  NCNG sold  natural gas to
     affiliates.  During the years ended  December  31, 2003 and 2002,  sales of
     natural  gas  to  affiliates  amounted  to $11  million  and  $20  million,
     respectively. These revenues are included in discontinued operations on the
     Consolidated Statements of Income.

20.  FINANCIAL INFORMATION BY BUSINESS SEGMENT

     The Company  currently  provides  services  through the following  business
     segments: PEC Electric,  PEF, Fuels, CCO and Rail Services.  Prior to 2004,
     other  nonregulated  business  activities  were reported  separately in the
     Other  segment.  These  reportable  segment  changes  reflect  the  current
     reporting  structure.  For  comparative  purposes,  the  results  have been
     restated to align with the current presentation.

     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  and  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.

     In  addition  to these  reportable  operating  segments,  the  Company  has
     Corporate and other  activities  that include  holding  company and service
     company  operations as well as other  nonregulated  business  areas.  These
     nonregulated business areas include  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 the 2004 losses is a
     $43 million pre-tax ($29 million after-tax)  settlement  agreement that SRS
     reached with the San  Francisco  United  School  District  related to civil
     proceedings.  Included in the 2002 losses are asset impairments and certain
     other  after-tax  charges related to the  telecommunications  operations of
     $225 million.  The  operations of NCNG were  reclassified  to  discontinued
     operations  and therefore  are not included in the results from  continuing
     operations  during  the  periods  reported.  The  profit  or  loss  of  the
     identified  segments  plus the loss of Corporate and Other  represents  the
     Company's total income from continuing operations.

     Products and services are sold between the various reportable segments. All
     intersegment transactions are at cost except for transactions between Fuels
     and PEF,  which are at rates set by the FPSC. In  accordance  with SFAS No.
     71, profits on intercompany  sales between PEF and Fuels are not eliminated
     if the sales  price is  reasonable  and the future  recovery of sales price
     through the ratemaking process is probable. The profits for all three years
     presented were not significant.

                                      126
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------------------------------
                              PEC                                     Rail      Corporate
(in millions)               Electric    PEF      Fuels      CCO     Services    and Other   Eliminations   Totals
-------------------------------------------------------------------------------------------------------------------
Year ended
     December 31, 2004
Revenues
    Unaffiliated             $ 3,628 $ 3,525    $ 1,179   $   240    $ 1,130     $     70     $      -     $ 9,772
    Intersegment                   -       -        331         -          1          441         (773)          -
-------------------------------------------------------------------------------------------------------------------
      Total revenues           3,628   3,525      1,510       240      1,131          511         (773)      9,772
-------------------------------------------------------------------------------------------------------------------
Depreciation and
   amortization                  570     281         93        58         21           45            -       1,068
Total interest charges,
    net                          192     114         22        17         27          361          (86)        647
Gain on sale of assets             -       -         54         -          -            3            -          57
Income tax expense
    (benefit) (a)                237     174       (230)       (1)        15          (80)           -         115
Segment profit (loss)            464     333        180        (4)        16         (236)           -         753
Total assets                  10,590   7,924        986     1,709        596       17,741      (13,553)     25,993
Capital and investment
    expenditures                 519     480        157        25         40           14            -       1,235
-------------------------------------------------------------------------------------------------------------------
Year ended
     December 31, 2003
Revenues
    Unaffiliated             $ 3,589 $ 3,152    $   928   $   170    $   846     $     56     $      -     $ 8,741
    Intersegment                   -       -        346         -          1          446         (793)          -
-------------------------------------------------------------------------------------------------------------------
      Total revenues           3,589   3,152      1,274       170        847          502         (793)      8,741
-------------------------------------------------------------------------------------------------------------------
Depreciation and
   amortization                  562     307         80        42         20           29            -       1,040
Total interest charges,          197      91         23         4         29          356          (72)        628
    net
Impairment of long-lived
    assets and investments        11       -         17         -          -           10            -         38
Income tax expense               238     147       (415)        8          2          (46)         (45)      (111)
    (benefit) (a)
Segment profit (loss)            515     295        235        20         (1)        (253)           -        811
Total assets                  10,748   7,280      1,142     1,747        586       17,955      (13,365)     26,093
Capital and investment
    expenditures                 445     526        309       338        103           35            -      1,756
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------
Year ended
   December 31, 2002
Revenues
    Unaffiliated             $ 3,539 $ 3,062    $   607   $    92    $    714    $     77     $      -     $ 8,091
    Intersegment                   -       -        329         -           5         418         (752)          -
-------------------------------------------------------------------------------------------------------------------
      Total revenues           3,539   3,062        936        92         719         495         (752)      8,091
-------------------------------------------------------------------------------------------------------------------
Depreciation and
     amortization                524     295         47        20          20          32            -         938
Total interest charges,          212     106         24       (12)         33         351          (81)        633
     net
Impairment of long-
     lived assets and              -       -          -         -          59         330            -         389
     investments
Income tax expense               237     163       (373)       16         (16)       (191)           6        (158)
     (benefit) (a)
Segment profit (loss)            513     323        176        27         (42)       (445)           -         552
Total assets                  10,139   6,678        934     1,452         529      15,872      (11,886)     23,718
Capital and investment
   expenditures                  619     550        170       682           8          73            -       2,102
-------------------------------------------------------------------------------------------------------------------
</TABLE>
     (a)  Amounts include income tax benefit  reallocation  from holding company
          to profitable subsidiaries according to an SEC order.

                                      127
<PAGE>

Geographic Data

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
    -----------------------------------------------------------------------------
    (in millions)                   U.S.       Canada        Mexico  Consolidated
    -----------------------------------------------------------------------------
    2004
    Consolidated revenues         $ 9,644       $ 112          $ 16      $ 9,772
    -----------------------------------------------------------------------------
    2003
    Consolidated revenues         $ 8,624       $ 103          $ 14      $ 8,741
    -----------------------------------------------------------------------------
    2002
    Consolidated revenues         $ 7,984        $ 93          $ 14      $ 8,091
    -----------------------------------------------------------------------------
</TABLE>

21.  OTHER INCOME AND OTHER EXPENSE

     Other  income  and  expense  includes   interest   income,   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:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------------
(in millions)                                                  2004       2003        2002
---------------------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income             $   32     $   27       $  33
DIG Issue C20 amortization (Note 18A)                             9          2           -
Contingent value obligation unrealized gain (Note 16)             9          -          28
Investment gains                                                  -          5           -
AFUDC equity                                                     11         14           8
Gain on sale of property and partnership investment              12         25          12
Other                                                            34         17          42
-------------------------------------------------------------------------------------------
    Total other income                                       $  107     $   90       $ 123
-------------------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses           $   20     $   20       $  29
Donations                                                        10         12          19
Investment losses                                                 6          -           -
Contingent value obligation unrealized loss (Note 16)             -          9           -
Loss from equity investments                                      6         40          21
Loss on debt extinguishment and interest rate collars
   (Note 13D)                                                    15          -           -
Other                                                            42         25          27
-------------------------------------------------------------------------------------------
   Total other expense                                       $   99     $  106       $  96
-------------------------------------------------------------------------------------------
Other, net                                                   $    8     $  (16)      $  27
-------------------------------------------------------------------------------------------
</TABLE>

     Nonregulated energy and delivery services include power protection services
     and mass market programs  (surge  protection,  appliance  services and area
     light  sales) and  delivery,  transmission  and  substation  work for other
     utilities.

22.  ENVIRONMENTAL MATTERS

     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

     The provisions of the Comprehensive  Environmental  Response,  Compensation
     and  Liability  Act of 1980,  as  amended  (CERCLA),  authorize  the EPA to
     require  the  cleanup  of  hazardous  waste  sites.  This  statute  imposes
     retroactive joint and several liabilities. Some states, including North and
     South  Carolina,  have similar  types of  legislation.  The Company and its
     subsidiaries are periodically  notified by regulators including the EPA and
     various state  agencies of their  involvement  or potential  involvement in
     sites  that  may  require  investigation  and/or  remediation.   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. The Company also
     is currently in the process of assessing  potential  costs and exposures at
     other sites. For all sites, as 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.  A discussion of sites by legal
     entity follows.

                                      128
<PAGE>

     Various  organic  materials  associated with the production of manufactured
     gas,  generally  referred to as coal tar, are  regulated  under federal and
     state laws. PEC and PEF are each potentially  responsible parties (PRPs) at
     several manufactured gas plant (MGP) sites.

     PEC,  PEF and  Progress  Fuels  Corporation  have  filed  claims  with  the
     Company's  general  liability  insurance  carriers to recover costs arising
     from 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.

     PEC

     There are nine former MGP sites and a number of other sites associated with
     PEC that have required or are anticipated to require  investigation  and/or
     remediation costs.

     During the fourth  quarter of 2004,  the EPA  advised  PEC that it had been
     identified as a PRP at the Ward Transformer site located in Raleigh,  North
     Carolina.  The EPA  offered  PEC  and 34  other  PRPs  the  opportunity  to
     negotiate  cleanup of the site and reimbursement of less than $2 million to
     the EPA for EPA's past  expenditures in addressing  conditions at the site.
     Although a loss is  considered  probable,  an agreement  among PRPs has not
     been reached;  consequently,  it is not possible at this time to reasonably
     estimate the total amount of PEC's  obligation for  remediation of the Ward
     Transformer site.

     At December 31, 2004 and 2003,  PEC's  accruals for probable and  estimable
     costs related to various  environmental  sites, which are included in other
     liabilities and deferred  credits and are expected to be paid out over many
     years, were:

-----------------------------------------------------------------
(in millions)                                   2004        2003
-----------------------------------------------------------------
Insurance fund                                  $  7       $   9
Transferred from NCNG at time of sale              2           2
-----------------------------------------------------------------
Total accrual for environmental sites           $ 9        $ 11
-----------------------------------------------------------------

     PEC  received   insurance   proceeds  to  address  costs   associated  with
     environmental  liabilities  related to its involvement with some sites. All
     eligible  expenses  related to these are  charged  against a specific  fund
     containing  these proceeds.  PEC spent  approximately $2 million related to
     environmental  remediation in 2004. PEC is unable to provide an estimate of
     the reasonably  possible total  remediation  costs beyond what is currently
     accrued because 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.
     Because the extent of environmental  impact,  allocation among PRPs for all
     sites,  remediation  alternatives  (which could involve  either  minimal or
     significant  efforts),  and concurrence of the regulatory  authorities have
     not yet reached the stage where a  reasonable  estimate of the  remediation
     costs  can be made,  PEC  cannot  determine  the  total  costs  that may be
     incurred in connection  with the  remediation of all sites at this time. It
     is  anticipated  that  sufficient  information  will become  available  for
     several  sites  during  2005  to  allow  a  reasonable  estimate  of  PEC's
     obligation for those sites to be made.

     PEF

     At December 31, 2004 and 2003,  PEF's  accruals for probable and  estimable
     costs related to various  environmental  sites, which are included in other
     liabilities and deferred  credits and are expected to be paid out over many
     years, were:

------------------------------------------------------------------------------
(in millions)                                                 2004       2003
------------------------------------------------------------------------------
Remediation of distribution and substation transformers       $ 27       $ 12
MGP and other sites                                             18          6
------------------------------------------------------------------------------
Total accrual for environmental sites                         $ 45       $ 18
------------------------------------------------------------------------------

                                      129
<PAGE>

     PEF has received  approval  from the FPSC for recovery of costs  associated
     with the remediation of distribution  and substation  transformers  through
     the  Environmental  Cost Recovery Clause (ECRC).  Under agreements with the
     Florida  Department  of  Environmental  Protection  (FDEP),  PEF  is in the
     process of examining  distribution  transformer  sites and substation sites
     for potential  equipment integrity issues that could result in the need for
     mineral oil  impacted  soil  remediation.  Through  2004 PEF has reviewed a
     number of distribution  transformer sites and substation sites. PEF expects
     to have completed its review of distribution  transformer  sites by the end
     of 2007 and has completed the review of  substation  sites in 2004.  Should
     further sites be  identified,  PEF believes that any estimated  costs would
     also be  recovered  through  the ECRC  clause.  In  2004,  PEF  accrued  an
     additional $19 million due to  identification of additional sites requiring
     remediation,  and spent approximately $4 million related to the remediation
     of  transformers.  PEF has  recorded a  regulatory  asset for the  probable
     recovery of these costs through the ECRC.

     The  amounts for MGP and other  sites,  in the table  above,  relate to two
     former MGP sites and other sites  associated with PEF that have required or
     are anticipated to require  investigation and/or remediation.  In 2004, PEF
     received  approximately $12 million in insurance claim settlement  proceeds
     and recorded a related accrual for associated  environmental  expenses. The
     proceeds  are  restricted  for  use in  addressing  costs  associated  with
     environmental  liabilities.  Expenditures  for the year  were  less than $1
     million.

     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.  Because the extent of environmental  impact,
     allocation among PRPs for all sites,  remediation alternatives (which could
     involve  either  minimal or significant  efforts),  and  concurrence of the
     regulatory  authorities  have  not  yet  advanced  to  the  stage  where  a
     reasonable  estimate of the remediation costs can be made, at this time PEF
     is unable to provide an estimate of its obligation to remediate these sites
     beyond what is currently  accrued.  As more activity occurs at these sites,
     PEF will assess the need to adjust the  accruals.  It is  anticipated  that
     sufficient  information  will become available in 2005 to make a reasonable
     estimate of PEF's obligation for one of the MGP sites.

     The Florida Legislature passed risk-based corrective action (RBCA, known as
     Global RBCA) legislation in the 2003 regular session. Risk-based corrective
     action   generally  means  that  the  corrective   action   prescribed  for
     contaminated  sites can correlate to the level of human health risk imposed
     by the  contamination at the property.  The Global RBCA law expands the use
     of the risk-based  corrective action to all contaminated sites in the state
     that are not currently in one of the state's waste  cleanup  programs.  The
     FDEP  developed the rules  required by the RBCA statute,  holding  meetings
     with interested  stakeholders and hosting public workshops.  The rules have
     the  potential  for  making  future  cleanups  in  Florida  more  costly to
     complete.  The  Global  RBCA rule was  adopted  at the  February  2,  2005,
     Environmental  Review Commission hearing.  The effective date of the Global
     RBCA rule is expected to be  announced  in April 2005.  The Company and PEF
     are in the process of assessing the impact of this matter.

     FLORIDA PROGRESS CORPORATION

     In 2001, FPC established a $10 million  accrual to address  indemnities and
     retained an environmental  liability associated with the sale of its Inland
     Marine  Transportation  business.  In 2003,  the  accrual was reduced to $4
     million based on a change in estimate. During 2004, expenditures related to
     this liability were not material to the Company's financial  condition.  As
     of December 31, 2004, the remaining  accrual balance was  approximately  $3
     million.  FPC measures its liability for these exposures based on estimable
     and probable remediation scenarios.

     Certain  historical  sites  are  being  addressed  voluntarily  by FPC.  An
     immaterial accrual has been established to address  investigation  expenses
     related to these sites.  At this time,  the Company  cannot  determine  the
     total costs that may be incurred in connection with these sites.

     RAIL

     Rail Services is voluntarily  addressing certain historical waste sites. At
     this  time,  the  Company  cannot  determine  the total  costs  that may be
     incurred in connection with these sites.

                                      130
<PAGE>

     AIR QUALITY

     Congress is considering  legislation  that would require  reductions in air
     emissions of 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 that could be material to the Company's
     consolidated financial position or results of operations. Control equipment
     that will be installed on North Carolina  fossil  generating  facilities as
     part of the NC Clean Air  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 changes
     at those  facilities were subject to New Source Review  requirements or New
     Source Performance Standards under the Clean Air Act. The Company was asked
     to provide information to the EPA as part of this initiative and cooperated
     in supplying 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,  in excess of $1.0 billion.
     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 the Federal Appeals Court and
     its  implementation  stayed.  In  July  2004,  the  EPA  announced  it will
     reconsider   certain  issues  arising  from  the  final  routine  equipment
     replacement rule. The comment period closed on August 30, 2004. The Company
     cannot predict the outcome of this matter.

     In 1998,  the EPA published a final rule under Section 110 of the Clean Air
     Act  addressing  the  regional  transport  of ozone (NOx SIP  Call).  Total
     capital  expenditures to meet the  requirements of the NOx SIP Call Rule in
     North and South Carolina could reach  approximately $370 million.  To date,
     the Company has spent approximately $282 million related to these projected
     amounts.  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. Parties unrelated to the Company have undertaken efforts to have
     Georgia  excluded from the rule and its  requirements.  Georgia has not yet
     submitted  a state  implementation  plan to comply with the Section 110 NOx
     SIP Call. The Company cannot predict the outcome of this matter in Georgia.

     In 1997, the EPA issued final  regulations  establishing a new 8-hour ozone
     standard.  In April  2004,  the EPA  identified  areas that do not meet the
     standard.  The states  with  identified  areas,  including  North and South
     Carolina,  are  proceeding  with the  implementation  of the federal 8-hour
     ozone  standard.  Both states  promulgated  final  regulations,  which will
     require PEC to install NOx  controls  under the states'  programs to comply
     with the 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  requirements  for  additional  controls  at some
     units. The Company cannot predict the outcome of this matter.

     In June 2002,  the NC Clean Air  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 projects that its capital
     costs to meet these emission targets will total  approximately $895 million
     by the end of 2013.  PEC has expended  approximately  $108 million of these
     capital costs through  December 31, 2004.  PEC currently has  approximately
     5,100  MW of  coal-fired  generation  capacity  in North  Carolina  that is
     affected by this Act.  The law  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 law 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.  The  law  requires  PEC  to  amortize  $569  million,
     representing 70% of the original cost estimate of $813 million,  during the
     five-year rate freeze period.  PEC recognized  amortization of $174 million
     and  $74  million  for  the  years  ended  December  31,  2004,  and  2003,
     respectively,  and has recognized  $248 million in cumulative  amortization
     through December 31, 2004. The remaining  amortization  requirement of $321
     million will be recorded over the  three-year  period  ending  December 31,
     2007. The law permits PEC the flexibility to vary the amortization schedule
     for  recording  of the  compliance  costs from none up to $174  million per
     year. The NCUC will hold a hearing prior to December 31, 2007, to determine
     cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC
     entered into an agreement  with the State of North  Carolina to transfer to
     the  State  certain  NOx and SO2  emissions  allowances  that  result  from
     compliance with the collective NOx and SO2 emissions limitations set out in
     the law.  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.

                                      131
<PAGE>

     In 1997,  the EPA's  Mercury  Study  Report and Utility  Report to Congress
     concluded  that mercury is not a risk to the average  person in America 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 alternative control
     plans that would limit mercury emissions from coal-fired power plants.  The
     final rule was released on March 15,  2005.  The EPA's rule  establishes  a
     mercury cap and trade  program for  coal-fired  power plants that  requires
     limits to be met in two phases,  in 2010 and 2018. The Company is reviewing
     the final rule.  Installation of additional air quality  controls is likely
     to be needed to meet the mercury rule's requirements.  Compliance plans and
     the cost to  comply  with  the rule  will be  determined  once the  Company
     completes its review.

     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.  As proposed,  the rule may require the Company to
     install  additional  pollution  controls on its residual  oil-fired  units,
     resulting  in  significant  capital  expenditures.  PEC does not have units
     impacted by this proposal;  PEF has eight units that are affected, and they
     currently  do not have  pollution  controls  in place  that  would meet the
     proposed  requirements  of the nickel rule. The EPA expects to finalize the
     nickel rule in March 2005.  Compliance  costs will be determined  following
     promulgation of the rule.

     In December  2003,  the EPA released its  proposed  Interstate  Air Quality
     Rule,  currently  referred to as the Clean Air Interstate Rule (CAIR).  The
     final rule was  released  on March 10,  2005.  The EPA's rule  requires  28
     states and the  District  of  Columbia,  including  North  Carolina,  South
     Carolina,  Georgia and Florida, to reduce NOx and SO2 emissions in order to
     attain preset state NOx and SO2 emissions levels.  The Company is reviewing
     the final rule.  Installation of additional air quality  controls is likely
     to be needed to meet the CAIR  requirements.  Compliance plans and the cost
     to comply with the rule will be determined  once the Company  completes its
     review.  The air quality controls already installed for compliance with the
     NOx SIP Call and  currently  planned by the  Company to comply  with the NC
     Clean Air  legislation  will  reduce  the costs  required  to meet the CAIR
     requirements for the Company's North Carolina units.

     In March 2004,  the North Carolina  Attorney  General filed a petition with
     the EPA  under  Section  126 of the  Clean  Air  Act,  asking  the  federal
     government to force coal-fired  power plants in 13 other states,  including
     South Carolina,  to reduce their NOx and SO2 emissions.  The state of North
     Carolina  contends  these  out-of-state   emissions  interfere  with  North
     Carolina's  ability to meet  national air quality  standards  for ozone and
     particulate  matter.  The EPA has  agreed  to make a  determination  on the
     petition by August 1, 2005.  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 at the affected  facilities.  Integration of these new wastewater
     streams  into the existing  wastewater  treatment  processes  may result in
     permitting,  construction and treatment requirements imposed on PEC and PEF
     in the immediate and extended future.

     After many years of litigation and settlement negotiations, the EPA adopted
     regulations in February 2004 to implement Section 316(b) of the Clean Water
     Act. These regulations  became effective  September 7, 2004. 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.  The Company  currently  estimates  that from 2005
     through  2009 the  range of its  expenditures  to meet the  Section  316(b)
     requirements  of the Clean Water Act will be $85  million to $115  million.
     The range includes $20 million to $30 million at PEC and $65 million to $85
     million at PEF.

                                      132
<PAGE>

     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. In 2004,  Russia  ratified the Protocol,  and the treaty
     went into effect on February  16, 2005.  The United  States has not adopted
     the  Kyoto  Protocol,  and the Bush  administration  has  stated  it favors
     voluntary programs.  A number of carbon dioxide emissions control proposals
     have been advanced in Congress.  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 of  control or
     limitation  cannot be  recovered  from  customers.  The Company  favors the
     voluntary   program  approach   recommended  by  the   administration   and
     continually   evaluates   options   for  the   reduction,   avoidance   and
     sequestration of greenhouse gases.  However, the Company cannot predict the
     outcome of this matter.

     Progress  Energy has  announced its plan to issue a report on the Company's
     activities  associated with current and future environmental  requirements.
     The report will include a discussion of the environmental requirements that
     the Company  currently faces and expects to face in the future,  as well as
     an  assessment  of  potential  mandatory   constraints  on  carbon  dioxide
     emissions. The report will be issued by March 31, 2006.

23.  COMMITMENTS AND CONTINGENCIES

     A. Purchase Obligations

     At December  31, 2004,  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)                      2005        2006         2007        2008         2009  Thereafter
------------------------------------------------------------------------------------------------------
Fuel                            $ 2,219    $  1,473      $   663       $ 229        $ 252     $ 1,270
Purchased power                     473         473          479         449          416       4,614
Construction obligations             51           -            -           -            -           -
Other purchase obligations          100          70           64          41           39         268
------------------------------------------------------------------------------------------------------
Total                           $ 2,843    $  2,016      $ 1,206       $ 719        $ 707     $ 6,152
------------------------------------------------------------------------------------------------------
</TABLE>

     FUEL AND PURCHASED POWER

     FPC, PEC and Fuels have entered into various long-term  contracts for coal,
     oil and gas. Payments under these  commitments were $2,097 million,  $1,719
     million and $1,414 million for 2004, 2003 and 2002, respectively.

     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  and  energy  costs,  total   approximately  $38  million.   These
     contractual  purchases totaled $39 million, $36 million and $36 million for
     2004, 2003 and 2002, 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, 2004, 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  estimated   minimum   annual   payments  of
     approximately  $43 million,  representing  capital-related  capacity costs.
     Estimated  annual payments for energy and capacity costs are  approximately
     $72  million   through  2009.   Total  purchases   (including   energy  and
     transmission  use  charges)  under the Rockport  agreement  amounted to $63
     million, $66 million and $59 million for 2004, 2003 and 2002, respectively.

                                      133
<PAGE>

     PEC executed two long-term  agreements for the purchase of power from Broad
     River LLC's Broad River facility.  One 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.  The second  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  for both
     capacity  and  energy  under the Broad  River  agreements  amounted  to $42
     million, $37 million and $38 million in 2004, 2003 and 2002 respectively.

     PEF has long-term  contracts for  approximately  489 MW of purchased  power
     with other  utilities,  including a contract with The Southern  Company for
     approximately  414 MW of  purchased  power  annually  through  2015.  Total
     purchases, for both energy and capacity, under these agreements amounted to
     $129  million,  $124  million  and $109  million  for 2004,  2003 and 2002,
     respectively. Total capacity payments were $56 million, $55 million and $50
     million for 2004,  2003 and 2002,  respectively.  Minimum  purchases  under
     these contracts,  representing  capital-related capacity costs, at December
     31, 2004 are $60  million,  $63 million,  $65 million,  $66 million and $67
     million for 2005 through 2009, respectively, and $244 million thereafter.

     Both  PEC and PEF have  ongoing  purchased  power  contracts  with  certain
     cogenerators  (qualifying  facilities)  with expiration  dates ranging from
     2005 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 $248 million, $244 million and $235 million for 2004,
     2003 and 2002,  respectively.  Minimum  expected future  capacity  payments
     under these contracts at December 31, 2004, are $271 million, $279 million,
     $289  million,  $298  million  and  $263  million  for 2005  through  2009,
     respectively,    and   $3.8   billion    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 $91 million in 2004,  $113 million in 2003 and
     $145 million in 2002.

     On December 2, 2004, PEF entered into precedent and related agreements with
     Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT),
     and BG LNG Services,  LLC for the supply of natural gas and associated firm
     pipeline  transportation  to augment  PEF's gas supply needs for the period
     from May 1, 2007, to April 30, 2027. The total cost to PEF associated  with
     the agreements is approximately $3.3 billion.  The transactions are subject
     to several conditions precedent, which include obtaining the Florida Public
     Service  Commission's  approval  of  the  agreements,  the  completion  and
     commencement of operation of the necessary related  expansions to SNG's and
     FGT's respective  natural gas pipeline systems,  and other standard closing
     conditions.  Due to the conditions in the  agreements,  the estimated costs
     associated with these  agreements are not included in the contractual  cash
     obligations table above.

     CONSTRUCTION OBLIGATIONS

     The  Company  has   purchase   obligations   related  to  various   capital
     construction  projects.  Total  payments  under these  contracts  were $102
     million,   $158  million  and  $143  million  for  2004,   2003  and  2002,
     respectively.

     OTHER PURCHASE OBLIGATIONS

     The  Company  has  entered  into  various  other  contractual   obligations
     primarily  related to service  contracts for operational  services  entered
     into  by  PESC,  a PVI  parts  and  services  contract,  and a PEF  service
     agreement  related to the Hines Complex.  Payments  under these  agreements
     were $69  million,  $31 million and $420  million for 2004,  2003 and 2002,
     respectively.

     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.  During 2004 and 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).  The
     related  agreements  and their  amendments  require  the payment of minimum
     annual  royalties of  approximately $7 million for each plant through 2007.
     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 $73 million and $94 million at December 31,
     2004 and 2003,  respectively,  representing the minimum amounts due through
     2007,  discounted at 6.05%.  At December 31, 2004 and 2003, the portions of
     the asset and  liability  recorded  that were  classified  as current  were

                                      134
<PAGE>

     approximately $26 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 none in 2004,  $2 million in 2003 and $51 million in 2002.
     Future expected minimum royalty payments are  approximately $26 million for
     2005 through 2007. The Company has the 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 2004 and 2003 royalty  payments of  approximately  $42 million
     and $48 million,  respectively,  pending the establishment of the necessary
     escrow accounts. Once established, those funds will be placed into escrow.

     During 2004 Progress Energy made the first installment of $10 million for a
     contract dispute. The installments for 2005 and 2006, respectively, are $16
     million and $17 million (See Note 20).

     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 $65 million,  $60
     million and $71 million for 2004,  2003 and 2002,  respectively.  Purchased
     power  expense  under  agreements   classified  as  operating  leases  were
     approximately $24 million in 2004 and $5 million in 2003.

     Assets recorded under capital leases at December 31 consist of:

-------------------------------------------------------------------
(in millions)                            2004         2003
-------------------------------------------------------------------
Buildings                                $  30        $  30
Equipment and other                          2            3
Less:  Accumulated amortization            (11)         (10)
-------------------------------------------------------------------
                                         $  21        $  23
-------------------------------------------------------------------

     Minimum annual payments,  excluding executory costs such as property taxes,
     insurance and maintenance, under long-term noncancelable leases at December
     31, 2004, are:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------------
(in millions)                                        Capital Leases     Operating Leases
-----------------------------------------------------------------------------------------
2005                                                       $  4             $  66
2006                                                          4                55
2007                                                          4                58
2008                                                          4                58
2009                                                          3                54
Thereafter                                                   31               307
-----------------------------------------------------------------------------------------
                                                           $ 50             $ 598
                                                                      -------------------
Less amount representing imputed interest                   (21)
----------------------------------------------------------------------
Present value of net minimum lease payments
              under capital leases                         $ 29
-----------------------------------------------------------------------------------------
</TABLE>

     In 2003, the Company entered into a new operating lease for a building, for
     which minimum annual rental  payments are included in the table above.  The
     lease terms provide for no rental  payments during the last 15 years of the
     lease,  during which period $53 million of rental  expense will be recorded
     in the Consolidated Statements of Income.

     The Company, excluding PEC and PEF, is also a lessor of land, buildings and
     other types of properties it owns under operating leases with various terms
     and expiration  dates. The leased buildings are depreciated  under the same
     terms as other buildings included in diversified business property. Minimum
     rentals  receivable  under  noncancelable  leases for 2005 through 2009 are
     approximately  $32  million,  $22 million,  $14 million,  $9 million and $6
     million,  respectively,  with  $17  million  receivable  thereafter.  Rents
     received under these operating leases totaled $63 million,  $46 million and
     $53 million for 2004, 2003 and 2002, respectively.

     PEC is the lessor of electric  poles,  streetlights  and other  facilities.
     Minimum rentals under noncancelable leases are $9 million for 2005 and none
     thereafter. Rents received totaled $32 million, $31 million and $28 million
     for 2004, 2003 and 2002, respectively.

                                      135
<PAGE>

     PEF is the lessor of electric  poles,  streetlights  and other  facilities.
     Rents  received are based on a fixed  minimum  rental where price varies by
     type of equipment and totaled $63 million,  $56 million and $52 million for
     2004, 2003 and 2002,  respectively.  Minimum rentals receivable  (excluding
     streetlights) under noncancelable  leases for 2005 is $5 million,  for 2006
     through 2009 $1 million,  and $8 million  thereafter.  Streetlight  rentals
     were $40  million,  $38 million  and $34  million  for 2004,  2003 and 2002
     respectively. Future streetlight rentals would approximate 2004 revenues.

     D. Guarantees

     To  facilitate  commercial  transactions  of  the  Company's  subsidiaries,
     Progress Energy and certain wholly owned subsidiaries enter into agreements
     providing future financial or performance  assurances to third parties (See
     Note 19).

     At December 31, 2004, the Company had issued  guarantees on behalf of third
     parties with an estimated  maximum exposure of  approximately  $10 million.
     These guarantees  support synthetic fuel operations.  At December 31, 2004,
     management   does  not  believe   conditions  are  likely  for  significant
     performance under these agreements.

     In connection  with the sale of  partnership  interests in Colona (See Note
     4B),  Progress Fuels  indemnified  the buyers against any claims related to
     Colona resulting from violations of any  environmental  laws.  Although the
     terms of the agreement  provide for no limitation to the maximum  potential
     future payments under the  indemnification,  the Company has estimated that
     the maximum total of such payments would not be material.

     E. Claims and Uncertainties

     OTHER CONTINGENCIES

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

     DOE failed to begin  taking  spent  nuclear  fuel by January 31,  1998.  In
     January  2004,  PEC and PEF filed a complaint in the United States Court of
     Federal Claims against the DOE, claiming that the DOE breached the Standard
     Contract for Disposal of Spent  Nuclear Fuel (SNF) by failing to accept SNF
     from various  Progress  Energy  facilities  on or before  January 31, 1998.
     Damages due to DOE's breach will likely exceed $100 million.  Approximately
     60 cases  involving  the  Government's  actions  in  connection  with spent
     nuclear fuel are currently pending in the Court of Federal Claims.

     DOE and the PEC/PEF parties have agreed to a stay of the lawsuit, including
     discovery.  The parties agreed to, and the trial court  entered,  a stay of
     proceedings,  in  order  to  allow  for  possible  efficiencies  due to the
     resolution of legal and factual  issues in previously  filed cases in which
     similar  claims are being  pursued by other  plaintiffs.  These  issues may
     include,  among others,  so-called "rate issues," or the minimum  mandatory
     schedule for the  acceptance of SNF and high level waste (HLW) by which the
     Government  was  contractually  obligated to accept  contract  holders' SNF
     and/or HLW, and issues regarding recovery of damages under a partial breach
     of  contract  theory  that will be  alleged to occur in the  future.  These
     issues  have been or are  expected to be  presented  in the trials that are
     currently  scheduled to occur during  2005.  Resolution  of these issues in
     other  cases  could  facilitate  agreements  by the  parties in the PEC/PEF
     lawsuit,  or at a minimum,  inform the Court of decisions  reached by other
     courts if they remain  contested and require  resolution in this case.  The
     trial court has continued this stay until June 24, 2005.

     With certain  modifications and additional  approval by the NRC,  including
     the  installation  of  onsite  dry  storage   facilities  at  Robinson  and
     Brunswick,  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  operating  licenses  for  all  of  PEC's  nuclear
     generating units.

     With certain  modifications and additional  approval by the NRC,  including
     the  installation  of onsite dry storage  facilities at PEF's nuclear unit,
     Crystal River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities
     will be  sufficient to provide  storage  space for spent fuel  generated on
     PEF's system through the expiration of the operating license for CR3.

                                      136
<PAGE>

     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.  In January 2003, the State of Nevada,
     Clark County,  Nevada,  and the City of Las Vegas petitioned the U.S. Court
     of  Appeals  for  the  District  of  Columbia  Circuit  for  review  of the
     Congressional override resolution. These same parties also challenged EPA's
     radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected
     the challenge to the  constitutionality  of the resolution  approving Yucca
     Mountain,  but ruled that the EPA was wrong to set a 10,000-year compliance
     period in the radiation protection standard. EPA is currently reworking the
     standard but has not stated when the work will be complete.  DOE originally
     planned to submit a license  application  to the NRC to construct the Yucca
     Mountain  facility  by the end of 2004.  However,  in  November  2004,  DOE
     announced  it would not submit the license  application  until  mid-2005 or
     later.  Also in November  2004,  Congressional  negotiators  approved  $577
     million for fiscal year 2005 for the Yucca Mountain project,  approximately
     $300  million  less than  requested  by DOE but  approximately  the same as
     approved in 2004. The DOE continues to state it plans to begin operation of
     the  repository at Yucca  Mountain in 2010.  PEC and PEF cannot predict the
     outcome of this matter.

     2. In 2001,  PEC  entered  into a contract  to  purchase  coal from  Dynegy
     Marketing and Trade (DMT).  After DMT experienced  financial  difficulties,
     including credit ratings  downgrades by certain credit reporting  agencies,
     PEC requested credit  enhancements in accordance with the terms of the coal
     purchase   agreement   in  July  2002.   When  DMT  did  not  offer  credit
     enhancements,  as required by a provision in the contract,  PEC  terminated
     the contract in July 2002.

     PEC initiated a lawsuit seeking a declaratory judgment that the termination
     was lawful.  DMT  counterclaimed,  stating the  termination was a breach of
     contract and an unfair and deceptive trade practice. On March 23, 2004, the
     United States  District  Court for the Eastern  District of North  Carolina
     ruled that PEC was liable for breach of contract,  but ruled against DMT on
     its unfair and deceptive trade practices claim. On April 6, 2004, the Court
     entered a judgment against PEC in the amount of approximately  $10 million.
     The Court did not rule on DMT's  request  under the  contract  for  pending
     legal costs.

     On May 4, 2004,  PEC  authorized  its  outside  counsel to file a notice of
     appeal of the April 6, 2004,  judgment,  and on May 7, 2004,  the notice of
     appeal  was filed with the United  States  Court of Appeals  for the Fourth
     Circuit.  On June 8, 2004,  DMT filed a motion to dismiss the appeal on the
     ground that PEC's notice of appeal  should have been filed on or before May
     6,  2004.  On June 16,  2004,  PEC  filed a motion  with  the  trial  court
     requesting  an  extension  of the  deadline for the filing of the notice of
     appeal.  By order dated  September  10,  2004,  the trial court  denied the
     extension  request.  On September 15, 2004, PEC filed a notice of appeal of
     the September 10, 2004,  order,  and by order dated September 29, 2004, the
     appellate court consolidated the first and second appeals.  DMT's motion to
     dismiss the first appeal remains pending.

     The  consolidated  appeal has been fully briefed,  and the court of appeals
     has indicated  that it will hear  arguments,  which  tentatively  have been
     scheduled for the week of May 23, 2005.

     In the first quarter of 2004,  PEC recorded a liability for the judgment of
     approximately  $10 million and a regulatory asset for the probable recovery
     through its fuel adjustment  clause. The Company cannot predict the outcome
     of this matter.

     3. On February  1, 2002,  the  Company  filed a complaint  with the Surface
     Transportation  Board  (STB)  challenging  the  rates  charged  by  Norfolk
     Southern  Railway Company  (Norfolk  Southern) for coal  transportation  to
     certain  generating  plants. In a decision dated December 23, 2003, the STB
     found that the rates were unreasonable,  awarded reparations and prescribed
     maximum rates. Both parties  petitioned the STB for  reconsideration of the
     December 23, 2003 decision.  On October 20, 2004, the STB  reconsidered its
     December 23, 2003 decision and concluded  that the rates charged by Norfolk
     Southern were not unreasonable.  Because the Company paid the maximum rates
     prescribed by the STB in its December 23, 2003 decision for several  months
     during  2004,  which  were  less  than  the  rates  ultimately  found to be
     reasonable,  the STB  ordered the  Company to pay to Norfolk  Southern  the
     difference between the rate levels plus interest.

     The Company  subsequently filed a petition with the STB to phase in the new
     rates  over a period of time,  and  filed a notice of appeal  with the U.S.
     Court of Appeals for the D.C.  Circuit.  Pursuant to an order issued by the
     STB on January 6, 2005, the phasing  proceeding  will proceed on a schedule
     that appears  likely to produce an STB decision  before the end of 2005. On
     January 12, 2005, the STB filed a Motion to Dismiss the Company's appeal on
     the  grounds  that its  October 20,  2004,  order is not "final"  until the
     Company's phasing application has been decided.

                                      137
<PAGE>

     As of December  31,  2004,  the  Company  has  accrued a  liability  of $42
     million, of which $23 million represents reparations previously remitted to
     PEC by Norfolk  Southern  that are now subject to refund.  Of the remaining
     $19  million,  $17 million has been  recorded as deferred  fuel cost on the
     Consolidated  Balance Sheet, while the remaining $2 million attributable to
     wholesale customers has been charged to fuel used in electric generation on
     the Consolidated Statements of Income.

     The Company cannot predict the outcome of this matter.

     4. 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 qualify
     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.  The amount of Section 29 credits  that the Company is
     allowed  to claim in any  calendar  year is  limited  by the  amount of the
     Company's  regular federal income tax liability.  Synthetic fuel tax credit
     amounts  allowed but not  utilized  are  carried  forward  indefinitely  as
     deferred  alternative minimum tax credits.  All entities have received PLRs
     from the IRS with  respect to their  synthetic  fuel  operations.  However,
     these PLRs do not address the  placed-in-service  date  determination.  The
     PLRs do not limit the  production  on which  synthetic  fuel credits may be
     claimed.  Total  Section  29 credits  generated  to date  (including  those
     generated by FPC prior to its acquisition by the Company) are approximately
     $1.5 billion, of which $713 million has been used to offset regular federal
     income tax liability and $745 million is being carried  forward as deferred
     alternative  minimum tax credits.  Also, $7 million has not been recognized
     due to the decrease in tax liability  resulting from expenses  incurred for
     the 2004  hurricane  damage.  The  current  Section 29 tax  credit  program
     expires at the end of 2007.

     IMPACT OF HURRICANES

     For the  year  ended  December  31,  2004,  the  Company's  synthetic  fuel
     facilities sold 8.3 million tons of synthetic fuel and the Company recorded
     $215 million of Section 29 tax credits.  The amount of synthetic  fuel sold
     and tax credits  recorded  in 2004 was  impacted  by  hurricane  costs that
     reduced the Company's projected 2004 regular tax liability.

     For the nine months ended September 30, 2004, the Company's  synthetic fuel
     facilities  sold 7.7 million tons of  synthetic  fuel,  which  generated an
     estimated  $204 million of Section 29 tax credits.  Due to the  anticipated
     decrease in the Company's  tax  liability as a result of expenses  incurred
     for the 2004 hurricane damage,  the Company estimated that it would be able
     to use in 2004,  or carry  forward to future  years,  only $125  million of
     these  Section 29 tax  credits at  September  30,  2004.  As a result,  the
     Company  recorded a charge of $79 million related to Section 29 tax credits
     at September 30, 2004.

     On November  2, 2004,  PEF filed a petition  with the FPSC to recover  $252
     million of storm costs plus interest from customers over a two-year period.
     Based on a reasonable  expectation at December 31, 2004, that the FPSC will
     grant the requested  recovery of the storm costs,  the Company's  loss from
     the casualty is less than originally anticipated.  As of December 31, 2004,
     the Company estimates that it will be able to use in 2004, or carry forward
     to future years,  $215 million of these Section 29 tax credits.  Therefore,
     the Company  recorded  tax  credits of $90  million  for the quarter  ended
     December 31, 2004,  which the Company now  anticipates can be used. For the
     year ended December 31, 2004, the Company's  synthetic fuel facilities sold
     8.3 million  tons of synthetic  fuel,  which  generated  an estimated  $222
     million of Section 29 tax credits.  As of December  31,  2004,  the Company
     anticipates  that  approximately  $7  million  of tax  credits  related  to
     synthetic  fuel sold  during  the year  could not be used and have not been
     recognized.

     The Company believes its right to recover storm costs is well  established;
     however,  the Company  cannot predict the timing or outcome of this matter.
     If the FPSC should deny PEF's  petition  for the recovery of storm costs in
     2005,  there  could be a material  impact on the  amount of 2005  synthetic
     fuels production and results of operations.

     IRS PROCEEDINGS

     In September 2002, all of Progress Energy's  majority-owned  synthetic fuel
     entities 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.

                                      138
<PAGE>

     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 concluded the PFA program with respect to Colona.

     In July 2004,  Progress  Energy was  notified  that the IRS field  auditors
     anticipated taking an adverse position regarding the placed-in-service date
     of  the  Company's  four  Earthco  synthetic  fuel  facilities.  Due to the
     auditors' position,  the IRS decided to exercise its right to withdraw from
     the PFA program with Progress  Energy.  With the IRS's  withdrawal from the
     PFA program,  the review of Progress Energy's Earthco facilities is back on
     the normal  procedural  audit path of the  Company's  tax returns.  Through
     December  31, 2004,  the  Company,  on a  consolidated  basis,  has used or
     carried  forward  approximately  $1.0  billion of tax credits  generated by
     Earthco  facilities.  If  these  credits  were  disallowed,  the  Company's
     one-time  exposure for cash tax payments  would be $294 million  (excluding
     interest),  and earnings and equity would be reduced by approximately  $1.0
     billion, excluding interest. Progress Energy's amended $1.13 billion credit
     facility includes a covenant that limits the maximum  debt-to-total capital
     ratio to 68%.  This ratio  includes  other  forms of  indebtedness  such as
     guarantees  issued by PGN,  letters of credit  and  capital  leases.  As of
     December 31, 2004,  the  Company's  debt-to-total  capital  ratio was 60.7%
     based on the credit agreement definition for this ratio. The impact on this
     ratio of  reversing  approximately  $1.0  billion of tax credits and paying
     $294 million for taxes would be to increase the ratio to 65.7%.

     On October 29,  2004,  Progress  Energy  received  the IRS field  auditors'
     report  concluding  that the  Earthco  facilities  had not been  placed  in
     service  before July 1, 1998,  and that the tax credits  generated by those
     facilities should be disallowed. The Company disagrees with the field audit
     team's  factual  findings and  believes  that the Earthco  facilities  were
     placed in service  before July 1, 1998.  The Company also believes that the
     report applies an inappropriate  legal standard concerning what constitutes
     "placed in  service."  The Company  intends to contest the field  auditors'
     findings and their proposed disallowance of the tax credits.

     Because of the  disagreement  between the Company and the field auditors as
     to the proper  legal  standard to apply,  the Company  believes  that it is
     appropriate  and helpful to have this issue reviewed by the National Office
     of the IRS,  just as the  National  Office  reviewed  the issues  involving
     chemical  change.  Therefore,  the Company is asking the National Office to
     clarify the legal standard and has initiated this process with the National
     Office.   The  Company  believes  that  the  appeals   process,   including
     proceedings  before  the  National  Office,  could  take up to two years to
     complete;  however,  it cannot  control the actual timing of resolution and
     cannot predict the outcome of this matter.

     In  management's  opinion,  the Company is complying with all the necessary
     requirements to be allowed such credits under Section 29, and,  although it
     cannot  provide  certainty,  it  believes  that it will  prevail  in  these
     matters.  Accordingly,  while  the  Company  adjusted  its  synthetic  fuel
     production for 2004 in response to the effects of expenses  incurred due to
     the  hurricane  damage  and its  impact  on 2004 tax  liability,  it has no
     current plans to alter its synthetic  fuel  production  schedule for future
     years as a result of the IRS field auditors'  report.  However,  should the
     Company fail to prevail in these matters, there could be material liability
     for previously taken Section 29 tax credits, with a material adverse impact
     on earnings and cash flows.

     PROPOSED ACCOUNTING RULES FOR UNCERTAIN TAX POSITIONS

     In July 2004, the FASB stated that it plans to issue an exposure draft of a
     proposed  interpretation  of SFAS No. 109,  "Accounting  for Income Taxes,"
     (SFAS No.  109)  that  would  address  the  accounting  for  uncertain  tax
     positions.  The FASB has indicated  that the  interpretation  would require
     that  uncertain  tax  benefits be probable of being  sustained  in order to
     record such benefits in the  financial  statements.  The exposure  draft is
     expected  to be issued in the first  quarter of 2005.  The  Company  cannot
     predict  what  actions  the FASB  will take or how any such  actions  might
     ultimately   affect  the  Company's   financial   position  or  results  of
     operations,  but such changes could have a material impact on the Company's
     evaluation and recognition of Section 29 tax credits.

                                      139
<PAGE>

     PERMANENT SUBCOMMITTEE

     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.

     SALE OF PARTNERSHIP INTEREST

     In June 2004, the Company, through its subsidiary, Progress Fuels, sold, in
     two transactions,  a combined 49.8% partnership  interest in Colona Synfuel
     Limited   Partnership,   LLLP,  one  of  its  synthetic  fuel   facilities.
     Substantially all proceeds from the sales will be received over time, which
     is  typical  of such  sales in the  industry.  Gain from the sales  will be
     recognized  on a cost  recovery  basis.  The  Company's  book  value of the
     interests sold totaled approximately $5 million. The company received total
     gross  proceeds of $10 million in 2004.  Based on projected  production and
     tax credit levels,  the Company  anticipates  receiving  approximately  $24
     million  in 2005,  approximately  $31  million in 2006,  approximately  $32
     million in 2007 and  approximately $8 million through the second quarter of
     2008.  In the event that the  synthetic  fuel tax  credits  from the Colona
     facility are reduced,  including an increase in the price of oil that could
     limit or  eliminate  synthetic  fuel tax  credits,  the amount of  proceeds
     realized from the sale could be significantly impacted.

     IMPACT OF CRUDE OIL PRICES

     Although  the  Internal  Revenue  Code  Section  29 tax  credit  program is
     expected to continue through 2007,  recent  unprecedented and unanticipated
     increases  in the price of oil could  limit the amount of those  credits or
     eliminate them altogether for one or more of the years following 2004. This
     possibility  is due to a provision of Section 29 that  provides that if the
     average  wellhead price per barrel for  unregulated  domestic crude oil for
     the year (the "Annual  Average  Price")  exceeds a certain  threshold value
     (the "Threshold  Price"),  the amount of Section 29 tax credits are reduced
     for that year. Also, if the Annual Average Price increases high enough (the
     "Phase Out  Price"),  the Section 29 tax credits  are  eliminated  for that
     year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out
     Price was $62.94 per barrel.  The  Threshold  Price and the Phase Out Price
     are adjusted annually for inflation.

     If the Annual Average Price falls between the Threshold Price and the Phase
     Out Price  for a year,  the  amount by which  Section  29 tax  credits  are
     reduced  will  depend  on where  the  Average  Annual  Price  falls in that
     continuum.  For example,  for 2003,  if the Annual  Average  Price had been
     $56.54 per barrel,  there would have been a 50%  reduction in the amount of
     Section 29 tax credits for that year.

     The Secretary of the Treasury  calculates the Annual Average Price based on
     the  Domestic  Crude Oil First  Purchases  Prices  published  by the Energy
     Information  Agency (EIA).  Because the EIA publishes its  information on a
     three-month  lag, the Secretary of the Treasury  finalizes its calculations
     three  months after the year in question  ends.  Thus,  the Annual  Average
     Price for calendar year 2003 was published in April 2004.

     Although the official notice for 2004 is not expected to be published until
     April 2005,  the Company does not believe that the Annual Average Price for
     2004 will reach the  Threshold  Price for 2004.  Consequently,  the Company
     does not  expect  the  amount  of its 2004  Section  29 tax  credits  to be
     adversely affected by oil prices.

     The Company  cannot predict with any certainty the Annual Average Price for
     2005 or beyond.  Therefore, it cannot predict whether the price of oil will
     have a material effect on its synthetic fuel business after 2004.  However,
     if during 2005 through 2007, oil prices remain at historically  high levels
     or  increase,  the  Company's  synthetic  fuel  business  may be  adversely
     affected for those years, and, depending on the magnitude of such increases
     in oil  prices,  the adverse  affect for those years could be material  and
     could have an impact on the Company's  synthetic fuel results of operations
     and production plans.

     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 and disclosures have been
     made in accordance  with SFAS No. 5,  "Accounting  for  Contingencies,"  to
     provide  for  such  matters.  In  the  opinion  of  management,  the  final
     disposition of pending  litigation would not have a material adverse effect
     on the Company's consolidated results of operations or financial position.

                                      140
<PAGE>

24.  SUBSEQUENT EVENTS

     Sale of Progress Rail

     On  February  18,  2005,  the  Company  announced  it  has  entered  into a
     definitive  agreement to sell Progress  Rail to One Equity  Partners LLC, a
     private  equity firm unit of J.P.  Morgan Chase & Co.  Gross cash  proceeds
     from the  transaction  will be $405  million,  subject to  working  capital
     adjustments.  The sale is expected to close by mid-2005,  and is subject to
     various closing conditions  customary to such  transactions.  Proceeds from
     the sale are  expected to be used to reduce  debt.  The Company  expects to
     report  Progress Rail as a  discontinued  operation in the first quarter of
     2005.  The  carrying   amounts  for  the  assets  and  liabilities  of  the
     discontinued operations disposal group included in the Consolidated Balance
     Sheets as of December 31, are as follows:

------------------------------------------------------------------------
(in millions)                                    2004           2003
------------------------------------------------------------------------
 Total current assets                           $ 378           $ 373
 Total property, plant & equipment (net)          173             151
 Total other assets                                40              77
 Total current liabilities                        156             114
 Total long-term liabilities                        3               3
 Total capitalization                             432             484
------------------------------------------------------------------------

     Cost Management Initiative

     On February 28, 2005,  as part of a previously  announced  cost  management
     initiative,  the  executive  officers of the  Company  approved a workforce
     restructuring.   The   restructuring   will  result  in  a   reduction   of
     approximately  450  positions  and is expected to be completed in September
     2005. The cost management  initiative is designed to permanently  reduce by
     $75-100 million the projected  growth in the Company's annual operation and
     maintenance  expenses  by the end of 2007.  In  addition  to the  workforce
     restructuring, the cost management initiative includes a voluntary enhanced
     retirement program.

     In connection with the cost management  initiative,  the Company expects to
     incur one-time pre-tax charges of approximately $130 million. Approximately
     $30 million of that amount relates to payments for severance benefits,  and
     will be  recognized  in the first  quarter of 2005 and paid over time.  The
     remaining  approximately  $100  million  will be  recognized  in the second
     quarter of 2005 and relates primarily to postretirement  benefits that will
     be paid over time to those  eligible  employees who elect to participate in
     the  voluntary  enhanced  retirement  program.  Approximately  3,500 of the
     Company's  15,700  employees are eligible to  participate  in the voluntary
     enhanced retirement program.  The total cost management  initiative charges
     could change significantly depending upon how many eligible employees elect
     early retirement under the voluntary  enhanced  retirement  program and the
     salary, service years and age of such employees.

                                      141
<PAGE>

25.  CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

     Summarized quarterly financial data is as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------------
(in millions except per share data)                 First            Second        Third Quarter     Fourth Quarter
                                                   Quarter          Quarter
----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues                                 $  2,245          $  2,408           $ 2,761           $  2,358
Operating income                                        296               305               584                291
Income from continuing operations
     before cumulative effect of changes
     in accounting principles                           108               153               303                189
Net income                                              108               154               303                194
Common stock data:
Basic earnings per common share
     Income from continuing operations
           before cumulative effect of changes
           in accounting principles                    0.45              0.63              1.25               0.78
     Net income                                        0.45              0.63              1.25               0.80
Diluted earnings per common share
     Income from continuing operations
           before cumulative effect of changes
           in accounting principles                    0.45              0.63              1.24               0.78
     Net income                                        0.45              0.63              1.24               0.80
Dividends declared per common share                    0.575             0.575             0.575              0.590
Market price per share - High                         47.95             47.50             44.32              46.10
                         Low                          43.02             40.09             40.76              40.47
-------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues                                 $  2,187          $  2,050           $ 2,457           $  2,047
Operating income                                        357               274               478                248
Income from continuing operations
           before cumulative effect of changes
           in accounting principles                     207               154               337                113
Net income                                              219               157               318                 88
Common stock data:
Basic earnings per common share
     Income from continuing operations
           before cumulative effect of changes
           in accounting principles                    0.89              0.65              1.41               0.47
     Net income                                        0.94              0.66              1.33               0.37
Diluted earnings per common share
     Income from continuing operations
           before cumulative effect of changes
           in accounting principles                    0.89              0.65              1.39               0.47
     Net income                                        0.94              0.66              1.31               0.37
Dividends declared per common share                    0.560             0.560             0.560              0.575
Market price per share - High                         46.10             48.00             45.15              46.00
                       - Low                          37.45             38.99             39.60              41.60
-------------------------------------------------------------------------------------------------------------------
</TABLE>

     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.
     Fourth  quarter  2004  includes  a $31  million  after-tax  gain on sale of
     natural  gas  assets  (See Note 4A) and the  recording  of $90  million  of
     Section 29 tax credit  (See Note 23E).  Third  quarter  2004  includes  the
     reversal of $79 million of Section 29 tax  credits  (See Note 23E).  Second
     quarter 2004 includes the settlement of civil proceeding  related to SRS of
     $43 million  ($29 million  after-tax)  (See Note 20).  Fourth  quarter 2003
     includes  impairment charges related to Kentucky May and certain Affordable
     Housing  investments of $38 million ($24 million  after-tax) (See Note 10).
     Fourth  quarter 2003  includes  the impact of a  cumulative  effect for DIG
     Issue 20 of $38 million ($23 million after-tax) (See Note 18).

                                      142
<PAGE>

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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,  2004 and 2003,  and the related  consolidated  statements  of
income, retained earnings,  comprehensive income, and cash flows for each of the
three years in the period ended December 31, 2004.  These  financial  statements
are the responsibility of the 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 the standards of the Public  Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material  misstatement.  PEC is not required to have, nor
were we engaged to perform,  an audit of its  internal  control  over  financial
reporting.  An audit includes  consideration  of internal control over financial
reporting as a basis for designing audit  procedures that are appropriate in the
circumstances,  but  not  for  the  purpose  of  expressing  an  opinion  on the
effectiveness of PEC's internal control over financial  reporting.  Accordingly,
we express no such opinion. An audit also includes  examining,  on a test basis,
evidence  supporting the amounts and  disclosures  in the financial  statements,
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 December 31, 2004 and 2003, and
the results of its  operations and its cash flows for each of the three years in
the period ended  December 31, 2004, in conformity  with  accounting  principles
generally accepted in the United States of America.

As discussed in Notes 1D and 13A to the consolidated  financial  statements,  in
2003,  PEC adopted  Statement  of  Financial  Accounting  Standards  No. 143 and
Derivative Implementation Group Issue C20.

/s/ Deloitte & Touche LLP


Raleigh, North Carolina
March 7, 2005


                                      143
<PAGE>


<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of INCOME
-----------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                                 2004          2003            2002
-----------------------------------------------------------------------------------------------------------
Operating Revenues
   Electric                                                          $ 3,628       $ 3,589         $ 3,539
   Diversified business                                                    1            11              15
-----------------------------------------------------------------------------------------------------------
      Total Operating Revenues                                         3,629         3,600           3,554
-----------------------------------------------------------------------------------------------------------
Operating Expenses
   Fuel used in electric generation                                      836           825             752
   Purchased power                                                       301           296             347
   Operation and maintenance                                             871           782             802
   Depreciation and amortization                                         570           562             524
   Taxes other than on income                                            173           162             158
   Diversified business                                                    1             4              15
   Impairment of diversified business long-lived assets                    -             -             101
-----------------------------------------------------------------------------------------------------------
        Total Operating Expenses                                       2,752         2,631           2,699
-----------------------------------------------------------------------------------------------------------
Operating Income                                                         877           969             855
-----------------------------------------------------------------------------------------------------------
Other Income (Expense)
   Interest income                                                         4             6               7
   Impairment of investments                                               -           (21)            (25)
   Other, net                                                             11           (11)             13
-----------------------------------------------------------------------------------------------------------
        Total Other Income (Expense)                                      15           (26)             (5)
-----------------------------------------------------------------------------------------------------------
Interest Charges
   Interest charges                                                      195           198             217
   Allowance for borrowed funds used during construction                  (3)           (1)             (5)
-----------------------------------------------------------------------------------------------------------
        Total Interest Charges, Net                                      192           197             212
-----------------------------------------------------------------------------------------------------------
Income before Income Tax and Cumulative Effect of Change in
  Accounting Principles                                                  700           746             638
Income Tax Expense                                                       239           241             207
-----------------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Change in Accounting                  461           505             431
  Principles
Cumulative Effect of Change in Accounting Principles, Net of Tax           -           (23)              -
-----------------------------------------------------------------------------------------------------------
Net Income                                                               461           482             431
Preferred Stock Dividend Requirement                                       3             3               3
-----------------------------------------------------------------------------------------------------------
Earnings for Common Stock                                            $   458       $   479         $   428
-----------------------------------------------------------------------------------------------------------
</TABLE>

See Notes to Consolidated Financial Statements.

                                      144
<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                                                                2004               2003
---------------------------------------------------------------------------------------------------
ASSETS
Utility Plant
  Utility plant in service                                           $   13,521           $ 13,331
  Accumulated depreciation                                               (5,806)            (5,307)
---------------------------------------------------------------------------------------------------
        Utility plant in service, net                                     7,715              8,024
  Held for future use                                                         5                  5
  Construction work in progress                                             379                267
  Nuclear fuel, net of amortization                                         186                159
---------------------------------------------------------------------------------------------------
        Total Utility Plant, Net                                          8,285              8,455
---------------------------------------------------------------------------------------------------
Current Assets
  Cash and cash equivalents                                                  18                 12
  Short-term investments                                                     82                226
  Receivables                                                               397                410
  Receivables from affiliated companies                                      20                 27
  Inventory                                                                 390                387
  Deferred fuel cost                                                        140                 66
  Income taxes receivable                                                    59                 37
  Prepayments and other current assets                                       76                 63
---------------------------------------------------------------------------------------------------
        Total Current Assets                                              1,182              1,228
---------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
  Regulatory assets                                                         473                463
  Nuclear decommissioning trust funds                                       581                505
  Miscellaneous other property and investments                              158                169
  Other assets and deferred debits                                          108                118
---------------------------------------------------------------------------------------------------
        Total Deferred Debits and Other Assets                            1,320              1,255
---------------------------------------------------------------------------------------------------
           Total Assets                                              $   10,787           $ 10,938
---------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Common Stock Equity
  Common stock without par value, authorized 200 million shares,
     160 million shares issued and outstanding at December 31        $    1,975           $  1,953
  Unearned ESOP common stock                                                (76)               (89)
  Accumulated other comprehensive loss                                     (114)                (7)
  Retained earnings                                                       1,287              1,380
---------------------------------------------------------------------------------------------------
        Total Common Stock Equity                                         3,072              3,237
  Preferred Stock - Not Subject to Mandatory Redemption                      59                 59
  Long-Term Debt, Net                                                     2,750              3,086
---------------------------------------------------------------------------------------------------
        Total Capitalization                                              5,881              6,382
---------------------------------------------------------------------------------------------------
Current Liabilities
  Current portion of long-term debt                                         300                300
  Accounts payable                                                          254                188
  Payables to affiliated companies                                           83                136
  Notes payable to affiliated companies                                     116                 25
  Interest accrued                                                           77                 80
  Short-term obligations                                                    221                  4
  Customer deposits                                                          45                 40
  Other current liabilities                                                 179                133
---------------------------------------------------------------------------------------------------
        Total Current Liabilities                                         1,275                906
---------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
  Noncurrent income tax liabilities                                         991              1,057
  Accumulated deferred investment tax credits                               140                148
  Regulatory liabilities                                                  1,052              1,149
  Asset retirement obligations                                              924                932
  Accrued pension and other benefits                                        383                207
  Other liabilities and deferred credits                                    141                157
---------------------------------------------------------------------------------------------------
        Total Deferred Credits and Other Liabilities                      3,631              3,650
---------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 17 and 18)
---------------------------------------------------------------------------------------------------
            Total Capitalization and Liabilities                     $   10,787           $ 10,938
---------------------------------------------------------------------------------------------------
 See Notes to Consolidated Financial Statements.
</TABLE>

                                      145
<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
-------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                                            2004         2003          2002
-------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income                                                                      $   461        $ 482         $ 431
Adjustments to reconcile net income to net cash provided by operating
activities:
      Impairment of long-lived assets and investments                                 -           21           126
      Depreciation and amortization                                                 658          660           631
      Cumulative effect of change in accounting principles                            -           23             -
      Deferred income taxes                                                         (19)         (69)          (82)
      Investment tax credit                                                          (7)         (10)          (12)
      Deferred fuel credit                                                          (56)          33           (15)
   Cash provided (used) by changes in operating assets and liabilities:
      Receivables                                                                    (4)          10           (13)
      Receivables from affiliated companies                                           7           20            (8)
      Inventory                                                                     (18)         (21)            5
      Prepayments and other current assets                                           13           21           (15)
      Accounts payable                                                               35          (56)           39
      Accounts payable to affiliated companies                                      (53)          24           (19)
      Other current liabilities                                                       9           57            (2)
      Other                                                                          50           38            32
-------------------------------------------------------------------------------------------------------------------
         Net Cash Provided by Operating Activities                                1,076        1,233         1,098
-------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions                                                           (519)        (445)         (619)
Proceeds from sale of subsidiaries and other investments                             25           28           244
Diversified business property additions and acquisitions                              -           (1)          (12)
Nuclear fuel additions                                                             (101)         (66)          (81)
Net contributions to nuclear decommissioning trust                                  (31)         (31)          (31)
Purchases of short-term investments                                              (2,108)      (2,813)       (2,962)
Proceeds from sales of short-term investments                                     2,252        2,587         2,962
Other investing activities                                                           (3)          (1)          (17)
-------------------------------------------------------------------------------------------------------------------
         Net Cash Used in Investing Activities                                     (485)        (742)         (516)
-------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt                                              -          588           542
Net increase (decrease) in short-term obligations                                   217         (437)          177
Net change in intercompany notes                                                     91           74           (97)
Retirement of long-term debt                                                       (339)        (276)         (807)
Dividends paid to parent                                                           (551)        (443)         (397)
Dividends paid on preferred stock                                                    (3)          (3)           (3)
-------------------------------------------------------------------------------------------------------------------
         Net Cash Used in Financing Activities                                     (585)        (497)         (585)
-------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents                                  6           (6)           (3)
-------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year                                       12           18            21
-------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year                                        $    18      $    12       $    18
-------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized)                $   185      $   180       $   203
                            income taxes (net of refunds)                       $   286      $   296       $   319
-------------------------------------------------------------------------------------------------------------------
</TABLE>

See  Notes to Consolidated Financial Statements.

                                      146
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
----------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                2004         2003         2002
----------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year               $ 1,380      $ 1,344       $ 1,313
Net income                                               461          482           431
Preferred stock dividends at stated rates                 (3)          (3)           (3)
Common stock dividends                                  (551)        (443)         (397)
----------------------------------------------------------------------------------------
Retained Earnings at End of Year                     $ 1,287      $ 1,380       $ 1,344
----------------------------------------------------------------------------------------
</TABLE>




<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31                                                             2004            2003           2002
------------------------------------------------------------------------------------------------------------------------
Net Income                                                                      $    461           $ 482         $  431
Other Comprehensive Income
      Changes in net unrealized losses on cash flow hedges (net of tax
             (expense) benefit of  $1, ($1) and $9,  respectively)                    (1)              3            (14)
      Reclassification adjustment for amounts included in net income
             (net of tax benefit of  $0,  $0 and $8, respectively)                     -               1             11
      Minimum pension liability adjustment (net of tax (expense)
             benefit of $68, ($47) and $47, respectively)                           (106)             72            (73)
------------------------------------------------------------------------------------------------------------------------
             Other Comprehensive Income                                         $   (107)          $  76         $  (76)
------------------------------------------------------------------------------------------------------------------------
Comprehensive Income                                                            $    354           $ 558         $  355
------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                      147
<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 was
     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 Caronet, Inc. (Caronet), 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,  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 (PT 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.

     The consolidated  financial  statements of PEC and its subsidiaries include
     the majority owned and controlled subsidiaries. Noncontrolling interests in
     the subsidiaries are included in other  liabilities and deferred credits in
     the Consolidated Balance Sheets.  Income or losses from these interests are
     included in other  income in the  Consolidated  Statements  of Income.  The
     results of  operations  for minority  interest are reported on a net of tax
     basis if the underlying subsidiary is structured as a taxable entity.

     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. These investments are primarily in limited
     liability corporations and limited liability partnerships, and the earnings
     from these investments are recorded on a pre-tax basis (See Note 16). These
     equity method investments are included in miscellaneous  other property and
     investments in the  Consolidated  Balance Sheets.  At December 31, 2004 and
     2003, PEC has equity method  investments of  approximately  $15 million and
     $24 million, respectively.

     Certain  investments  in debt  and  equity  securities  that  have  readily
     determinable  market values,  and for which PEC does not have control,  are
     accounted for as available-for-sale  securities at fair value in accordance
     with SFAS No. 115,  "Accounting for Certain  Investments in Debt and Equity
     Securities."  These  investments  include  investments held in trust funds,
     pursuant to United States Nuclear Regulatory Commission (NRC) requirements,
     to fund certain costs of decommissioning  nuclear plants. The fair value of
     these trust funds was $581  million and $505  million at December  31, 2004
     and 2003,  respectively.  PEC also actively invests available cash balances
     in various financial  instruments,  such as tax-exempt debt securities that
     have stated maturities of 20 years or more. These instruments provide for a
     high degree of liquidity through arrangements with banks that provide daily
     and weekly  liquidity  and 7, 28 and 35 day  auctions  which  allow for the
     redemption of the investment at its face amount plus earned income.  As PEC
     intends to sell these instruments generally within 30 days from the balance
     sheet date, they are classified as current assets. At December 31, 2004 and
     2003, the fair value of these investments was $82 million and $226 million,
     respectively.  Other investments in debt and equity securities are included
     in miscellaneous other property and investments in the Consolidated Balance
     Sheets.  At  December  31,  2004 and 2003,  the fair  value of these  other
     investments was $3 million and $2 million, respectively.

     Other  investments  are  stated  principally  at cost.  These  cost  method
     investments are included in miscellaneous other property and investments in
     the  Consolidated  Balance  Sheets.  At December 31, 2004 and 2003, PEC has
     approximately  $1 million  and $1  million,  respectively,  of cost  method
     investments.

                                      148
<PAGE>

     Certain amounts for 2003 and 2002 have been  reclassified to conform to the
     2004  presentation.   Reclassifications  include  the  reclassification  of
     instruments  used in  PEC's  cash  management  program  from  cash and cash
     equivalents to short-term  investments of $226 million at December 31, 2003
     in the Consolidated Balance Sheets. In the Consolidated  Statements of Cash
     Flow for each of the three years in the period  ended  December  31,  2004,
     total cash balances and total cash flows used in investing  activities were
     revised to reflect the  reclassification of these instruments from cash and
     cash equivalents to short-term investments.

     C. Consolidation of Variable Interest Entities

     PEC consolidates  all voting interest  entities in which it owns a majority
     voting  interest  and all  variable  interest  entities for which it is the
     primary  beneficiary  in  accordance  with  FASB  Interpretation  No.  46R,
     "Consolidation of Variable Interest Entities - An Interpretation of ARB No.
     51" (FIN No. 46R). PEC is the primary  beneficiary of and  consolidates two
     limited  partnerships  that  qualify  for  federal  affordable  housing and
     historic tax credits under  Section 42 of the Internal  Revenue Code. As of
     December 31, 2004,  the total assets of the two entities  were $37 million,
     the majority of which are collateral for the entities'  obligations and are
     included in other  current  assets and  miscellaneous  other  property  and
     investments in the Consolidated Balance Sheet.

     PEC is the primary  beneficiary of a limited partnership that invests in 17
     low-income  housing  partnerships  that  qualify  for federal and state tax
     credits.  PEC  has  requested  but  has  not  received  all  the  necessary
     information   to  determine   the  primary   beneficiary   of  the  limited
     partnership's  underlying 17 partnership  investments,  and has applied the
     information  scope  exception  in FIN  No.  46R,  paragraph  4(g) to the 17
     partnerships.  PEC has no direct exposure to loss from the 17 partnerships;
     PEC's only exposure to loss is from its  investment of less than $1 million
     in the consolidated limited  partnership.  PEC will continue its efforts to
     obtain  the  necessary  information  to fully  apply FIN No.  46R to the 17
     partnerships. PEC believes that if the limited partnership is determined to
     be  the  primary  beneficiary  of  the  17  partnerships,   the  effect  of
     consolidating  the 17  partnerships  would  not  be  significant  to  PEC's
     Consolidated Balance Sheets.

     PEC has variable  interests in two power plants  resulting  from  long-term
     power purchase  contracts.  PEC has requested the necessary  information to
     determine  if the  counterparties  are  variable  interest  entities  or to
     identify the primary  beneficiaries.  Both entities declined to provide PEC
     with  the  necessary  financial  information,   and  PEC  has  applied  the
     information  scope  exception in FIN No. 46R,  paragraph  4(g).  PEC's only
     significant  exposure to  variability  from these  contracts  results  from
     fluctuations  in the market price of fuel used by the two entities'  plants
     to produce the power  purchased by PEC.  PEC is able to recover  these fuel
     costs under its fuel clause. Total purchases from these counterparties were
     approximately  $58 million,  $53 million and $53 million in 2004,  2003 and
     2002,  respectively.  PEC will continue its efforts to obtain the necessary
     information  to fully apply FIN No. 46R to these  contracts.  The  combined
     generation  capacity of the two entities' power plants is approximately 880
     MW. PEC believes that if it is determined to be the primary  beneficiary of
     these two entities,  the effect of consolidating  the entities would result
     in increases to total assets,  long-term  debt and other  liabilities,  but
     would have an insignificant or no impact on PEC's common stock equity,  net
     earnings or cash flows. However, because PEC has not received any financial
     information from these two counterparties,  the impact cannot be determined
     at this time.

     PEC also has  interests in several  other  variable  interest  entities for
     which  PEC is not  the  primary  beneficiary.  These  arrangements  include
     investments in approximately  22 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, 2004, that PEC could be required to record in its income statement as a
     result  of  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.

                                      149
<PAGE>

     D. 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

     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. These deferred fuel costs are recognized in revenues and
     fuel expenses as they are billable to customers.

     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, 2004,  2003 and 2002,  gross
     receipts  tax and other  excise taxes of  approximately  $89  million,  $81
     million and $80 million, respectively, are included in electric revenue and
     taxes other than on income on the Consolidated Statements of Income.

     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  Intercompany  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 carryover 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.  Except for the allocation of this Progress
     Energy tax  benefit,  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 11).

     STOCK-BASED COMPENSATION

     PEC  participates in the stock option  programs  offered by Progress Energy
     (See Note 8B). PEC measures  compensation  expense for stock options as the
     difference  between the market price of Progress  Energy's common stock and
     the exercise  price of the option at the grant date.  The exercise price at
     which options are granted by Progress Energy 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 Progress  Energy'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.

                                      150
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------------------------
(in millions)                                                       2004        2003         2002
-----------------------------------------------------------------------------------------------------
Net income, as reported                                            $ 461       $ 482        $ 431
Deduct:  Total stock option expense determined under fair
     value method for all awards, net of related tax effects           7           6            5
-----------------------------------------------------------------------------------------------------
Pro forma net income                                               $ 454       $ 476        $ 426
-----------------------------------------------------------------------------------------------------
</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.
     Certain  costs  that  would  otherwise  not be  capitalized  under GAAP are
     capitalized in accordance with regulatory  treatment.  The cost of renewals
     and  betterments is also  capitalized.  Maintenance and repairs of property
     (including  planned major  maintenance  activities),  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,
     disposal or  decommissioning  costs that do not represent  ARO's under SFAS
     No. 143 "Accounting for Asset Retirement  Obligations,"  (SFAS No. 143) are
     charged to regulatory liabilities.

     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 system 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.

     ASSET RETIREMENT OBLIGATIONS

     Effective  January 1, 2003,  PEC  adopted  the  guidance in SFAS No. 143 to
     account for legal  obligations  associated  with the  retirement of certain
     tangible long-lived assets. The present value of retirement costs for which
     PEC has a legal  obligation are 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.

     The adoption of this  statement  had no impact on the income of PEC, as the
     effects were offset by the  establishment of a regulatory asset pursuant to
     SFAS No. 71 and related orders by the North Carolina  Utilities  Commission
     (NCUC) and the Public  Service  Commission of South  Carolina  (SCPSC) (See
     Note 6A). The NCUC and SCPSC also issued an order to authorize  deferral of
     all prospective  effects  related to SFAS No. 143 as a regulatory  asset or
     liability. Therefore, SFAS No. 143 has no impact on the income of PEC.

     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 4A). Pursuant to their rate-setting  authority,
     the  NCUC and  SCPSC  can also  grant  approval  to  accelerate  or  reduce
     depreciation and amortization of utility assets.

     Amortization   of  nuclear   fuel  costs  is  computed   primarily  on  the
     units-of-production  method. 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.

                                      151
<PAGE>

     INVENTORY

     PEC accounts for inventory using the average-cost  method.  Inventories are
     valued at the lower cost or market.

     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  Consolidated
     Balance Sheets as regulatory  assets and regulatory  liabilities  (See Note
     6A).

     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 4B.

     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 (See Note 6A).

     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,  unless the  derivatives  meet the SFAS No. 133 criteria for
     normal  purchases or normal sales and are designated as such. PEC generally
     designates  derivative  instruments  as normal  purchases  or normal  sales
     whenever the SFAS No. 133  criteria  are met. If normal  purchase or normal
     sale  criteria are not met, PEC will  generally  designate  the  derivative
     instruments  as cash flow or fair value  hedges if the related SFAS No. 133
     hedge   criteria  are  met.   During  2003,   the  FASB   reconsidered   an
     interpretation  of  SFAS  No.  133.  See  Note  13 for  the  effect  of the
     interpretation  and  additional   information   regarding  risk  management
     activities and derivative transactions.

     ENVIRONMENTAL

     As discussed in Note 17, PEC accrues environmental  remediation liabilities
     when the criteria for SFAS No. 5, "Accounting for  Contingencies," has been
     met. Environmental 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.  Environmental  expenditures  that
     have future  economic  benefits are  capitalized  in accordance  with PEC's
     asset capitalization policy.

     IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS

     PEC 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

                                      152
<PAGE>

     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."

     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 7 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, except
     for any transactions that must be credited directly to equity in accordance
     with the provisions of Staff  Accounting  Bulletin No. 51,  "Accounting for
     Sales of Stock by a Subsidiary."

2.   NEW ACCOUNTING STANDARDS

     FASB STAFF POSITION 106-2,  "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED
     TO THE MEDICARE  PRESCRIPTION  DRUG  IMPROVEMENT AND  MODERNIZATION  ACT OF
     2003"

     In  December  2003,  the  Medicare   Prescription  Drug,   Improvement  and
     Modernization Act of 2003 (Medicare Act) was signed into law. In accordance
     with guidance issued by the FASB in FASB Staff Position 106-1,  "Accounting
     and  Disclosure  Requirements  Related to the  Medicare  Prescription  Drug
     Improvement and Modernization Act of 2003" (FASB Staff Position 106-1), PEC
     elected to defer  accounting  for the  effects of the  Medicare  Act due to
     uncertainties  regarding the effects of the  implementation of the Medicare
     Act and the accounting  for certain  provisions of the Medicare Act. In May
     2004, the FASB issued definitive  accounting  guidance for the Medicare Act
     in FASB Staff  Position  106-2,  which was  effective  for PEC in the third
     quarter of 2004.  FASB Staff Position  106-2 results in the  recognition of
     lower  other  postretirement  employee  benefit  (OPEB)  costs  to  reflect
     prescription  drug-related  federal  subsidies  to be  received  under  the
     Medicare  Act.  As  a  result  of  the  Medicare  Act,  PEC's   accumulated
     postretirement  benefit  obligation  as of January 1, 2004,  was reduced by
     approximately $42 million,  and PEC's 2004 net periodic cost was reduced by
     approximately $7 million.

     STATEMENT  OF  FINANCIAL  ACCOUNTING  STANDARDS  NO.  123  (REVISED  2004),
     "SHARE-BASED PAYMENT" (SFAS NO. 123R)

     In December  2004,  the FASB issued SFAS No. 123R,  which  revises SFAS No.
     123,  "Accounting for Stock-Based  Compensation" and supersedes  Accounting
     Principles  Board (APB)  Opinion No. 25,  "Accounting  for Stock  Issued to
     Employees."  The key  requirement  of SFAS  No.  123R is that  the  cost of
     share-based  awards to employees  will be measured based on an award's fair
     value  at  the  grant  date,  with  such  cost  to be  amortized  over  the
     appropriate  service period.  Previously,  entities could elect to continue
     accounting  for such awards at their grant date  intrinsic  value under APB
     Opinion No. 25, and PEC made that  election.  The  intrinsic  value  method
     resulted in PEC recording no compensation expense for stock options granted
     to employees (See Note 1D).

     SFAS No.  123R will be  effective  for PEC on July 1, 2005.  PEC intends to
     implement  the standard  using the required  modified  prospective  method.
     Under that method, PEC will record compensation expense under SFAS No. 123R
     for  all  awards  it  grants  after  July  1,  2005,  and  it  will  record
     compensation expense (as previous awards continue to vest) for the unvested
     portion of previously  granted  awards that remain  outstanding  at July 1,
     2005. In 2004,  Progress  Energy made the decision to cease  granting stock
     options  and  intends  to  replace  that  compensation  program  with other
     programs.  Therefore,  the amount of stock  option  expense  expected to be
     recorded in 2005 is below the amount  that would have been  recorded if the
     stock option program had continued.  PEC expects to record approximately $1
     million of pre-tax expense for stock options in 2005.

                                      153
<PAGE>

3.   HURRICANE RELATED COSTS

     Hurricanes  Charley and Ivan struck  significant  portions of PEC's service
     territories  during the third  quarter of 2004.  PEC  incurred  restoration
     costs of $13  million,  of which $12 million was charged to  operation  and
     maintenance expense and $1 million was charged to capital expenditures. PEC
     does not have an ongoing  regulatory  mechanism to recover storm costs; and
     therefore,  hurricane  restoration  costs  recorded in the third quarter of
     2004 were  charged  to  operations  and  maintenance  expenses  or  capital
     expenditures based on the nature of the work performed.  In connection with
     other storms,  PEC has previously  sought and received  permission from the
     NCUC  and the  SCPSC to defer  storm  expenses  and  amortize  them  over a
     five-year period.  PEC did not seek deferral of 2004 hurricane  restoration
     costs (See Note 6B).

4.   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)                                          2004         2003
-----------------------------------------------------------------------------
Production plant  (7-33 years)                     $   7,954      $  8,024
Transmission plant  (30-75 years)                      1,212         1,155
Distribution plant  (12-50 years)                      3,701         3,538
General plant and other (8-75 years)                     654           614
-----------------------------------------------------------------------------
Utility plant in service                            $ 13,521      $ 13,331
-----------------------------------------------------------------------------

     Generally,  electric utility plant,  other than nuclear fuel, is pledged as
     collateral for the first mortgage bonds of PEC (See Note 9).

     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 7.2% in 2004,
     4.0% in 2003 and 6.2% in 2002.

     Depreciation   provisions  on  utility  plant,  as  a  percent  of  average
     depreciable  property other than nuclear fuel,  were 2.1% in 2004, and 2.7%
     in 2003 and 2002,  respectively.  The  depreciation  provisions  related to
     utility  plant were $275  million,  $345  million and $326 million in 2004,
     2003 and 2002,  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 4D),  regulatory  approved
     expenses (See Note 6) and clean air amortization (See Note 6B).

     During 2004,  PEC met the  requirements  of both the NCUC and the SCPSC for
     the  implementation  of a  depreciation  study which allowed the utility to
     reduce  the  rates  used to  calculate  depreciation  expense.  The  annual
     reduction  in  depreciation  expense  is  approximately  $82  million.  The
     reduction  is due  primarily  to  extended  lives at each of PEC's  nuclear
     units. The new depreciation rates were effective January 1, 2004.

     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,  for the years ended December 31,
     2004,  2003 and 2002 were $106  million,  $112  million  and $109  million,
     respectively, and are included in fuel used for electric generation.

     B. Diversified Business Property

     Gross diversified business property was $7 million at December 31, 2004 and
     2003,  respectively.  These  amounts  consist  primarily of  buildings  and
     equipment  that are being  depreciated  over periods  ranging from 31 to 65
     years.  Accumulated  depreciation was $2 million and $1 million at December
     31, 2004 and 2003, respectively.  Diversified business depreciation expense
     was $1 million in 2004 and 2003,  and $4 million in 2002.  Net  diversified
     business   property  is  included  in  miscellaneous   other  property  and
     investments on the Consolidated Balance Sheets.

                                      154
<PAGE>

     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):

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------------------------
2004                     Company Ownership        Plant            Accumulated           Construction
        Facility             Interest           Investment         Depreciation         Work in Progress
-------------------------------------------------------------------------------------------------------------
Mayo Plant                    83.83%             $   516           $   249                   $  1
Harris Plant                  83.83%               3,185             1,387                     13
Brunswick Plant               81.67%               1,624               888                     28
Roxboro Unit No. 4            87.06%                 323               147                      1
-------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------
2003                     Company Ownership         Plant          Accumulated            Construction
        Facility             Interest            Investment       Depreciation         Work In Progress
-------------------------------------------------------------------------------------------------------------
Mayo Plant                    83.83%              $   464           $   242                  $ 50
Harris Plant                  83.83%                3,248             1,424                     7
Brunswick Plant               81.67%                1,611               885                    21
Roxboro Unit No. 4            87.06%                  323               139                     1
-------------------------------------------------------------------------------------------------------------
</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. Asset Retirement Obligations

     At  December  31,  2004 and 2003,  the asset  retirement  costs  related to
     nuclear   decommissioning   of  irradiated   plant,   net  of   accumulated
     depreciation, totaled $46 million and $113 million, respectively. Funds set
     aside  in  PEC's  nuclear  decommissioning  trust  funds  for  the  nuclear
     decommissioning liability totaled $580 million and $505 million at December
     31,  2004  and  2003,  respectively.   Net  nuclear  decommissioning  trust
     unrealized gains are included in regulatory liabilities (See Note 6A).

     Decommissioning  cost  provisions,  which are included in depreciation  and
     amortization  expense,  were $31  million  in each of 2004,  2003 and 2002.
     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 expense  recognized  for the disposal or removal of
     utility assets that are not SFAS No. 143 asset removal  obligations,  which
     are included in depreciation  and amortization  expense,  were $83 million,
     $86 million and $81 million in 2004, 2003 and 2002, respectively.

     PEC recognizes  removal,  nonirradiated  decommissioning  and dismantlement
     costs in regulatory  liabilities  on the  Consolidated  Balance Sheets (See
     Note 6A). At December 31, 2004, such costs consist of removal costs of $601
     million and removal costs for nonirradiated  areas at nuclear facilities of
     $70 million.  At December 31, 2003,  such costs consist of removal costs of
     $901  million  and  removal  costs  for  nonirradiated   areas  at  nuclear
     facilities of $67 million.  During 2004, PEC reduced its estimated  removal
     costs to take into account the estimates used in the  depreciation  studies
     implemented during 2004 (See Note 4A). This resulted in a downward revision
     in the PEC  estimated  removal  costs and  equal  increase  in  accumulated
     depreciation of approximately $345 million.

     PEC  re-measured  its ARO for the  nuclear  decommissioning  of  irradiated
     plants to take into  account  updated  site-specific  decommissioning  cost
     studies,  which are  required  by the NCUC  every five  years.  The ARO for
     nuclear decommissioning was reduced by $63 million to $924 million.

     PEC's most recent  site-specific  estimates of  decommissioning  costs were
     developed  in 2004,  using  2004  cost  factors,  and are  based on  prompt
     dismantlement  decommissioning,  which  reflects the cost of removal of all
     radioactive and other  structures  currently at the site, with such removal
     occurring after operating  license  expiration.  These  estimates,  in 2004
     dollars,  are $294  million  for  Robinson  Unit No.  2, $290  million  for
     Brunswick  Unit No.  1,  $313  million  for  Brunswick  Unit No. 2 and $359
     million for the Harris Plant.  The estimates are subject to change based on
     a variety  of factors  including,  but not  limited  to,  cost  escalation,
     changes in technology applicable to nuclear  decommissioning and changes in
     federal, state or local regulations. The cost estimates exclude the portion
     attributable  to North  Carolina  Eastern  Municipal  Power  Agency  (Power
     Agency),  which holds an undivided  ownership interest in the Brunswick and
     Harris nuclear  generating  facilities.  NRC operating licenses held by PEC
     currently  expire in December 2014 and September 2016 for Brunswick Units 2

                                      155
<PAGE>

     and 1,  respectively.  An application to extend these licenses 20 years was
     submitted in October 2004.  The NRC  operating  license held by PEC for the
     Shearon Harris Nuclear Plant (Harris  Plant)  currently  expires in October
     2026.  An  application  to extend  this  license 20 years is expected to be
     submitted  in the  fourth  quarter  of 2006.  On April  19,  2004,  the NRC
     announced  that it has renewed  the  operating  license for PEC's  Robinson
     Nuclear Plant (Robinson) for an additional 20 years through July 2030.

     PEC has identified but not recognized AROs related to electric transmission
     and distribution  assets as the result of easements over property not owned
     by PEC.  These  easements  are generally  perpetual and require  retirement
     action only upon  abandonment  or  cessation of use of the property for the
     specified  purpose.  The ARO 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 would be
     recorded at that time.

     The following table shows the changes to the asset retirement obligations:

--------------------------------------------------------------------
(in millions)
--------------------------------------------------------------------
Asset retirement obligations as of January 1, 2003            $ 880
Accretion expense                                                52
--------------------------------------------------------------------
Asset retirement obligations as of  December 31, 2003           932
Accretion expense                                                55
Deductions                                                      (63)
--------------------------------------------------------------------
Asset retirement obligations as of  December 31, 2004         $ 924
--------------------------------------------------------------------

     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 there under,  following
     a 12-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 $23 million with
     respect  to  the  primary  coverage,   $27  million  with  respect  to  the
     decontamination,  decommissioning  and excess  property  coverage,  and $15
     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 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.

     PEC is insured against public  liability for a nuclear incident up to $10.8
     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
     could possibly approve revisions to the Price Anderson Act during 2005 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.

                                      156
<PAGE>

     PEC self-insures  its transmission and distribution  lines against loss due
     to storm damage and other natural disasters.

5.   CURRENT ASSETS

     RECEIVABLES

     At December 31, receivables were comprised of:

------------------------------------------------------------------------------
(in millions)                                        2004            2003
------------------------------------------------------------------------------
Trade accounts receivable                           $ 240           $ 254
Unbilled accounts receivable                          155             145
Other receivables                                      12              28
Allowance for doubtful accounts receivable            (10)            (17)
------------------------------------------------------------------------------
Total receivables                                   $ 397           $ 410
------------------------------------------------------------------------------

     Income tax receivables and interest income  receivables are not included in
     this  classification.  These amounts are included in prepayments  and other
     current assets on the Consolidated Balance Sheets.

     INVENTORY

     At December 31, inventory was comprised of:

----------------------------------------------------------------------
(in millions)                          2004             2003
----------------------------------------------------------------------
Fuel for production                   $  127            $ 117
Materials and supplies                   263              270
----------------------------------------------------------------------
Total inventory                       $  390            $ 387
----------------------------------------------------------------------

6.   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 that 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 1D).

                                      157
<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)                                                          2004         2003
---------------------------------------------------------------------------------------------
Deferred fuel cost - current (Note 6B)                              $   140        $    66
---------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 6B)                                 28             47
Deferred impact of ARO (Note 1D)                                        305            291
Income taxes recoverable through future rates (Note 11)                  36             33
Loss on reacquired debt (Note 1D)                                        22             22
Storm deferral (Note 3 and 6B)                                           25             21
Deferred DOE enrichment facilities-related costs                         12             19
Other                                                                    45             30
---------------------------------------------------------------------------------------------
     Total long-term regulatory assets                                  473            463
---------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 4D)                                      (671)          (968)
Emission allowance                                                       (8)            (8)
Net nuclear decommissioning trust unrealized gains (Note 4D)           (125)           (99)
Clean air compliance (Note 6B)                                         (248)           (74)
---------------------------------------------------------------------------------------------
     Total long-term regulatory liabilities                          (1,052)        (1,149)
---------------------------------------------------------------------------------------------
         Net regulatory assets (liabilities)                        $  (439)       $  (620)
---------------------------------------------------------------------------------------------
</TABLE>

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

     B. Retail Rate Matters

     As of  December  31,  2004,  PEC's  North  Carolina  retail fuel costs were
     under-recovered  by $145 million.  This amount is comprised of $117 million
     eligible  for recovery in 2005 and $28 million  deferred  from a 2001 order
     from the NCUC that cannot be collected  during 2005, and has therefore been
     classified  as a long-term  asset.  PEC  intends to collect  this amount by
     October 31, 2007.

     On October 15, 2004,  the SCPSC  approved PEC's request to leave fuel rates
     unchanged.  The deferred fuel balance at December 31, 2004, is $23 million.
     This amount is eligible  for  recovery  in PEC's 2005 South  Carolina  fuel
     review.

     PEC   obtained   SCPSC  and  NCUC   approval  of  fuel  factors  in  annual
     fuel-adjustment  proceedings.  The NCUC approved an annual  increase of $62
     million,  $20 million and $46 million by orders  issued in September  2004,
     2003 and 2002,  respectively.  The SCPSC  approved PEC's petition each year
     and the changes were insignificant.

     PEC filed with the SCPSC seeking permission to defer expenses incurred from
     the first quarter 2004 winter storm.  The SCPSC  approved  PEC's request to
     defer the costs and  amortize  them  ratably  over five years  beginning in
     January 2005.  Approximately $9 million related to storm costs was deferred
     in 2004.

     In  October  2003,  PEC filed  with the NCUC  seeking  permission  to defer
     expenses  incurred  from  Hurricane  Isabel and the  February  2003  winter
     storms.  In December  2003,  the NCUC  approved  PEC's request to defer the
     costs  associated with Hurricane Isabel and the February 2003 ice storm and
     amortize them over a period of five years.  PEC charged  approximately  $24
     million in 2003 from  Hurricane  Isabel and from ice storms to the deferred
     account.  PEC recognized $5 million and $3 million of NC storm amortization
     during 2004 and 2003, respectively.

     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 2004 and 2003 and
     additional  depreciation  expense of approximately  $53 million 2002. Total
     accelerated  depreciation  recorded  through  December  31,  2004  was $403
     million.

     The North  Carolina  Clean  Smokestacks  Act enacted in June 2002 (NC Clean
     Air),  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. The
     legislation  provides for  significant  flexibility in the amount of annual
     amortization  recorded,  which  allows  the  utilities  to vary the  amount
     amortized within certain limits.  This flexibility  provides a utility with
     the  opportunity to consider the impacts of other factors on its regulatory
     return on equity when setting the  amortization  amount for each year.  PEC
     recognized  $174 million and $74 million of clean air  amortization  during
     2004 and 2003,  respectively.  This legislation freezes PEC's base rates in
     North Carolina for five years, subject to certain conditions (See Note 17).

                                      158
<PAGE>

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

     In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek
     a base retail  electric rate increase in North  Carolina and South Carolina
     through  December  2004.  The agreement not to seek a base retail  electric
     rate  increase  in  South   Carolina  was  extended  to  December  2005  in
     conjunction with regulatory approval to form a holding company.

     C. Regional Transmission Organizations and Standard Market Design

     In  2000,  the FERC  issued  Order  No.  2000 on RTOs,  which  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 have  materially  alter the  manner in which  transmission  and
     generation  services  are  provided  and paid for. In April 2003,  the FERC
     released a White Paper on the Wholesale  Market  Platform.  The White Paper
     provided an  overview of what the FERC  intended to include in a final rule
     in the SMD NOPR docket.  The White Paper retained 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 cannot predict the outcome
     of  these  matters  or the  effect  that  they  may  have on the  GridSouth
     proceedings  currently  ongoing before the FERC.  However,  by order issued
     December  22,  2004,  the FERC  terminated  a  portion  of the  proceedings
     regarding  GridSouth.  The GridSouth  Companies  asked the FERC for further
     clarification  to the  portions  of the  GridSouth  docket it  intended  to
     address. On March 2, 2005, the FERC affirmed that it only intended to close
     the mediation  portion of the GridSouth  docket.  It is unknown what impact
     the future proceedings will have on PEC's earnings, revenues or prices.

     PEC had $33  million  invested  in  GridSouth  related to startup  costs at
     December  31,  2004.   PEC  expects  to  recover  these  startup  costs  in
     conjunction  with the GridSouth  original  structure or in conjunction with
     any alternate combined transmission structures that emerge.

     D. FERC Market Power Mitigation

     A FERC order  issued in November  2001 on certain  unaffiliated  utilities'
     triennial  market-based wholesale power rate authorization updates required
     certain  mitigation  actions  that those  utilities  would need to take for
     sales/purchases  within their control areas and required those utilities to
     post  information on their Web sites regarding their power systems' status.
     As  a  result  of  a  request  for  rehearing   filed  by  certain   market
     participants,  FERC  issued an order  delaying  the  effective  date of the
     mitigation plan until after a planned technical  conference on market power
     determination.  In December 2003, the FERC issued a staff paper  discussing
     alternatives  and held a technical  conference  in January  2004.  In April
     2004,  the FERC  issued two orders  concerning  utilities'  ability to sell
     wholesale  electricity at market-based  rates. In the first order, the FERC
     adopted two new interim screens for assessing  potential  generation market
     power  of  applicants  for  wholesale  market-based  rates,  and  described
     additional  analyses and mitigation  measures that could be presented if an
     applicant  does not pass one of these interim  screens.  In July 2004,  the
     FERC issued an order on rehearing  affirming its  conclusions  in the April
     order.  In the second  order,  the FERC  initiated a rulemaking to consider
     whether the FERC's current  methodology  for  determining  whether a public
     utility  should be allowed to sell wholesale  electricity  at  market-based
     rates should be modified in any way.  Given the  difficulty PEC believes it
     would experience in passing one of the interim screens, on August 12, 2004,
     PEC notified the FERC that it would revise its Market-based  Rate tariff to
     restrict it to sales outside  PEC's control area and file a new  cost-based
     tariff for sales within PEC's  control  area that  incorporates  the FERC's
     default  cost-based rate  methodologies  for sales of one year or less. PEC
     anticipates  making this filing first quarter of 2005.  Although PEC cannot
     predict the ultimate outcome of these changes, PEC does not anticipate that
     its current  operations would be impacted  materially if PEC were unable to
     sell power at market-based rates in its respective control areas.

                                      159
<PAGE>

     E. Energy Delivery Capitalization Practice

     PEC has reviewed its capitalization policy for its Energy Delivery business
     unit. That review  indicated that in the areas of outage and emergency work
     not  associated  with major storms and  allocation of indirect  costs,  PEC
     should  revise  the way that it  estimates  the  amount  of  capital  costs
     associated  with such work.  PEC has  implemented  such  changes  effective
     January 1, 2005, which include more detailed  classification  of outage and
     emergency  work and  result in more  precise  estimation  and a process  of
     retesting  accounting  estimates  on an  annual  basis.  As a result of the
     changes in  accounting  estimates  for the outage  and  emergency  work and
     indirect costs, a lesser proportion of PEC's costs will be capitalized on a
     going forward  basis.  PEC  estimates  that the impact in 2005 will be that
     approximately  $25 million of costs that would have been capitalized  under
     the previous  policies  will be expensed.  Pursuant to SFAS No. 71, PEC has
     informed the state regulators having  jurisdiction over them of this change
     and that the new estimation  process will be implemented  effective January
     1, 2005.

7.   IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS

     PEC applies SFAS No. 144 for the  accounting and reporting of impairment or
     disposal of  long-lived  assets.  In 2003 and 2002,  PEC  recorded  pre-tax
     long-lived   asset  and  investment   impairments   and  other  charges  of
     approximately $21 million and $133 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.

     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 a pre-tax  impairment of $3
     million on a cost investment.

     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.

8.   EQUITY

     A. Capitalization

     At December 31, 2004,  PEC was authorized to issue up to 200 million shares
     of common  stock.  All shares issued and  outstanding  are held by Progress
     Energy.

                                      160
<PAGE>

     Preferred stock  outstanding at December 31, 2004 and 2003 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>

     PEC's  common stock  increased by $22 million,  $23 million and $26 million
     for the years ended December 31, 2004, 2003 and 2002, respectively, related
     primarily to the allocation of ESOP shares.

     There are various provisions  limiting the use of retained earnings for the
     payment of dividends  under  certain  circumstances.  At December 31, 2004,
     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,  2004,  PEC's common stock
     equity was approximately 52.2% of total capitalization. Refer to Note 9 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 nonbargaining
     unit  employees  and  certain  part-time   nonbargaining  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 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 3.5 million and 4.0 million ESOP suspense shares at December 31,
     2004 and 2003,  respectively,  with a fair value of $156  million  and $183
     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 $12 million,  $11 million and $13
     million for the years ended December 31, 2004, 2003 and 2002, respectively.
     Matching and incentive cost totaled  approximately $18 million, $16 million
     and $14 million  for the years  ended  December  31,  2004,  2003 and 2002,
     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, 2004,
     2003 and 2002, respectively, approximately 28 thousand, 3.0 million and 2.9
     million common stock options were granted. Of these amounts,  approximately
     1.9 million and 1.2 million  options  were granted to officers and eligible
     employees  of PEC in 2003 and 2002,  respectively.  No stock  options  were

                                      161
<PAGE>

     granted to  officers  and  employees  of PEC in 2004.  PEC expects to begin
     expensing  stock  options on July 1, 2005, by adopting new FASB guidance on
     accounting for  stock-based  compensation  (See Note 2). In 2004,  however,
     Progress  Energy made the  decision  to cease  granting  stock  options and
     intends  to  replace  that   compensation   program  with  other  programs.
     Therefore,  the amount of stock option  expense  expected to be recorded in
     2005 is below the amount that would have been  recorded if the stock option
     program had continued.

     The pro forma  information  presented  in Note 1D  regarding  net income 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
     1D have been  determined  as if PEC had  accounted  for its employee  stock
     options under SFAS No. 123.

     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 Progress Energy to grant shares of restricted common
     stock to officers and key employees of PEC. 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 $7  million,  $15  million  and $11  million  in 2004,  2003 and  2002,
     respectively.

     C. Accumulated Other Comprehensive Loss

     Components of accumulated other comprehensive loss are as follows:

------------------------------------------------------------------------
(in millions)                                       2004         2003
------------------------------------------------------------------------
Loss on cash flow hedges                          $   (7)       $  (6)
Minimum pension liability adjustments               (107)          (1)
------------------------------------------------------------------------
Total accumulated other comprehensive loss        $ (114)       $  (7)
------------------------------------------------------------------------

9.   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, 2004):

                                      162
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-----------------------------------------------------------------------------------
(in millions)                                                  2004        2003
-----------------------------------------------------------------------------------
First mortgage bonds, maturing 2005-2033            6.33%      $ 1,600     $ 1,900
Pollution control obligations, maturing 2017-2024   1.98%          669         708
Unsecured notes, maturing 2012                      6.50%          500         500
Medium-term notes, maturing 2008                    6.65%          300         300
Unamortized premium and discount, net                              (19)        (22)
Current portion of long-term debt                                 (300)       (300)
-----------------------------------------------------------------------------------
     Total Long-Term Debt, Net                                 $ 2,750     $ 3,086
-----------------------------------------------------------------------------------
</TABLE>

     At December 31, 2004, PEC had committed lines of credit,  which are used to
     support its  commercial  paper  borrowings  and are included in  short-term
     obligations.  At December 31, 2004, the weighted  average  interest rate on
     borrowings  under the lines of credit was  3.29%.  PEC is  required  to pay
     minimal annual commitment fees to maintain its credit facilities.

     The following table summarizes PEC's credit facilities (in millions):

-------------------------------------------------------------------------
       Desscription              Total      Outstanding        Available
-------------------------------------------------------------------------
364-Day (expiring 7/27/05)      $ 165          $ 90             $  75
3-Year (expiring 7/31/05)         285             -               285
Less:  amounts reserved(a)                                       (131)
-------------------------------------------------------------------------
                                $ 450          $ 90             $ 229
-------------------------------------------------------------------------
     (a)  To the extent amounts are reserved for commercial paper outstanding or
          backing  letters  of credit,  they are not  available  for  additional
          borrowings.

     At  December  31,  2004 and  2003,  PEC had $131  million  and $4  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, 2004 and 2003 were 2.77% and
     2.25%, respectively.

     The combined  aggregate  maturities of long-term debt for 2005 through 2009
     are   approximately,   in  millions,   $300,  $0,  $200,   $300  and  $400,
     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 that are not recorded on the Consolidated  Balance
     Sheets.  At December 31, 2004,  PEC's total debt to total capital ratio was
     52.3%.

     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.

     CROSS-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 apply only to defaults of indebtedness by Progress
     Energy and its significant subsidiaries, which includes PEC.

                                      163
<PAGE>

     The lenders may accelerate payment of any outstanding debt if cross-default
     provisions  are  triggered.  Any such  acceleration  would cause a material
     adverse change in the respective  company's  financial  condition.  Certain
     agreements  underlying 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, 2004,  none of
     PEC's  retained  earnings was  restricted.  Refer to Note 8 for  additional
     dividend restrictions related to PEC's Articles of Incorporation.

     C. Collateralized Obligations

     PEC's first mortgage bonds are collateralized 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,  2004,  PEC had  approximately  $2.269
     billion 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 13.

10.  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,  2004 and 2003,  there  were  miscellaneous
     investments  consisting  primarily of  investments  in  company-owned  life
     insurance  and other  benefit plan assets with  carrying  amounts  totaling
     approximately  $94  million  and $90  million,  respectively,  included  in
     miscellaneous  other property and investments in the  Consolidated  Balance
     Sheets.  The carrying amount of these  investments  approximates fair value
     due to the  short  maturity  of  certain  instruments.  Other  instruments,
     including short-term investments, are presented at fair value in accordance
     with GAAP. The carrying amount of PEC's long-term debt,  including  current
     maturities,  was $3.050 billion and $3.386 billion at December 31, 2004 and
     2003, respectively. The estimated fair value of this debt, as obtained from
     quoted market prices for the same or similar issues, was $3.307 billion and
     $3.686 billion at December 31, 2004 and 2003, 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.

11.  INCOME TAXES

     Deferred income taxes have been provided for temporary  differences.  These
     occur when there are differences  between 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.   To  the  extent  that  the
     establishment of deferred income taxes under SFAS No. 109,  "Accounting for
     Income  Taxes,"  (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 utility pursuant to rate orders.

                                      164
<PAGE>

     Accumulated deferred income tax assets (liabilities) at December 31 are:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------
(in millions)                                                        2004         2003
---------------------------------------------------------------------------------------
 Current deferred tax asset - other
    Included in prepayments and other current assets                   36           16
---------------------------------------------------------------------------------------
Noncurrent deferred tax asset (liability)
    Investments                                                         4            5
    Supplemental executive retirement plans                             9            7
    Other post-employment benefits (OPEB)                              52           46
    Other pension plans                                                56           (8)
    Income tax credit carry forward                                    21           22
    Accumulated depreciation and property cost differences           (960)      (1,066)
    Deferred costs                                                    (13)          26
    Deferred fuel                                                     (55)          31
    Valuation allowance                                                (1)          (1)
    Miscellaneous other temporary differences, net                     (1)         (39)
---------------------------------------------------------------------------------------
Total noncurrent deferred tax liability                              (888)        (977)
---------------------------------------------------------------------------------------
</TABLE>

     Total  deferred  income tax  liabilities  were  $1,713  million  and $1,758
     million at December 31, 2004 and 2003, respectively.  Total deferred income
     tax assets  were $861  million and $797  million at  December  31, 2004 and
     2003,  respectively.   Total  noncurrent  income  tax  liabilities  on  the
     Consolidated  Balance  Sheets at December  31, 2004 and 2003  include  $103
     million and $80 million, respectively, related to probable tax liabilities,
     on which PEC accrues  interest  that would be payable  with the related tax
     amount  in  future  years.   All  tax   contingency   reserves   relate  to
     capitalization and basis issues.

     The federal  income tax credit carry  forward at December 31, 2004 consists
     of $21 million of general  business credit with a carry forward period that
     will begin to expire in 2020.

     PEC did not  establish any  additional  valuation  allowances in 2004.  PEC
     established  additional  valuation  allowances of $1 million and $4 million
     during 2003 and 2002,  respectively,  due to the  uncertainty  of realizing
     certain future state tax benefits. 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:

------------------------------------------------------------------------------
                                                 2004       2003      2002
------------------------------------------------------------------------------
Effective income tax rate                        34. 1%     32.3%     32.5%
State income taxes, net of federal benefit       (2.9)      (1.9)     (3.1)
Investment tax credit amortization                1.1        1.4       1.9
Progress Energy tax benefit allocation            3.0        3.0       5.0
AFUDC amortization                               (0.5)      (1.5)     (5.8)
Other differences, net                            0.2        1.7       4.5
------------------------------------------------------------------------------
Statutory federal income tax rate                35.0%      35.0%     35.0%
------------------------------------------------------------------------------

                                      165
<PAGE>

     Income  tax  expense  (benefit)  applicable  to  continuing  operations  is
     comprised of:

-----------------------------------------------------------------------------
(in millions)                                2004        2003        2002
-----------------------------------------------------------------------------
Income tax expense (credit):
Current  - federal                           $ 232       $ 283       $ 265
           state                                33          37          36
Deferred - federal                             (18)        (56)        (76)
           state                                (1)        (13)         (6)
Investment tax credit                           (7)        (10)        (12)
-----------------------------------------------------------------------------
       Total income tax expense              $ 239       $ 241       $ 207
-----------------------------------------------------------------------------

     PEC and each of its  wholly  owned  subsidiaries  have  entered  into a Tax
     Agreement  with  Progress  Energy  (See Note 1D).  PEC's  intercompany  tax
     receivable  was $62 million and $40 million at December  31, 2004 and 2003,
     respectively.

12.  BENEFIT PLANS

     PEC and some of its  subsidiaries  have a  noncontributory  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)                          2004          2003         2002        2004      2003      2002
--------------------------------------------------------------------------------------------------------
Service cost                        $      24    $     23   $       19     $      6  $      7  $      6
Interest cost                              52          51           51           15        15        14
Expected return on plan assets            (69)        (70)         (73)          (4)       (3)       (3)
Amortization, net                           1           -            1            3         5         2
--------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit)       $       8    $      4    $     (2)     $     20  $     24  $     19
--------------------------------------------------------------------------------------------------------
</TABLE>

     Net periodic cost for other  postretirement  benefits decreased during 2004
     due to the implementation of FASB Staff Position 106-2 (See Note 2).

     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.

                                      166
<PAGE>

     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)                                      2004         2003              2004              2003
-----------------------------------------------------------------------------------------------------------
Obligation at January 1                        $      837   $       802       $      218        $      234
Service cost                                           24            23                6                 7
Interest cost                                          52            51               15                15
Plan amendment                                         14             -                -                 -
Benefit payments                                      (50)          (46)              (5)               (8)
Actuarial loss (gain)                                  51             7               28               (30)
-----------------------------------------------------------------------------------------------------------
Obligation at December 31                             928           837              262               218
Fair value of plan assets at December 31              753           694               45                43
-----------------------------------------------------------------------------------------------------------
Funded status                                        (175)         (143)            (217)             (175)
Unrecognized transition obligation                      -             -                9                23
Unrecognized prior service cost                        18             4                -                 -
Unrecognized net actuarial (gain) loss                181           150               36                (1)
Minimum pension liability adjustment                 (194)           (2)               -                 -
-----------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net     $     (170)  $         9       $     (172)       $     (153)
-----------------------------------------------------------------------------------------------------------
</TABLE>

     The 2003 OPEB  obligation  information  above has been  restated due to the
     implementation of FASB Staff Position 106-2 (See Note 2).

     The net accrued  pension  cost of $170  million at December  31,  2004,  is
     included in accrued pension and other benefits in the Consolidated  Balance
     Sheets. The net prepaid pension cost of $9 million at December 31, 2003, is
     recognized in the  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 accrued pension
     and other  benefits.  The defined  benefit  pension plans with  accumulated
     benefit  obligations  in  excess  of  plan  assets  had  projected  benefit
     obligations  totaling $928 million and $22 million at December 31, 2004 and
     2003,  respectively.   Those  plans  had  accumulated  benefit  obligations
     totaling  $923  million and $19  million,  at  December  31, 2004 and 2003,
     respectively,  plan assets of $753 million at December 31, 2004 and no plan
     assets at December 31, 2003. The total accumulated  benefit  obligation for
     pension  plans was $923  million and $834  million at December 31, 2004 and
     2003,  respectively.  The accrued OPEB cost is included in accrued  pension
     and other benefits in the Consolidated Balance Sheets.

     A minimum  pension  liability  adjustment  of $194  million was recorded at
     December 31, 2004. This  adjustment  resulted in a charge of $18 million to
     intangible  assets,  included in other  assets and deferred  debits,  and a
     pre-tax charge of $176 million to accumulated other  comprehensive  loss, a
     component of common stock equity. A minimum pension liability adjustment of
     $2 million was recorded at December 31, 2003. This adjustment was offset by
     a corresponding  pre-tax charge 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)                                      2004       2003           2004      2003
--------------------------------------------------------------------------------------------
Fair value of plan assets January 1               $ 693      $ 574           $ 43      $ 33
Actual return on plan assets                         89        165              5        10
Benefit payments                                    (50)       (46)            (5)       (8)
Employer contributions                               21          1              2         8
--------------------------------------------------------------------------------------------
Fair value of plan assets at December 31          $ 753      $ 694           $ 45      $ 43
--------------------------------------------------------------------------------------------
</TABLE>

     In the table  above,  substantially  all employer  contributions  represent
     benefit  payments made directly from PEC assets except for the 2004 pension
     amount.  The  remaining  benefits  payments  were made  directly  from plan
     assets. In 2004, PEC made a contribution directly to pension plan assets of
     approximately  $20 million,  which  represented  its  allocated  share of a
     required Progress Energy contribution.  The OPEB benefit payments represent
     the net PEC cost after participant contributions. Participant contributions
     represent approximately 40% of gross benefit payments.

                                      167
<PAGE>

     The asset  allocation  for PEC's  plans at the end of 2004 and 2003 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       Target      Percentage of Plan
                           Allocations       Assets at Year End    Allocations    Assets at Year End
                           -------------    --------------------   -----------    ------------------
Asset Category                 2005             2004      2003         2005         2004      2003
----------------------------------------------------------------------------------------------------
  Equity - domestic             48%              47%       49%           48%         47%        49%
  Equity - international        15%              21%       22%           15%         21%        22%
  Debt - domestic               12%               9%       11%           12%          9%        11%
  Debt - international          10%              11%       11%           10%         11%        11%
  Other                         15%              12%        7%           15%         12%         7%
----------------------------------------------------------------------------------------------------
  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 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 2005,  PEC expects to make no  contributions  directly  to pension  plan
     assets. The expected benefit payments for the pension benefit plan for 2005
     through 2009 and in total for  2010-2014,  in millions,  are  approximately
     $59,  $57,  $58,  $62, $64 and $375,  respectively.  The  expected  benefit
     payments  for the  OPEB  plan  for  2005  through  2009  and in  total  for
     2010-2014, in millions, are approximately $14, $15, $16, $16, $17, and $98,
     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.  PEC  expects to begin  receiving  prescription
     drug-related  federal  subsidies  in 2006  (See Note 2),  and the  expected
     subsidies  for 2006 through 2009 and in total for  2010-2014,  in millions,
     are  approximately  $1,  $1,  $1, $2 and $10,  respectively.  The  expected
     benefit  payments  above do not reflect the  potential  effects of the 2005
     voluntary enhanced retirement program (See Note 18).

     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
                                                                 ----------------     -----------------------------
                                                                   2004       2003        2004            2003
-------------------------------------------------------------------------------------------------------------------
Discount rate                                                     5.90%      6.30%       5.90%           6.30%
Rate of increase in future compensation - supplementary plan      5.25%      5.00%          -               -
Initial medical cost trend rate for pre-Medicare benefits            -          -        7.25%           7.25%
Initial medical cost trend rate for post-Medicare benefits           -          -        7.25%           7.25%
Ultimate medical cost trend rate                                     -          -        5.00%           5.25%
Year ultimate medical cost trend rate is achieved                    -          -        2008            2009
--------------------------------------------------------------------------------------------------- ---------------
</TABLE>

     PEC's primary defined benefit  retirement plan for nonbargaining  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. 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.

                                      168
<PAGE>

     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
                                                              -------------------------   -------------------------------
                                                              2004     2003      2002       2004      2003         2002
-------------------------------------------------------------------------------------------------- --------- ------------
Discount rate                                                   6.30%    6.60%    7.50%     6.30%     6.60%        7.50%
Rate of increase in future compensation - nonbargaining             -    4.00%    4.00%        -         -            -
Rate of increase in future compensation - supplementary plan    5.00%    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%
-------------------------------------------------------------------------------------------------- --------- ------------
</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 9.0% and
     9.5%. PEC has chosen to use an expected long-term rate of 9.25%.

     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 2004 would  increase by $1 million,  and
     the OPEB  obligation at December 31, 2004,  would  increase by $14 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
     2004 would  decrease by $1 million and the OPEB  obligation at December 31,
     2004, would decrease by $13 million.

13.  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  nonperformance  by  counterparties  is not  expected  to  have a
     material  effect on the  consolidated  financial  position or  consolidated
     results of operations of PEC.

     A. Commodity Derivatives

     GENERAL

     Most of PEC'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 PEC. 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
     original  liability of $38 million  associated  with the fair value loss is
     being  amortized  to  earnings  over the term of the related  contract.  At
     December 31, 2004 and 2003, the remaining liability was $26 million and $35
     million, respectively.

     ECONOMIC DERIVATIVES

     Derivative products,  primarily electricity and natural gas contracts,  are
     entered into 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  to results of  operations
     during  2004,  2003 or  2002,  and PEC did not  have  material  outstanding
     positions in such contracts at December 31, 2004 or 2003.

                                      169
<PAGE>

     CASH FLOW HEDGES

     PEC 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.  As of December 31, 2004, PEC had $110
     million notional amount of pay-fixed forward swaps to hedge its exposure to
     interest rates with regard to future  issuances of debt (pre-issue  hedges)
     and $21 million  notional  amount of pay-fixed  forward  starting  swaps to
     hedge its  exposure  to interest  rates with regard to an upcoming  railcar
     lease. On February 4, 2005, PEC entered another $50 million notional amount
     of its pre-issue hedges.  All the swaps have a computational  period of ten
     years.  These hedges had a fair value  liability  position of $2 million at
     December 31,  2004.  PEC had no open cash flow hedges at December 31, 2003.
     The ineffective  portion of interest rate cash flow hedges was not material
     to PEC's results of operations in 2004. As of December 31, 2004, PEC had $7
     million of after-tax  deferred  losses in accumulated  other  comprehensive
     income (OCI),  including amounts related to terminated  hedges, of which $1
     million is  expected  to be  reclassified  to  earnings  within the next 12
     months.  Due to the  volatility  of  interest  rates,  the  value in OCI is
     subject to change prior to its reclassification into earnings.

     FAIR VALUE HEDGES

     PEC uses fair value  hedging  strategies  to manage its  exposure  to fixed
     interest rates on long-term debt. At December 31, 2004 and 2003, 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.

14.  RELATED PARTY TRANSACTIONS

     The Company's  subsidiaries  provide and receive services,  at cost, to and
     from Progress  Energy and its  subsidiaries,  in accordance with agreements
     approved by the U.S.  Securities and Exchange  Commission (SEC) pursuant to
     Section 13(b) of the PUHCA.  Services include purchasing,  human resources,
     accounting,   legal,   transmission  and  delivery   support,   engineering
     materials,  contract support, loaned employees payroll costs, constructions
     management  and other  centralized  administrative,  management and support
     services.  The costs of the services are billed on a  direct-charge  basis,
     whenever possible,  and on allocation factors for general costs that cannot
     be  directly  attributed.  Billings  from  affiliates  are  capitalized  or
     expensed  depending  on  the  nature  of  the  services  rendered.  Amounts
     receivable  from and/or payable to affiliated  companies for these services
     are  included in  receivables  from  affiliated  companies  and payables to
     affiliated companies on the Consolidated Balance Sheets.

     Progress Energy Service  Company,  LLC, (PESC) provides the majority of the
     affiliated services under the approved agreements. Service provided by PESC
     during 2004,  2003 and 2002 to PEC amounted to $209  million,  $184 million
     and $198 million, respectively. Based on a standard review by the Office of
     Public Utility  Regulation within the SEC the method for allocating certain
     PESC governance  costs changed and retroactive  reallocations  for 2002 and
     2001  charges  were  recorded  in 2003.  The net  after-tax  impact  of the
     reallocation of costs was a reduction of expenses at PEC by $10 million.

     PEC and an  affiliated  utility also provide and receive  services at cost.
     Services  provided by PEC during 2004, 2003 and 2002 amount to $52 million,
     $35 million and $72 million, respectively.  Services received by PEC during
     2004,  2003 and 2002 amount to $16  million,  $7 million  and $16  million,
     respectively.

     To facilitate  commercial  transactions of Progress Energy's  subsidiaries,
     Progress Energy and certain wholly owned subsidiaries enter into agreements
     providing future financial or performance  assurances to third parties.  As
     of December 31, 2004,  Progress Energy's guarantees include $181 million to
     support nuclear  decommissioning.  PEC determined that its external funding
     levels did not fully meet the nuclear  decommissioning  financial assurance
     levels required by NRC,  therefore PEC obtained parent company  guarantees.
     The  Company  and PEC also  purchased  $43  million  of  surety  bonds  and
     authorized  the  issuance  of  standby   letters  of  credit  by  financial
     institutions of $4 million on behalf of PEC.

                                      170
<PAGE>

     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 is also used to settle  intercompany  balances.
     The weighted-average  interest rate for the money pool was 1.72%, 1.47% and
     2.18% at December 31, 2004, 2003 and 2002, respectively. Amounts payable to
     the money pool are included in notes payable to affiliated companies on the
     Consolidated  Balance Sheets. PEC recorded  insignificant  interest expense
     related to the money pool for all the years presented.

     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 and 2002,  gas sales from NCNG to PEC  amounted  to $11
     million and $18  million,  respectively.  The gas sales for 2003  indicated
     above exclude any sales  subsequent to September 2003.  Strategic  Resource
     Solutions,  Corp. and its  subsidiary,  which were wholly owned until 2004,
     managed  subcontracts  for PEC.  Amounts for the three years presented were
     not significant.  PEC has entered into a Tax Agreement with Progress Energy
     (See Note 11).

15.  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.

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
-------------------------------------------------------------------------------------------------
(in millions)                               PEC Electric          Other              Total
-------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
Revenues                                       $ 3,628            $    1           $  3,629
Depreciation and amortization                      570                 -                570
Total interest charges, net                        192                 -                192
Income tax expense (benefit)                       237                 2                239
Income (loss) excluding cumulative effect          464               (6)                458
Total segment assets                            10,590               197             10,787
Capital and investment
    expenditures                                   519                 -                519
-------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Revenues                                       $ 3,589            $   11           $  3,600
Depreciation and amortization                      562                 1                563
Total interest charges, net                        197                 -                197
Impairment of long-lived assets &
    investments                                     11                10                 21
Income tax expense (benefit)                       238                 3                241
Income (loss) excluding cumulative effect          515               (13)               502
Total segment assets                            10,748               190             10,938
Capital and investment
    expenditures                                   445                 1                446
-------------------------------------------------------------------------------------------------
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 tax expense (benefit)                       237               (30)               207
Income (loss) excluding cumulative effect          513               (85)               428
Total segment assets                            10,139               266             10,405
Capital and investment
    expenditures                                   619                12                631
-------------------------------------------------------------------------------------------------
</TABLE>

                                      171
<PAGE>

16.  OTHER INCOME AND OTHER EXPENSE

     Other  income  and  expense  includes   interest   income,   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 years ended December 31, are as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
---------------------------------------------------------------------------------------
(in millions)                                               2004      2003      2002
---------------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income            $ 15      $ 12      $ 16
DIG Issue C20 amortization (Note 13A)                          9         2         -
AFUDC equity                                                   4         2         6
Gain on sale of property                                      12         6         3
Other                                                          2         -        16
---------------------------------------------------------------------------------------
    Total other income                                      $ 42      $ 22      $ 41
---------------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses          $  9      $  9      $ 14
Donations                                                      7         6         7
Losses from Equity Investments                                 1        16         7
Other                                                         14         2         -
---------------------------------------------------------------------------------------
   Total other expense                                      $ 31      $ 33      $ 28
---------------------------------------------------------------------------------------
Other, net                                                    11       (11)       13
---------------------------------------------------------------------------------------
</TABLE>

     Nonregulated energy and delivery services include power protection services
     and mass market programs  (surge  protection,  appliance  services and area
     light  sales) and  delivery,  transmission  and  substation  work for other
     utilities.

17.  ENVIRONMENTAL MATTERS

     PEC is subject to federal, state and local regulations addressing hazardous
     and solid waste management,  air and water quality and other  environmental
     matters.

     HAZARDOUS AND SOLID WASTE MANAGEMENT

     The provisions of the Comprehensive  Environmental  Response,  Compensation
     and  Liability  Act of 1980,  as  amended  (CERCLA),  authorize  the EPA to
     require  the  cleanup  of  hazardous  waste  sites.  This  statute  imposes
     retroactive joint and several liabilities. Some states, including North and
     South  Carolina,  have similar types of  legislation.  PEC is  periodically
     notified by  regulators  including  the EPA and various  state  agencies of
     their  involvement  or  potential  involvement  in sites  that may  require
     investigation  and/or  remediation.  There are presently several sites with
     respect  to which PEC has been  notified  by the EPA and the State of North
     Carolina of its potential liability,  as described below in greater detail.
     PEC is also  currently  in the  process of  assessing  potential  costs and
     exposures at other sites.  For all sites,  assessments  are  developed  and
     analyzed,  PEC will accrue  costs for the sites to the extent the costs are
     probable and can be reasonably estimated.

     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).

     PEC has filed  claims  with its  general  liability  insurance  carriers to
     recover costs arising from actual or potential  environmental  liabilities.
     All claims have been  settled  other than with  insolvent  carriers.  These
     settlements  have not had a material effect on the  consolidated  financial
     position or results of operations.

                                      172
<PAGE>

     ENVIRONMENTAL LIABILITIES

     There are nine former MGP sites and a number of other sites associated with
     PEC that have required or are anticipated to require  investigation  and/or
     remediation costs.

     During the fourth  quarter of 2004,  the EPA  advised  PEC that it had been
     identified as a PRP at the Ward Transformer site located in Raleigh,  North
     Carolina.  The EPA  offered  PEC  and 34  other  PRPs  the  opportunity  to
     negotiate  cleanup of the site and reimbursement of less than $2 million to
     the EPA for EPA's past  expenditures in addressing  conditions at the site.
     Although a loss is  considered  probable,  an agreement  among PRPs has not
     been reached;  consequently,  it is not possible at this time to reasonably
     estimate the total amount of PEC's  obligation for  remediation of the Ward
     Transformer site.

     At December 31, 2004 and 2003,  PEC's  accruals for probable and  estimable
     costs related to various  environmental  sites, which are included in other
     liabilities and deferred  credits and are expected to be paid out over many
     years, were:

-----------------------------------------------------------------------
(in millions)                                         2004        2003
-----------------------------------------------------------------------
Insurance fund                                         $ 7        $  9
Transferred from NCNG at time of sale                    2           2
-----------------------------------------------------------------------
Total accrual for environmental sites                  $ 9        $ 11
-----------------------------------------------------------------------

     PEC  received   insurance   proceeds  to  address  costs   associated  with
     environmental  liabilities  related to its involvement with some sites. All
     eligible  expenses  related to these are  charged  against a specific  fund
     containing  these proceeds.  PEC spent  approximately $2 million related to
     environmental  remediation in 2004. PEC is unable to 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.
     Because the extent of environmental  impact,  allocation among PRPs for all
     sites,  remediation  alternatives  (which could involve  either  minimal or
     significant  efforts),  and concurrence of the regulatory  authorities have
     not yet reached the stage where a  reasonable  estimate of the  remediation
     costs  can be made,  PEC  cannot  determine  the  total  costs  that may be
     incurred in connection  with the  remediation of all sites at this time. It
     is  anticipated  that  sufficient  information  will become  available  for
     several  sites  during  2005  to  allow  a  reasonable  estimate  of  PEC's
     obligation for those sites to be made.

     AIR QUALITY

     Congress is considering  legislation  that would require  reductions in air
     emissions of 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 PEC's
     consolidated financial position or results of operations. Control equipment
     that will be installed on North Carolina  fossil  generating  facilities as
     part of the NC Clean Air  legislation  discussed  below may address some of
     the issues outlined above.  However, PEC cannot predict the outcome of this
     matter.

     The EPA is  conducting  an  enforcement  initiative  related to a number of
     coal-fired  utility power plants in an effort to determine  whether changes
     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
     supplying 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,  in excess of $1.0 billion.
     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 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 the Federal Appeals Court and
     its  implementation  stayed.  In  July  2004,  the  EPA  announced  it will
     reconsider   certain  issues  arising  from  the  final  routine  equipment
     replacement  rule. The comment period closed on August 30, 2004. PEC cannot
     predict the outcome of this matter.

                                      173
<PAGE>

     In 1998,  the EPA published a final rule under Section 110 of the Clean Air
     Act  addressing  the  regional  transport  of ozone (NOx SIP  Call).  Total
     capital  expenditures to meet the  requirements of the NOx SIP Call Rule in
     North and South Carolina could reach  approximately  $370 million.  PEC has
     spent  approximately  $282  million  to date  related  to  these  projected
     amounts.  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.

     In 1997, the EPA issued final  regulations  establishing a new 8-hour ozone
     standard.  In April  2004,  the EPA  identified  areas that do not meet the
     standard.  The states  with  identified  areas,  including  North and South
     Carolina,  are  proceeding  with the  implementation  of the federal 8-hour
     ozone  standard.  Both states  promulgated  final  regulations,  which will
     require PEC to install NOx  controls  under the states'  programs to comply
     with the 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  requirements  for  additional  controls  at some
     units. PEC cannot predict the outcome of this matter.

     In June 2002,  the NC Clean Air  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 projects that its capital
     costs to meet these emission targets will total  approximately $895 million
     by the end of 2013.  PEC has expended  approximately  $108 million of these
     capital costs through  December 31, 2004.  PEC currently has  approximately
     5,100  MW of  coal-fired  generation  capacity  in North  Carolina  that is
     affected by this Act.  The law  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 law 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.  The  law  requires  PEC  to  amortize  $569  million,
     representing 70% of the original cost estimate of $813 million,  during the
     five-year rate freeze period.  PEC recognized  amortization of $174 million
     and  $74  million  for  the  years  ended  December  31,  2004,  and  2003,
     respectively,  and has recognized  $248 million in cumulative  amortization
     through December 31, 2004. The remaining  amortization  requirement of $321
     million will be recorded over the  three-year  period  ending  December 31,
     2007. The law permits PEC the flexibility to vary the amortization schedule
     for  recording  of the  compliance  costs from none up to $174  million per
     year. The NCUC will hold a hearing prior to December 31, 2007, to determine
     cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC
     entered into an agreement  with the State of North  Carolina to transfer to
     the  State  certain  NOx and SO2  emissions  allowances  that  result  from
     compliance with the collective NOx and SO2 emissions limitations set out in
     the law.  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
     concluded  that mercury is not a risk to the average  person in America 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 alternative control
     plans that would limit mercury emissions from coal-fired power plants.  The
     final rule was released on March 15,  2005.  The EPA's rule  establishes  a
     mercury cap and trade  program for  coal-fired  power plants that  requires
     limits to be met in two  phases,  in 2010 and 2018.  PEC is  reviewing  the
     final rule. Installation of additional air quality controls is likely to be
     needed to meet the mercury rule's  requirements.  Compliance  plans and the
     cost to comply  with the rule will be  determined  once PEC  completes  its
     review.

     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. PEC does not have units impacted by this proposal.
     The EPA expects to finalize the nickel rule in March 2005.

     In December  2003,  the EPA released its  proposed  Interstate  Air Quality
     Rule,  currently  referred to as the Clean Air Interstate Rule (CAIR).  The
     final rule was  released  on March 10,  2005.  The EPA's rule  requires  28
     states and the District of  Columbia,  including  North  Carolina and South
     Carolina,  to reduce NOx and SO2  emissions in order to attain preset state
     NOx and SO2 emissions levels. PEC is reviewing the final rule. Installation

                                      174
<PAGE>

     of additional air quality  controls is likely to be needed to meet the CAIR
     requirements. Compliance plans and the cost to comply with the rule will be
     determined once PEC completes its review.  The air quality controls already
     installed for compliance with the NOx SIP Call and currently planned by PEC
     to comply with the NC Clean Air legislation  will reduce the costs required
     to meet the CAIR requirements for PEC's North Carolina units.

     In March 2004,  the North Carolina  Attorney  General filed a petition with
     the EPA  under  Section  126 of the  Clean  Air  Act,  asking  the  federal
     government to force coal-fired  power plants in 13 other states,  including
     South  Carolina to reduce their NOx and SO2  emissions.  The state of North
     Carolina  contends  these  out-of-state   emissions  interfere  with  North
     Carolina's  ability to meet  national air quality  standards  for ozone and
     particulate  matter.  The EPA has  agreed  to make a  determination  on the
     petition by August 1, 2005. PEC 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 at the affected  facilities.  Integration of these new wastewater
     streams  into the existing  wastewater  treatment  processes  may result in
     permitting,  construction and treatment  requirements imposed on PEC in the
     immediate and extended future.

     After many years of litigation and settlement negotiations, the EPA adopted
     regulations in February 2004 to implement Section 316(b) of the Clean Water
     Act. These regulations  became effective  September 7, 2004. 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. PEC currently estimates that from 2005 through 2009
     the range of its  expenditures  to meet the Section 316(b)  requirements of
     the Clean Water Act will be $20 million to $30 million.

     OTHER ENVIRONMENTAL MATTERS

     The Kyoto  Protocol  was  adopted in 1997 by the United  Nations to address
     global  climate  change by reducing  emissions of carbon  dioxide and other
     greenhouse  gases. In 2004,  Russia  ratified the Protocol,  and the treaty
     went into effect on February  16, 2005.  The United  States has not adopted
     the  Kyoto  Protocol,  and the Bush  administration  has  stated  it favors
     voluntary programs.  A number of carbon dioxide emissions control proposals
     have been advanced in Congress.  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 of control or limitation  cannot
     be recovered  from  customers.  PEC favors the voluntary  program  approach
     recommended by the administration and continually evaluates options for the
     reduction,  avoidance and sequestration of greenhouse gases.  However,  PEC
     cannot predict the outcome of this matter.

     Progress Energy has announced its plan to issue a report on it's activities
     associated with current and future environmental  requirements.  The report
     will include a discussion of the  environmental  requirements  that the PEC
     currently faces and expects to face in the future, as well as an assessment
     of potential mandatory constraints on carbon dioxide emissions.  The report
     will be issued by March 31, 2006.

18.  COMMITMENTS AND CONTINGENCIES

     A. Purchase Obligations

     The following table reflects PEC's  contractual  cash obligations and other
     commercial  commitments at December 31, 2004, in the respective  periods in
     which they are due.

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------
(in millions)                    2005     2006     2007      2008     2009   Thereafter
----------------------------------------------------------------------------------------
Fuel                            $ 649    $ 450    $ 393     $ 126    $ 135      $   586
Purchased power                   137      130      125        84       86          526
Other Purchase Obligations         12        -        -         -        -           13
----------------------------------------------------------------------------------------
Total                           $ 798    $ 580    $ 518     $ 210    $ 221      $ 1,125
----------------------------------------------------------------------------------------
</TABLE>

                                      175
<PAGE>

     FUEL AND PURCHASED POWER

     PEC has entered into various long-term fuel contracts for coal, oil and gas
     requirements  of  its  generating   plants.   Total  payments  under  these
     commitments were $477 million,  $562 million and $524 million in 2004, 2003
     and 2002, respectively.

     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  and  energy  costs,  total   approximately  $38  million.   These
     contractual  purchases totaled $39 million, $36 million and $36 million for
     2004, 2003 and 2002, 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, 2004, 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  estimated   minimum   annual   payments  of
     approximately  $43 million,  representing  capital-related  capacity costs.
     Estimated  annual payments for energy and capacity costs are  approximately
     $72  million   through  2009.   Total  purchases   (including   energy  and
     transmission  use  charges)  under the Rockport  agreement  amounted to $63
     million, $66 million and $59 million for 2004, 2003 and 2002, respectively.

     PEC executed two long-term  agreements for the purchase of power from Broad
     River LLC's Broad River facility.  One 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.  The second  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  for both
     capacity  and  energy  under the Broad  River  agreements  amounted  to $42
     million, $37 million and $38 million in 2004, 2003 and 2002 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 2012.  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 $91 million, $113 million and $145
     million in 2004, 2003 and 2002, respectively.

     CONSTRUCTION OBLIGATIONS

     At December 31, 2004, PEC has no construction obligations.  Total purchases
     under various combustion turbine construction  obligations were $5 million,
     $21 million and $13 million for 2004, 2003 and 2002, respectively.

     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. During 2004 and
     2003, no capital parts have been purchased under this contract.

     PEC has  various  purchase  obligations  related  to  reactor  vessel  head
     replacements,  power uprates and spent fuel storages. Total purchases under
     these  contracts were $17 million for 2004 and $3 million for 2003.  Future
     purchase obligations are $12 million for 2005.

     PEC  incurred  expenses  related  to  various  other  purchase  obligations
     allocated  from PESC of $8  million  for 2004 and 2003 and $4  million  for
     2002.

                                      176
<PAGE>

     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 $20 million for 2004 and 2003 and
     $22 million for 2002.  These amounts  include rent expense  allocated  from
     PESC of $11 million,  $10 million and $12 million for 2004,  2003 and 2002,
     respectively.  Purchased  power  expense  under  agreements  classified  as
     operating leases were  approximately $24 million during 2004 and $5 million
     during 2003. Assets recorded under capital leases consist of:

-----------------------------------------------------------------
(in millions)                              2004          2003
-----------------------------------------------------------------
Buildings                                $   30         $  30
Less:  Accumulated amortization             (11)          (10)
-----------------------------------------------------------------
                                         $   19         $  20
-----------------------------------------------------------------

     Minimum annual payments,  excluding executory costs such as property taxes,
     insurance and maintenance, under long-term noncancelable leases at December
     31, 2004, are:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
------------------------------------------------------------------------------------
(in millions)                                     Capital Leases    Operating Leases
------------------------------------------------------------------------------------
2005                                                     $ 2          $  28
2006                                                       2             24
2007                                                       2             13
2008                                                       2             13
2009                                                       2             12
Thereafter                                                25             97
------------------------------------------------------------------------------------
                                                        $ 35          $ 187
                                                                   -----------------
Less amount representing imputed interest                (16)
-------------------------------------------------------------------
Present value of net minimum lease payments             $ 19
------------------------------------------------------------------------------------
</TABLE>

     PEC is the lessor of electric  poles,  streetlights  and other  facilities.
     Minimum rentals receivables under  noncancelable  leases are $9 million for
     2005 and none thereafter.  Rents received totaled $32 million,  $31 million
     and $28 million for 2004, 2003 and 2002, respectively.

     C. Claims and Uncertainties

     OTHER CONTINGENCIES

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

     DOE failed to begin  taking  spent  nuclear  fuel by January 31,  1998.  In
     January  2004,  PEC filed a complaint in the United States Court of Federal
     Claims  against  the DOE,  claiming  that  the DOE  breached  the  Standard
     Contract for Disposal of Spent  Nuclear Fuel (SNF) by failing to accept SNF
     from various PEC facilities on or before  January 31, 1998.  Damages due to
     DOE's  breach  will  likely  exceed $100  million.  Approximately  60 cases
     involving the  Government's  actions in connection  with spent nuclear fuel
     are currently pending in the Court of Federal Claims.

     DOE and the PEC  parties  have agreed to a stay of the  lawsuit,  including
     discovery.  The parties agreed to, and the trial court  entered,  a stay of
     proceedings,  in  order  to  allow  for  possible  efficiencies  due to the
     resolution of legal and factual  issues in previously  filed cases in which
     similar  claims are being  pursued by other  plaintiffs.  These  issues may
     include,  among others,  so-called "rate issues," or the minimum  mandatory
     schedule for the  acceptance of SNF and high level waste (HLW) by which the
     Government  was  contractually  obligated to accept  contract  holders' SNF
     and/or HLW, and issues regarding recovery of damages under a partial breach
     of  contract  theory  that will be  alleged to occur in the  future.  These
     issues  have been or are  expected to be  presented  in the trials that are
     currently  scheduled to occur during  2005.  Resolution  of these issues in
     other cases could facilitate  agreements by the parties in the PEC lawsuit,
     or at a minimum,  inform the Court of decisions  reached by other courts if
     they remain contested and require  resolution in this case. The trial court
     has continued this stay until June 24, 2005.

     With certain  modifications and additional  approval by the NRC,  including
     the  installation  of  onsite  dry  storage   facilities  at  Robinson  and
     Brunswick,  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  operating  licenses  for  all  of  PEC's  nuclear
     generating units.

                                      177
<PAGE>

     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.  In January 2003, the State of Nevada,
     Clark County,  Nevada,  and the City of Las Vegas petitioned the U.S. Court
     of  Appeals  for  the  District  of  Columbia  Circuit  for  review  of the
     Congressional override resolution. These same parties also challenged EPA's
     radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected
     the challenge to the  constitutionality  of the resolution  approving Yucca
     Mountain,  but ruled that the EPA was wrong to set a 10,000-year compliance
     period in the radiation protection standard. EPA is currently reworking the
     standard but has not stated when the work will be complete.  DOE originally
     planned to submit a license  application  to the NRC to construct the Yucca
     Mountain  facility  by the end of 2004.  However,  in  November  2004,  DOE
     announced  it would not submit the license  application  until  mid-2005 or
     later.  Also in November  2004,  Congressional  negotiators  approved  $577
     million for fiscal year 2005 for the Yucca Mountain project,  approximately
     $300  million  less than  requested  by DOE but  approximately  the same as
     approved in 2004. The DOE continues to state it plans to begin operation of
     the repository at Yucca Mountain in 2010. PEC cannot predict the outcome of
     this matter.

     2. In 2001,  PEC  entered  into a contract  to  purchase  coal from  Dynegy
     Marketing and Trade (DMT).  After DMT experienced  financial  difficulties,
     including credit ratings  downgrades by certain credit reporting  agencies,
     PEC requested credit  enhancements in accordance with the terms of the coal
     purchase   agreement   in  July  2002.   When  DMT  did  not  offer  credit
     enhancements,  as required by a provision in the contract,  PEC  terminated
     the contract in July 2002.

     PEC initiated a lawsuit seeking a declaratory judgment that the termination
     was lawful.  DMT  counterclaimed,  stating the  termination was a breach of
     contract and an unfair and deceptive trade practice. On March 23, 2004, the
     United States  District  Court for the Eastern  District of North  Carolina
     ruled that PEC was liable for breach of contract,  but ruled against DMT on
     its unfair and deceptive trade practices claim. On April 6, 2004, the Court
     entered a judgment against PEC in the amount of approximately  $10 million.
     The Court did not rule on DMT's  request  under the  contract  for  pending
     legal costs.

     On May 4, 2004,  PEC  authorized  its  outside  counsel to file a notice of
     appeal of the April 6, 2004,  judgment  and on May 7,  2004,  the notice of
     appeal  was filed with the United  States  Court of Appeals  for the Fourth
     Circuit.  On June 8, 2004,  DMT filed a motion to dismiss the appeal on the
     ground that PEC's notice of appeal  should have been filed on or before May
     6,  2004.  On June 16,  2004,  PEC  filed a motion  with  the  trial  court
     requesting  an  extension  of the  deadline for the filing of the notice of
     appeal.  By order dated  September  10,  2004,  the trial court  denied the
     extension  request.  On September 15, 2004, PEC filed a notice of appeal of
     the September 10, 2004,  order and by order dated  September 29, 2004,  the
     appellate court consolidated the first and second appeals.  DMT's motion to
     dismiss the first appeal remains pending.

     The  consolidated  appeal has been fully briefed,  and the court of appeals
     has indicated  that it will hear  arguments,  which  tentatively  have been
     scheduled for the week of May 23, 2005.

     PEC recorded a liability for the judgment of approximately  $10 million and
     a regulatory  asset for the probable  recovery  through its fuel adjustment
     clause in the first quarter of 2004. PEC cannot predict the outcome of this
     matter.

     3.  On  February  1,  2002,   PEC  filed  a  complaint   with  the  Surface
     Transportation  Board  (STB)  challenging  the  rates  charged  by  Norfolk
     Southern  Railway Company  (Norfolk  Southern) for coal  transportation  to
     certain  generating  plants. In a decision dated December 23, 2003, the STB
     found that the rates were unreasonable,  awarded reparations and prescribed
     maximum rates. Both parties  petitioned the STB for  reconsideration of the
     December 23, 2003 decision.  On October 20, 2004, the STB  reconsidered its
     December 23, 2003 decision and concluded  that the rates charged by Norfolk
     Southern  were  not  unreasonable.  Because  PEC  paid  the  maximum  rates
     prescribed by the STB in its December 23, 2003 decision for several  months
     during  2004,  which  were  less  than  the  rates  ultimately  found to be
     reasonable,  the STB ordered PEC to pay to Norfolk  Southern the difference
     between the rate levels plus interest.

                                      178
<PAGE>

     PEC  subsequently  filed a petition  with the STB to phase in the new rates
     over a period of time,  and filed a notice of appeal with the U.S. Court of
     Appeals for the D.C.  Circuit.  Pursuant  to an order  issued by the STB on
     January 6, 2005,  the phasing  proceeding  will proceed on a schedule  that
     appears  likely to  produce  an STB  decision  before  the end of 2005.  On
     January 12,  2005,  the STB filed a Motion to Dismiss  PEC's  appeal on the
     grounds that its October 20, 2004, order is not "final" until PEC's phasing
     application has been decided.

     As of December  31, 2004,  PEC has accrued a liability  of $42 million,  of
     which $23  million  represents  reparations  previously  remitted to PEC by
     Norfolk  Southern  that are now  subject to refund.  Of the  remaining  $19
     million,  $17  million  has been  recorded  as  deferred  fuel  cost on the
     Consolidated  Balance Sheet while the remaining $2 million  attributable to
     wholesale customers has been charged to fuel used in electric generation on
     the Consolidated Statements of Income.

     PEC cannot predict the outcome of this matter.

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

19.  SUBSEQUENT EVENT

     Cost Management Initiative

     On February 28, 2005,  as part of a previously  announced  cost  management
     initiative,  the executive officers of Progress Energy approved a workforce
     restructuring.  The  restructuring is expected to be completed in September
     of 2005. In addition to the workforce  restructuring,  the cost  management
     initiative includes a voluntary enhanced retirement program.

     In connection  with the cost  management  initiative,  PEC expects to incur
     one-time pre-tax charges of approximately  $55 million.  Approximately  $10
     million of that amount relates to payments for severance benefits, and will
     be  recognized  in the  first  quarter  of 2005 and  paid  over  time.  The
     remaining  approximately  $45  million  will be  recognized  in the  second
     quarter of 2005 and relates primarily to postretirement  benefits that will
     be paid over time to those  eligible  employees who elect to participate in
     the  voluntary  enhanced  retirement  program.  The total  cost  management
     initiative  charges  could  change  significantly  depending  upon how many
     eligible  employees  elect early  retirement  under the voluntary  enhanced
     retirement program and the salary, service years and age of such employees.

20.  CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
----------------------------------------------------------------------------------------------------------------
(in millions)                                First Quarter    Second Quarter   Third Quarter     Fourth Quarter
----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues                               $  901          $  862          $ 1,014             $  852
Operating income                                    236             191              317                133
Income before cumulative effect of
   change in accounting principles                  115              96              175                 75
Net income                                          115              96              175                 75
----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues                               $  929          $  819          $ 1,012             $  840
Operating income                                    256             184              295                234
Income before cumulative effect of
   change in accounting principles                  135              89              158                123
Net income                                          135              89              158                100
----------------------------------------------------------------------------------------------------------------
</TABLE>

     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.
     Fourth  quarter  2004  includes  approximately  $99  million  ($59  million
     after-tax)  more NC Clean  Air  legislation  amortization  than  the  other
     quarters  presented.  Fourth  quarter  2004 also  includes a  reduction  in
     depreciation  expense of $63 million ($38 million after-tax) resulting from
     a revised depreciation study due to extended lives at each of PEC's nuclear
     units  (See Note 4A).  Fourth  quarter  2003  includes  impairment  charges
     related to certain  investments of $21 million ($13 million after-tax) (See
     Note 7). Fourth quarter 2003 includes the impact of a cumulative effect for
     DIG Issue C20 of $38 million ($23 million after-tax) (See Note 13).

                                      179
<PAGE>

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the consolidated  financial statements of Progress Energy, Inc.,
and its  subsidiaries  (the  Company) as of December 31, 2004 and 2003,  and for
each of the three years in the period  ended  December  31,  2004,  management's
assessment of the effectiveness of the Company's internal control over financial
reporting  as of December  31,  2004,  and the  effectiveness  of the  Company's
internal  control over  financial  reporting  as of December 31, 2004,  and have
issued  our  reports  thereon  dated  March 7, 2005  (which  reports  express an
unqualified opinion and include an explanatory paragraph concerning the adoption
of new accounting  principles in 2003);  such reports are included  elsewhere in
this Form 10-K. Our audits also included the  consolidated  financial  statement
schedule of the Company listed in Item 15. 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
consolidated  financial  statements taken as a whole,  presents  fairly,  in all
material respects, the information set forth therein.

/s/ Deloitte & Touche LLP


Raleigh, North Carolina
March 7, 2005


                                       180
<PAGE>


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

TO THE BOARD OF DIRECTORS  AND  SHAREHOLDER  OF CAROLINA  POWER & LIGHT  COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:

We have audited the consolidated  financial statements of Carolina Power & Light
Company d/b/a Progress Energy Carolinas,  Inc., and its subsidiaries (PEC) as of
December 31, 2004 and 2003,  and for each of the three years in the period ended
December 31, 2004, and have issued our report thereon dated March 7, 2005 (which
expresses  an  unqualified   opinion  and  includes  an  explanatory   paragraph
concerning  the adoption of new accounting  principles in 2003);  such report is
included  elsewhere in this Form 10-K. Our audits also included the consolidated
financial  statement schedule of PEC listed in Item 15. This 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 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
March 7, 2004

                                      181
<PAGE>

                              PROGRESS ENERGY, INC.
                 Schedule II - Valuation and Qualifying Accounts
                               For the Years Ended
                                  (in millions)

<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 (a)        Period
-----------------------------------------------------------------------------------------------------------------------

Valuation and qualifying
accounts deducted in the
balance sheet from the
related assets:


DECEMBER 31, 2004
    Uncollectible accounts         $  32              $  17               $ (4)             $ (16)              $  29
    Fossil dismantlement
        reserve                      143                  1                  -                  -                 144
    Nuclear refueling
        outage reserve                 2                 10                  -                  -                  12

DECEMBER 31, 2003
    Uncollectible accounts         $  39              $  24               $  4              $ (35)              $  32
    Fossil dismantlement
        reserve                      142                  1                  -                  -                 143
    Nuclear refueling outage
        reserve                       10                  8                  -                (16)  (b)             2

DECEMBER 31, 2002
    Uncollectible accounts         $  39              $  22               $  -              $ (22)              $  39
    Fossil dismantlement
        reserve                      141                  1                  -                  -                 142
    Nuclear refueling outage
        reserve                        -                 10                  -                  -                  10
-----------------------------------------------------------------------------------------------------------------------

(a)  Deductions  from  provisions  represent  losses or  expenses  for which the
     respective  provisions  were  created.  In the  case of the  provision  for
     uncollectible  accounts,  such  deductions  are  reduced by  recoveries  of
     amounts previously written off.
(b)  Represents payments of actual expenditures related to the outages.

-----------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      182
<PAGE>

                         CAROLINA POWER & LIGHT COMPANY
                         d/b/a PROGRESS ENERGY CAROLINAS
                 Schedule II - Valuation and Qualifying Accounts
                               For the Years Ended
                                  (in millions)

<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 (a)      Period
-----------------------------------------------------------------------------------------------------------------------

Valuation and qualifying accounts
deducted in the balance sheet from
the related assets:


December 31, 2004
      Uncollectible accounts                 $ 17              $  7         $ (4)         $ (10)             $ 10



December 31, 2003
      Uncollectible accounts                 $ 12              $ 12         $  4          $ (11)             $ 17



December 31, 2002
      Uncollectible accounts                 $ 14              $  8         $  -          $ (10)             $ 12
-----------------------------------------------------------------------------------------------------------------------

(a)  Deductions  from  provisions  represent  losses or  expenses  for which the
     respective  provisions  were  created.  In the  case of the  provision  for
     uncollectible  accounts,  such  deductions  are  reduced by  recoveries  of
     amounts previously written off.

-----------------------------------------------------------------------------------------------------------------------
</TABLE>

                                      183
<PAGE>

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

None

ITEM 9A. CONTROLS AND PROCEDURES

Progress Energy, Inc.

DISCLOSURE CONTROLS AND PROCEDURES

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 to
ensure that  information  required  to be  disclosed  by Progress  Energy in the
reports that it files or submits under the Exchange Act, is recorded, processed,
summarized  and reported,  within the time periods  specified in the SEC's rules
and forms, and that such information is accumulated and communicated to Progress
Energy's  management,  including the Chief Executive Officer and Chief Financial
Officer,   as  appropriate,   to  allow  timely  decisions   regarding  required
disclosure.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the  responsibility  of Progress  Energy's  management  to  establish  and
maintain  adequate  internal control over financial  reporting,  as such term is
defined in Rules  13a-15(f) and  15(d)-15(f) of the  Securities  Exchange Act of
1934, as amended. Progress Energy's internal control over financial reporting is
a process designed to provide reasonable  assurance regarding the reliability of
financial  reporting and the  preparation  of financial  statements for external
purposes in accordance  with  generally  accepted  accounting  principles in the
United States of America.  Internal  control over financial  reporting  includes
policies and procedures  that (1) pertain to the maintenance of records that, in
reasonable   detail,   accurately  and  fairly  reflect  the   transactions  and
dispositions of the assets of Progress Energy; (2) provide reasonable  assurance
that  transactions are recorded as necessary to permit  preparation of financial
statements in accordance with generally  accepted  accounting  principles in the
United States of America;  (3) provide  reasonable  assurance  that receipts and
expenditures  of  Progress  Energy  are  being  made  only  in  accordance  with
authorizations  of management and directors of Progress Energy;  and (4) provide
reasonable  assurance  regarding  prevention or timely detection of unauthorized
acquisition,  use or disposition of Progress  Energy's  assets that could have a
material effect on the financial statements.

Because of its inherent  limitations,  internal control over financial reporting
may not prevent or detect misstatements.  Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate  because of changes in  conditions,  or that the degree of compliance
with the policies or procedures may deteriorate.

Management assessed the effectiveness of Progress Energy's internal control over
financial reporting as of December 31, 2004. Management based this assessment on
criteria for effective  internal control over financial  reporting  described in
"Internal Control - Integrated  Framework" issued by the Committee of Sponsoring
Organizations  of  the  Treadway  Commission  (COSO).   Management's  assessment
included an evaluation of the design of Progress  Energy's internal control over
financial reporting and testing of the operational effectiveness of its internal
control  over  financial  reporting.  Management  reviewed  the  results  of its
assessment with the Audit Committee of the Board of Directors.

Based on our assessment,  management  determined  that, as of December 31, 2004,
Progress Energy maintained effective internal control over financial reporting.

Management's  assessment  of the  effectiveness  of Progress  Energy's  internal
control over  financial  reporting as of December 31, 2004,  has been audited by
Deloitte & Touche LLP, an  independent  registered  public  accounting  firm, as
stated  in their  report  which  is  included  herein  in Item 9A  Controls  and
procedures of this Annual Report on Form 10-K.

                                      184
<PAGE>

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.

There has been no change in Progress  Energy's  internal  control over financial
reporting  during the quarter  ended  December  31,  2004,  that has  materially
affected, or is reasonably likely to materially affect its internal control over
financial reporting.

The Company  notes,  however,  that as part of the Company's  review of internal
controls for compliance with Section 404 of the Sarbanes-Oxley  Act, the Company
will be implementing changes related to capitalization  practices for its Energy
Delivery  business  units in PEC and PEF effective  January 1, 2005. A review of
these  practices  indicated that in the areas of outage and emergency  work, not
associated with major storm and allocation of indirect  costs,  both PEC and PEF
should revise the way that they estimate the amount of capital costs  associated
with such work.  The changes for 2005 in this area include use of more  detailed
accounts to  segregate  capital  and  expense  items,  more  regular  testing of
accounting  estimates and  realignment  of certain  accounting  functions.  This
matter is also  discussed  at Footnote 8F to the  Progress  Energy  Consolidated
Financial Statements.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We  have  audited   management's   assessment,   included  in  the  accompanying
Management's Report on Internal Control Over Financial Reporting,  that Progress
Energy, Inc., and its subsidiaries (the "Company") maintained effective internal
control over financial  reporting as of December 31, 2004, based on the criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The Company's management is
responsible for maintaining  effective internal control over financial reporting
and for its assessment of the  effectiveness  of internal control over financial
reporting.   Our  responsibility  is  to  express  an  opinion  on  management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.

We conducted  our audit in accordance  with the standards of the Public  Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain  reasonable  assurance  about whether  effective
internal  control  over  financial  reporting  was  maintained  in all  material
respects. Our audit included obtaining an understanding of internal control over
financial reporting,  evaluating management's assessment, testing and evaluating
the design and operating  effectiveness of internal control, and performing such
other  procedures as we considered  necessary in the  circumstances.  We believe
that our audit provides a reasonable basis for our opinions.

A company's internal control over financial  reporting is a process designed by,
or under the  supervision  of, the Company's  principal  executive and principal
financial officers, or persons performing similar functions, and effected by the
Company's  board of  directors,  management,  and  other  personnel  to  provide
reasonable  assurance  regarding the reliability of financial  reporting and the
preparation  of financial  statements for external  purposes in accordance  with
generally  accepted  accounting  principles.  A company's  internal control over
financial  reporting  includes those policies and procedures that (1) pertain to
the  maintenance  of records that, in reasonable  detail,  accurately and fairly
reflect the  transactions  and  dispositions  of the assets of the Company;  (2)
provide  reasonable  assurance  that  transactions  are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting  principles,  and that receipts and  expenditures  of the Company are
being made only in accordance with authorizations of management and directors of
the Company; and (3) provide reasonable assurance regarding prevention or timely
detection of  unauthorized  acquisition,  use or  disposition  of the  Company's
assets that could have a material effect on the financial statements.

Because  of  the  inherent   limitations  of  internal  control  over  financial
reporting,  including  the  possibility  of  collusion  or  improper  management
override of controls,  material  misstatements  due to error or fraud may not be
prevented or detected on a timely basis. Also,  projections of any evaluation of
the  effectiveness  of the internal  control over financial  reporting to future
periods are subject to the risk that the controls may become inadequate  because
of changes in conditions,  or that the degree of compliance with the policies or
procedures may deteriorate.

                                      185
<PAGE>

In our opinion,  management's  assessment that the Company maintained  effective
internal  control over  financial  reporting as of December 31, 2004,  is fairly
stated, in all material respects,  based on the criteria established in Internal
Control--Integrated   Framework   issued   by  the   Committee   of   Sponsoring
Organizations  of the  Treadway  Commission.  Also in our  opinion,  the Company
maintained, in all material respects,  effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control--Integrated   Framework   issued   by  the   Committee   of   Sponsoring
Organizations of the Treadway Commission.

We have also  audited,  in accordance  with the standards of the Public  Company
Accounting   Oversight  Board  (United  States),   the  consolidated   financial
statements  as of and for the year ended  December 31, 2004,  of the Company and
our  report  dated  March 7, 2005,  expressed  an  unqualified  opinion on those
consolidated financial statements.

/s/ Deloitte & Touche LLP

Raleigh, North Carolina
March 7, 2005

Progress Energy Carolinas, Inc.

Pursuant to 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 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  to ensure  that
information  required to be  disclosed  by PEC in the  reports  that it files or
submits under the Exchange Act, is recorded, processed, summarized and reported,
within the time periods  specified  in the SEC's rules and forms,  and that such
information is accumulated and communicated to PEC's  management,  including the
Chief Executive Officer and Chief Financial  Officer,  as appropriate,  to allow
timely decisions regarding required disclosure.

There has been no change in PEC's  internal  control  over  financial  reporting
during the quarter ended December 31, 2004, that has materially affected,  or is
reasonably  likely to materially  affect,  its internal  control over  financial
reporting.

As noted  above,  PEC will be  implementing  changes  related to  capitalization
practices for its Energy  Delivery  business unit  effective  January 1, 2005. A
review of these  practices  indicated  that in the areas of outage and emergency
work, not  associated  with major storm and  allocation of indirect  costs,  PEC
should revise the way that it estimates  the amount of capital costs  associated
with such work.  The changes for 2005 in this area include use of more  detailed
accounts to  segregate  capital  and  expense  items,  more  regular  testing of
accounting  estimates and  realignment  of certain  accounting  functions.  This
matter  is  also  discussed  in  Note  6E  to  the  PEC  Consolidated  Financial
Statements.

ITEM 9B. OTHER INFORMATION

In March 2005,  Progress  Energy,  Inc.'s 5-year credit  facility was amended to
increase  the  maximum  total  debt to total  capital  ratio  from 65% to 68% in
anticipation of the potential impacts of proposed accounting rules for uncertain
tax positions.

                                      186
<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 2004  definitive  proxy statement dated March 31, 2005, and
     incorporated  by reference  herein.  Information on PEC's  directors is set
     forth in the PEC 2004 definitive  proxy statement dated March 31, 2005, 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 Web site 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 Web site, 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 Web site and in print at no
     cost:

     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 2004  definitive  proxy  statement  dated March 31,  2005,  and
incorporated by reference herein. Information on PEC's executive compensation is
set forth in the PEC 2004  definitive  proxy statement dated March 31, 2005, 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 2004 definitive proxy statement,  dated March 31, 2005,
     and incorporated herein by reference.

     Information  regarding any person PEC knows to be the  beneficial  owner of
     more than 5% of any class of its voting securities is set forth in its 2004
     definitive proxy statement,  dated March 31, 2005, and incorporated  herein
     by reference.

                                      187
<PAGE>

b)   Information  on  security  ownership  of the  Progress  Energy's  and PEC's
     management  is set forth in the  Progress  Energy  and PEC 2004  definitive
     proxy  statements  dated March 31,  2005,  and  incorporated  by  reference
     herein.

c)   Information  on the equity  compensation  plans of  Progress  Energy is set
     forth under the  heading  "Equity  Compensation  Plan  Information"  in the
     Progress Energy 2004  definitive  proxy statement dated March 31, 2005, 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 2004  definitive  proxy  statements  dated March 31,
2005, 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 2004 definitive  proxy  statements dated March 31, 2005,
and incorporated by reference herein.


                                      188
<PAGE>


                                     PART IV


ITEM 15.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

                                      189
<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.  Most  of the  business  information  as  well  as the  financial  and
operational  data contained in our risk factors are updated  periodically in the
reports we file with the SEC.  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, financial condition and 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 subject
to regulatory  oversight with respect to, among other things,  rates and service
for electric  energy sold at retail,  retail service  territory and issuances of
securities.  In addition our operating  utilities are subject to regulation with
respect to  transmission  and sales of wholesale  power,  accounting and certain
other  matters.  We are also  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 2004 working on a  comprehensive  energy bill.
While  that  legislation  passed  the  House,  the  Senate  failed  to pass  the
legislation  in  2004.  There  will  probably  be an  effort  to  resurrect  the
legislation in 2005. 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 the Public Utility Holding  Company Act of 1935 ("PUHCA").  The Company
cannot predict the outcome or impact of the proposed or any future energy bill.

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 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, financial condition and results of operations.

                                      190
<PAGE>

We are subject to  numerous  environmental  laws and  regulations  that  require
significant capital expenditures, increase our cost of operations, and which may
impact or limit our business plans, or expose us to environmental liabilities.

We are subject to numerous  environmental  regulations affecting many aspects of
our present and future  operations,  including  air  emissions,  water  quality,
wastewater  discharges,   solid  waste  and  hazardous  waste.  These  laws  and
regulations  can  result in  increased  capital,  operating,  and  other  costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations.  These  laws and  regulations  generally  require  us to obtain and
comply with a wide variety of environmental licenses,  permits,  inspections and
other  approvals.  Both public  officials  and private  individuals  may seek to
enforce  applicable  environmental  laws and regulations.  We cannot predict the
outcome (financial or operational) of any related litigation that may arise.

In addition,  we may be a responsible party for environmental  clean up at sites
identified by a regulatory  body. We cannot predict with certainty the amount or
timing of all future  expenditures  related to environmental  matters because of
the  difficulty  of  estimating  clean up costs.  There is also  uncertainty  in
quantifying  liabilities under  environmental laws that impose joint and several
liability on all PRPs.

Our compliance  with  environmental  regulations  requires  significant  capital
expenditures  that impact our financial  condition.  For example,  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.  We expect the capital costs required to
meet these emission targets will total  approximately $895 million by 2013. Over
the next three  years,  we expect to incur  approximately  $510 million of total
capital costs associated with this legislation.

Congress currently considering further legislation that would require reductions
in air  emissions  of 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 our  consolidated
financial position or results of operations. However, the Company cannot predict
the outcome,  costs or impact of this matter. In December 2003, the EPA released
its proposed Interstate Air Quality Rule, currently referred to as the Clean Air
Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions,  including
North  Carolina,  South  Carolina,  Georgia and  Florida,  to reduce NOx and SO2
emissions in order to attain preset state NOx and SO2 emissions levels. The rule
is  expected  to become  final in March  2005.  While the air  quality  controls
already  installed and currently  planned for installation to comply with the NC
Clean  Air  legislation  will  reduce  the  costs  required  to  meet  the  CAIR
requirements for the our North Carolina units,  additional compliance costs will
be determined  once the rule is  finalized.  In March 2004,  the North  Carolina
Attorney  General  filed a petition  with the EPA under Section 126 of the Clean
Air Act,  asking the federal  government  to force  coal-fired  power  plants in
thirteen  other  states,  including  South  Carolina to reduce their NOx and SO2
emissions.  The state of North Carolina  contends these  out-of-state  emissions
interfere with North Carolina's  ability to meet national air quality  standards
for ozone and particulate  matter. The EPA has agreed to make a determination on
the petition by August 1, 2005.  The Company cannot predict the outcome or costs
associated with the matter.

See  additional  discussion  of these  environmental  matters  in Note 22 to the
Progress Energy Consolidated Financial Statements.

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.

                                      191
<PAGE>

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 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).  In its current form,  SMD NOPR
could materially alter the manner in which transmission and generation  services
are provided and paid for, and includes  provisions  for mandatory  RTOs and the
FERC's  assertion of jurisdiction  over certain  aspects of retail service.  The
Company  cannot  predict  the outcome or timing of any final rules or the effect
that  they may  have on the  GridSouth  and  GridFlorida  proceedings  currently
ongoing before the FERC.

At the state level,  significant uncertainty exists with respect to what action,
if any, the NCUC or FPSC will  ultimately  take. The Company has $33 million and
$4 million  invested in  GridSouth  and  GridFlorida,  respectively,  related to
startup  costs at December 31, 2004.  These amounts are included as a regulatory
asset at December 31, 2004.  The Company  expects to recover these startup costs
in  conjunction  with the GridSouth and  GridFlorida  original  structures or in
conjunction  with any alternate  combined  transmission  structures  that may be
required.  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.

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  they will be  created,  or whether  they 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.

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 and market prices peak during the hot summer  months.
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,  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.  For example,
during the third quarter of 2004, four  hurricanes hit our service  territories,
resulting in storm costs of approximately $398 million. In addition, these storm
costs reduced our  projected  2004 regular  federal  income tax  liability,  and
consequently,  our ability to benefit  from the tax credits  generated  from our
synthetic fuel operations.

                                      192
<PAGE>

Our ability to recover significant costs resulting from severe weather events is
subject to  regulatory  oversight and the timing and amount of any such recovery
is uncertain and may impact our financial conditions.

During the third quarter of 2004, four hurricanes struck significant portions of
our service territories, most significantly impacting PEF's territory. The total
estimated  restoration  cost of  these  storms  is $398  million.  PEC  incurred
restoration costs of $13 million,  of which $12 million was charged to operation
and maintenance expense and $1 million was charged to capital expenditures.  PEF
had estimated  total costs of $385 million,  of which $47 million was charged to
capital  expenditures,  and $338 million was charged to the storm damage reserve
pursuant to a regulatory order.

Under a regulatory order, PEF maintains a storm damage reserve account for major
storms.  With  respect  to storm  costs in excess of the  storm  damage  reserve
account,  PEF may seek recover from retail ratepayers.  On November 2, 2004, PEF
filed a petition  with the FPSC to  recover  $252  million  of storm  costs plus
interest  from  retail  ratepayers  over a two-year  period.  Given that not all
invoices have been  received as of December 31, 2004, it is PEF's  position that
its petition  presents a fair  projection  of total cost and does not need to be
updated at this time.  PEF will update its request upon receipt and audit of all
actual charges incurred.  Storm reserve costs of $13 million are attributable to
wholesale customers and such costs may be amortized  consistent with recovery of
such amounts in wholesale  rates.  The timing of any FPSC  decision and ultimate
amount recovered is uncertain at this time.

PEC is not required to maintain a storm damage reserve account and does not have
an  on-going  regulatory  mechanism  to  recover  storm  costs  and;  therefore,
hurricane  restoration  costs recorded in the third quarter of 2004 were charged
to operations  and  maintenance  expenses or capital  expenditures  based on the
nature  of the  work  performed.  In  connection  with  other  storms,  PEC  has
previously  sought and received  permission from the NCUC and the SCPSC to defer
storm  expenses  and  amortize  them over a five-year  period.  PEC did not seek
recovery of 2004 storm costs from the NCUC.

While we believe  that we are legally  entitled to recover  these  costs,  if we
cannot recover these costs, or costs associated with future significant  weather
events,  in a timely  manner,  or in an amount  sufficient  to cover our  actual
costs,  our financial  conditions and results of operations  could be materially
and adversely impacted.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding  impact on our commercial and industrial customers
as well as the demand and competitive state of the wholesale market.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2004, commercial and industrial customers represented approximately
37% of our total 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 recent  years,  in North and South  Carolina,  sales to industrial
customers   have  been  affected  by  downturns  in  the  textile  and  chemical
industries.

For the year ended December 31, 2004,  12% of our total  electric  revenues were
from wholesale sales.  Wholesale revenues  fluctuate with regional demand,  fuel
prices, and contracted capacity.  Our wholesale  profitability is dependent upon
our ability to renew or replace expiring wholesale contracts on favorable terms.
During  2004,   wholesale  revenues  decreased  from  expiring  contracts  being
renegotiated  by PEC at less favorable terms due to slightly  depressed  markets
and from increased  competition in the wholesale  markets served by PEC. If this
trend market  environment  persists,  we may experience  further declines in our
wholesale revenues.

In April 2004, the FERC issued two orders concerning  utilities' ability to sell
wholesale  electricity  at  market-based  rates.  In the first  order,  the FERC
adopted two new interim screens for assessing potential  generation market power
of  applicants  for  wholesale  market-based  rates,  and  described  additional
analyses and  mitigation  measures that could be presented if an applicant  does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider  whether the FERC's current  methodology
for  determining  whether a public  utility  should be allowed to sell wholesale
electricity  at  market-based  rates should be modified in any way. PEF does not
have  market-based  rate  authority for wholesale  sales in peninsular  Florida.
Given the  difficulty  PEC  believes it would  experience  in passing one of the
interim screens,  on August 12, 2004, PEC notified the FERC that it would revise
its Market-based  Rate tariff to restrict it to sales outside PEC's control area
and file a new  cost-based  tariff  for sales  within  PEC's  control  area that
incorporates the FERC's default  cost-based rate  methodologies for sales of one
year or less.  We  anticipate  making this filing the first  quarter of 2005. We
cannot  predict what impact PEC's  requirement to implement  cost-based  tariffs
will have on our  future  financial  condition,  results of  operations  or cash
flows.

                                      193
<PAGE>

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.

Increased commodity prices may adversely affect the financial condition, results
of operations or cash flows of us and our utilities' businesses.

The  Company is exposed to the  effects of market  fluctuations  in the price of
natural gas,  coal,  fuel oil,  electricity  and other  energy-related  products
marketed and  purchased as a result of its ownership of  energy-related  assets.
While each state  commission  allows  electric  utilities to recover  certain of
these costs through various cost recovery  clauses,  there is the potential that
all or a  portion  of these  future  costs  could  be  deemed  imprudent  by the
respective  commissions.  There is also a delay between the timing of when these
costs are incurred by the utilities and when these costs are recovered  from the
ratepayers,  which can  adversely  impact the cash flow of the  Company  and its
subsidiaries.

Prices for SO2  emission  allowance  credits  under the EPA's  emission  trading
program increased  significantly  during 2004. While SO2 allowances are eligible
for  annual  recovery  in the  Company's  jurisdictions  in  Florida  and  South
Carolina, no such annual recovery exists in North Carolina.  Future increases in
the price of SO2 allowances could have a significant adverse financial impact on
us and PEC and consequently on our results of operations and cash flows.

Risks Related to Us and Our Business

As a  holding  company,  we are  dependent  on  upstream  cash  flows  from  our
subsidiaries,  primarily our regulated  utilities.  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  associated  with  interest  charges on $4.3
billion of holding  company debt 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,  primarily our regulated utilities,  and the ability of
our  subsidiaries  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.  For the year ending  December  31, 2004,  approximately  100% of the
Company's cash from operations was provided by its utility  subsidiaries.  Other
sources of cash include the issuance of equity, short-term debt and intercompany
charges for capital costs.

The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators.  Accordingly, our profit
margins  could be adversely  affected if we or our utility  subsidiaries  do not
control operating costs.

The NCUC, the SCPSC and the FPSC each exercises  regulatory authority for review
and approval of the retail  electric  power rates charged  within its respective
state.  State  regulators  may not allow our  utility  subsidiaries  to increase
retail  rates in the manner or to the extent  requested  by those  subsidiaries.
State  regulators  may also seek to reduce retail rates.  For example,  in March
2002, PEF entered into a Stipulation and Settlement  Agreement (the "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.  As  discussed  below,  in  January  2005,  PEF
petitioned the FPSC for an increase in its retail base rates.

                                      194
<PAGE>

Additionally,  under the NC Clean Air legislation in North  Carolina,  passed in
2002,  PEC's base  retail  rates were  frozen  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,
and PEC has agreed not to seek a base  retail  electric  rate  increase in South
Carolina through 2005. 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.

If the FPSC does not approve our request for  increased  base rates,  we will be
faced with a significantly  increased cost structure that will not be adequately
covered by our base rates and, as a result, our results of operations, financial
condition  and  ability  to pay  dividends  could be  materially  and  adversely
impacted.

In January 2005, in anticipation of the expiration of the Agreement  approved by
the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC
that it intends to request an increase in its base rates,  effective  January 1,
2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the
projected test period for setting new base rates. We have faced significant cost
increases over the past decade and expect our  operational  costs to continue to
increase.  These costs include the costs  associated  with (i) completion of our
Hines  3  generation  facility,   (ii)  extraordinary  hurricane  damage  costs,
including  approximately  $50 million in capital costs which are not expected to
be directly recoverable,  (iii) our need to replenish our depleted storm reserve
or adjust the annual accrual by  approximately  $50 million annually in light of
recent history on a going-forward  basis,  and (iv) the expected  infrastructure
investment  necessary  to meet  high  customer  expectations,  coupled  with the
demands  placed  on  our  strong  customer  growth.  In  addition,   significant
additional  costs  include  increased   depreciation  and  fossil  dismantlement
expenses  in  excess  of $70  million  when  the  provisions  of  the  Agreement
addressing  these  expenses  expire  at the end of this  year.  We also face the
prospect of significant  compliance costs from  participation in the GridFlorida
regional transmission  organization pursuant to FERC's transmission independence
initiative and the FPSC's related directive.  Finally,  as is the case with most
companies in our industry,  we will continue to experience the pervasive  upward
pressure of inflation  on costs in general,  especially  the rapidly  increasing
costs of employee healthcare and other benefit programs.

Under the  Agreement,  our base  rates are at a level that  existed in 1983;  by
contrast,  the Consumer  Price Index has increased  just over 90% since then. If
the FPSC does not approve our request for increased base rates, we will be faced
with a  significantly  increased  cost structure that will not be covered by our
base rates.  Additionally,  as discussed below, the credit ratings of PEF may be
negatively impacted by the outcome of the rate case. As a result, our results of
operations, financial condition and ability to pay dividends could be materially
and adversely impacted.

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  4,286 MW,  or 18%,  of our
generation capacity for the year ended December 31, 2004. 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.

                                      195
<PAGE>

From time to time,  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 as required. 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   hurricanes,   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.

We rely on access to both short-term and long-term capital markets, and lines of
credit with  commercial  banks 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 these sources of liquidity, 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 to below investment grade
would  increase our cost of borrowing  and may  adversely  affect our ability to
access  one or more  financial  markets.  Market  disruptions  create  a  unique
uncertainty  as they  typically  result from factors  beyond are  control.  Such
market disruptions could include:

     o    an economic downturn;
     o    the bankruptcy of an unrelated energy company;
     o    capital market conditions generally;
     o    allegations of corporate scandal at unrelated companies;
     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.

In  addition,  we  believe  that  these  market  disruptions,  unrelated  to our
business, could result in a ratings downgrade and, correspondingly, increase our
cost of capital.  Additional  risks regarding the impact of a ratings  downgrade
are discussed below. 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, 2004,  commercial paper and
bank  borrowings  and  long-term  debt  balances  for  Progress  Energy  and its
subsidiaries were as follows (in millions):

                                      196
<PAGE>

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
  -----------------------------------------------------------------------------------------
                                               Outstanding
                                             Commercial Paper            Total Long-Term
   Company                                  and Bank Borrowings             Debt, Net
  -----------------------------------------------------------------------------------------
   Progress Energy, unconsolidated (a)            $  170                     $ 4,449
   PEC                                               221                       2,750
   PEF                                               293                       1,912
   Other Subsidiaries                                  -                         410 (b)
  -----------------------------------------------------------------------------------------
   Progress Energy, consolidated                  $  684                     $ 9,521 (c)
  -----------------------------------------------------------------------------------------
</TABLE>

(a)  Represents solely the outstanding indebtedness of the holding company.
(b)  Includes the following  subsidiaries:  Florida Progress Funding Corporation
     ($270 million) and Progress Capital Holdings, Inc. ($140 million).
(c)  Net of current  portion,  which at December 31, 2004, was $349 million on a
     consolidated basis.

At December 31, 2004,  Progress Energy and its subsidiaries have an aggregate of
five committed credit lines that support our commercial paper programs  totaling
$1.98 billion.  While our financial policy precludes us from issuing  commercial
paper in excess of our credit lines, at December 31, 2004, we had an outstanding
commercial  paper  balance  and  letters of credit of $574  million,  leaving an
additional $931 million available for future borrowing under our credit lines.

On January  31, 2005  Progress  Energy,  Inc.  entered  into a new $600  million
revolving credit  agreement,  which expires December 30, 2005. This facility was
added  to  provide  additional  liquidity  during  2005  due in  part  to  storm
restoration costs incurred in Florida during 2004. The Credit Agreement includes
a  defined  maximum  total  debt to total  capital  ratio  of 65% and a  minimum
interest  coverage ratio of 2.5 to 1. The Credit Agreement also contains various
cross-default  and other  acceleration  provisions.  On February  4, 2005,  $300
million was drawn under the new  facility  to reduce  commercial  paper and bank
loans outstanding.

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,  2004,  the required and actual
ratios were as follows:

-----------------------------------------------------------------------------
                         Leverage Ratios                Coverage Ratios
-----------------------------------------------------------------------------
                                       Actual                          Actual
Company            Maximum Ratio       Ratio       Minimum Ratio       Ratio
-----------------------------------------------------------------------------
Progress Energy           65%          60.7%           2.5:1           4.00:1
PEC                       65%          52.3%            n/a             n/a
PEF                       65%          50.8%           3.0:1           7.93:1
-----------------------------------------------------------------------------

In March 2005,  Progress  Energy,  Inc.'s 5-year credit  facility was amended to
increase  the  maximum  total  debt to total  capital  ratio  from 65% to 68% in
connection with the potential accounting rules for uncertain tax positions.  See
Notes 2 and 23E to the Progress Energy Consolidated Financial Statements.

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 PEC and PEF 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.  For Progress Energy's credit lines, loan draws
for the payment of maturing commercial paper are excluded from this provision. 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 and PEF'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 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.

                                      197
<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  either of these  cross-default  provisions  is
triggered,  the debt holders  could  accelerate  payment of  approximately  $4.3
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  which  would  cause us to be rated below
investment grade would likely 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.

On February 11, 2005,  Moody's  Investors Service (Moody's) credit rating agency
announced  that it lowered  the  ratings of Progress  Energy  Florida,  Progress
Capital  Holdings and FPC Capital Trust I and changed  their rating  outlooks to
stable from negative.  Moody's  affirmed the ratings of Progress Energy and PEC.
The  rating  outlooks  continue  to be stable at PEC and  negative  at  Progress
Energy.  Moody's  stated that it took this  action  primarily  due to  declining
credit metrics, higher O&M costs,  uncertainty regarding the timing of hurricane
cost  recovery,  regulatory  risks  associated  with the  upcoming  rate case in
Florida and ongoing capital requirements to meet Florida's growing demand.

In October 2004,  Moody's changed its outlook for Progress Energy from stable to
negative  and placed the  ratings of PEF under  review for  possible  downgrade.
PEC's ratings were affirmed.  Accordingly,  Progress  Energy's senior  unsecured
debt is  rated  "Baa2,"  (negative  outlook)  by  Moody's.  Moody's  cited  weak
financial ratios relative to its current ratings category,  rising O&M, pension,
benefit and insurance costs,  and delays in executing its  deleveraging  plan as
the  primary  reasons for the change in outlook.  With  respect to PEF,  Moody's
cited  declining  cash flows and rising  leverage  over the last several  years,
expected funding needs for large capital expenditure  programs,  risks regarding
its  upcoming  2005 rate case and the timing of hurricane  cost  recovery as the
primary reason for placing the PEF's credit ratings under review.

In October  2004,  S&P also  changed  Progress  Energy's  outlook from stable to
negative. S&P cited uncertainties  regarding the timing of recovery of hurricane
costs,  the Company's  debt  reduction  plans,  and the IRS audit of our Earthco
synthetic fuel facilities as the primary  reasons for the change in outlook.  In
addition,  for  similar  reasons,  S&P  reduced  the  short-term  debt rating of
Progress  Energy,  PEC and PEF to "A-3" from  "A-2".  Progress  Energy's  senior
unsecured  debt is rated  "BBB-" by S&P.  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-3" (stable outlook).

The  forgoing  ratings  actions by S&P and  Moody's do not  trigger  any debt or
collateral  guarantee  requirement,  however our short-term  cost of capital has
increased by between 25 to 87.5 basis  points.  However,  the ratings  currently
assigned to Progress Energy's,  senior unsecured debt is S&P's lowest investment
grade  ratings  category and has a negative  outlook.  Accordingly,  any further
downgrade by S&P of Progress  Energy's senior  unsecured rating will result in a
noninvestment  grade  rating  and will  trigger  debt and  collateral  guarantee
requirements (as described below), and may have a material adverse impact on our
cost of capital, results of operations and liquidity.

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While the Company's  long-term  target credit  ratings for each entity are above
the minimum investment grade ranking,  we cannot 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 may 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-3 or P-2,  the  current  ratings
assigned by S&P and Moody's,  respectively,  our access to the commercial  paper
market  would be  significantly  limited.  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, 2004,
Progress Energy has issued  guarantees  with a notional amount of  approximately
$809 million to support CCO's energy marketing businesses. Based upon the amount
of trading  positions  outstanding  at December 31, 2004,  if Progress  Energy's
ratings were to decline below  investment  grade by either S&P or Moody's (i.e.,
below "BBB-" at S&P or below  "Baa3" at Moody's),  we would have to deposit cash
or provide  letters of credit or other cash  collateral for  approximately  $450
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, 2004,  the coverage  amount is $275  million.
These collateral requirements could adversely affect our profitability on energy
trading and marketing transactions and limit our overall liquidity. In addition,
if we are unable to fund or otherwise  satisfy these  guarantee  obligations our
financial  condition  and  liquidity  would be  further  impacted  in a material
adverse manner.

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.

Synthetic Fuel Risks Associated With the IRS Audit

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,  although  these  PLR's do not  make  any  "placed-in-service"
determinations. These tax credits are subject to review by the IRS.

In July 2004, we were notified that the IRS field auditors anticipated taking an
adverse  position  regarding the  placed-in-service  date of the Company's  four
Earthco  synthetic  fuel  facilities.  Due to the  auditors'  position,  the IRS
decided to  exercise  its right to  withdraw  from the PFA  program  with us. In
October 2004, we received the IRS field  auditors'  report  concluding  that the
Earthco  facilities had not been placed in service before July 1, 1998, and that
the tax credits generated by those facilities should be disallowed. We intend to
contest the field auditors' findings and their proposed  disallowance of the tax
credits. We believe that the appeals process,  including  proceedings before the
IRS's National Office, could take up to two years to complete. We cannot control
the actual timing of resolution and cannot predict the outcome of this matter.

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Through  December 31, 2004, on a consolidated  basis, we have or carried forward
approximately  $1.0 billion of tax credits generated by the Earthco  facilities.
If these credits were  disallowed,  our one-time  exposure for cash tax payments
would be $294  million  (excluding  interest),  and earnings and equity would be
reduced by approximately $1.0 billion,  excluding interest.  If we were required
to reverse  approximately  $1.0  billion of tax credits and pay $294 million for
taxes our  financial  condition,  results of operations  and liquidity  would be
materially and adversely impacted.

Progress  Energy's  amended $1.13 billion  credit  facility  includes a covenant
which limits the maximum debt-to-total capital ratio to 68%. This ratio includes
other  forms of  indebtedness  such as  guarantees  issued by  Progress  Energy,
letters of credit and capital leases. As of December 31, 2004, Progress Energy's
debt-to-total  capital ratio was 60.7% based on the credit agreement  definition
for this ratio. The impact on this ratio of reversing approximately $1.0 billion
of tax credits and paying $294  million for taxes would be to increase the ratio
to 65.7%.

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.

Synthetic Fuel Risks Associated with Pending  Accounting Rules for Uncertain Tax
Positions

In July 2004, the Financial  Accounting  Standards Board ("FASB") stated that it
plans to issue an exposure draft of a proposed  interpretation  of SFAS No. 109,
"Accounting  for Income  Taxes," that would address the accounting for uncertain
tax positions. The FASB has indicated that the interpretation would require that
uncertain  tax  benefits be probable of being  sustained in order to record such
benefits  in the  financial  statements.  The  exposure  draft is expected to be
issued in the first quarter of 2005.  Under the  prevailing  sentiment,  the IRS
field auditors'  recommendation that the Earthco tax credits be disallowed would
make it difficult to conclude that the tax benefits from the Earthco  facilities
are probable of being sustained.  Accordingly, it is likely we would not be able
to record the benefit of the Earthco  tax credits on our  financial  statements.
This could require us to create a reserve up to $1.0 billion until the IRS issue
is resolved, which would immediately increase our debt to capitalization ratios.
The  Company  cannot  predict  what  actions  the FASB will take or how any such
actions might ultimately affect the Company's  financial  position or results of
operations,  but such  changes  could  have a material  impact on the  Company's
evaluation and recognition of Section 29 tax credits, which, in turn, may have a
material impact on our results of operations and financial condition.

Synthetic  Fuel Risks  Associated  With  Fluctuations  in the Company's  Regular
Income Tax Liability

The Company's  synthetic fuel production levels and the amount of tax credits it
can claim  each year are a  function  of the  Company's  projected  consolidated
regular federal income tax liability.  Any conditions that negatively impact the
Company's  tax  liability,  such as weather,  could also  diminish the Company's
ability  to utilize  credits,  including  those  previously  generated,  and the
synthetic fuel is generally not economical to produce absent the credits.

Synthetic Fuel Risks Associated With Crude Oil Prices

Recent unprecedented and unanticipated increases in the price of oil could limit
the amount of Section 29 tax credits or eliminate  them  altogether.  Section 29
provides that if the average wellhead price per barrel for unregulated  domestic
crude oil for the year (the "Annual Average Price") exceeds a certain  threshold
value (the "Threshold Price"),  the amount of Section 29 tax credits are reduced
for that year.  Also,  if the Annual  Average Price  increases  high enough (the
"Phase Out Price"), the Section 29 tax credits are eliminated for that year. For
2003,  the  Threshold  Price was  $50.14  per barrel and the Phase Out Price was

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$62.94 per  barrel.  The  Threshold  Price and the Phase Out Price are  adjusted
annually for inflation.  Although data for 2004 is not yet available,  we do not
expect the amount of our 2004 Section 29 tax credits to be adversely affected by
oil prices.  We cannot  predict with any certainty the Annual  Average Price for
2005 or beyond.  Therefore, we cannot predict whether the price of oil will have
a material effect on our synthetic fuel business after 2004.  However, if during
2005 through 2007,  oil prices remain at  historically  high levels or increase,
our  synthetic  fuel  business  may be  adversely  affected for those years and,
depending on the magnitude of such  increases in oil prices,  the adverse affect
for those years could be material and could have an impact on our synthetic fuel
production  plans which,  in turn, may have a material  impact on our results of
operations and financial condition.

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.

At December 31, 2004, we had approximately  3,100 MW 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
          o 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.

     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.  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.

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     o    Our facilities seek to enter into long-term power purchase  agreements
          to sell all or a portion of their generating  capacity.  CCO currently
          owns six electricity generation facilities with approximately 3,100 MW
          of generation capacity, and it has contractual rights to an additional
          2,500 MW of generation capacity from mixed fuel generation  facilities
          through   its   agreements   with  16  Georgia   electric   membership
          cooperatives  (EMCs).  CCO has contracts  for its combined  production
          capacity of approximately 77% for 2005, 81% for 2006 and 75% for 2007.
          Three above-market  tolling  agreements for approximately  1,200 MW of
          capacity  expired at the end of 2004.  CCO has  replaced  the  expired
          agreements  with  the  increased  cooperative  load  in  Georgia.  The
          increased  cooperative  load in Georgia  will  significantly  increase
          CCO's  revenue and cost of sales from 2004 to 2005 with lower  margins
          expected.  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.  More  recently we have moved from  tolling  arrangements  to full
requirements  contracts  which  have  lower  margins.  These  contracts  do  not
guarantee  us any rate of return on our  capital  investments  through  mandated
rates,  and our  revenues and results of  operations  from these  contracts  are
likely to depend,  in large part, upon prevailing market prices for power in our
regional  markets  and  other  competitive  markets.  These  market  prices  can
fluctuate  substantially  over relatively short periods of time. Trading margins
may  erode  as  markets  mature,  and  should  volatility  decline,  we may have
diminished opportunities for gain.

In  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;

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     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.

Our Fuels business  segment is involved in natural gas drilling and  production,
coal  terminal  services,  coal  mining,  and fuel  transportation  and delivery
operations  that are subject to risks that may reduce our revenues and adversely
impact our results of operations and financial condition.

The  Fuels  business   segment  engages  in  businesses  that  have  significant
operational  and  financial  risk.  Operational  risk  includes  the  activities
involved with natural gas drilling,  coal mining,  terminal and barge operations
and fuel  delivery.  Financial  risks  include  exposure  to  commodity  prices,
primarily fuel prices.  We actively  manage the  operational and financial risks
associated with these  businesses.  Nonetheless,  adverse changes in fuel prices
and  operational  issues beyond our control may result in losses in our earnings
or cash flows and adversely affect our balance sheet.


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PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS

In this section,  unless the context indicates  otherwise,  references to "our,"
"we," "us" or similar terms refer 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.  Most of the business information as well as the financial and
operational  data contained in our risk factors are updated  periodically in the
reports we file with the SEC.  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, financial condition and 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 subject
to regulatory  oversight with respect to, among other things,  rates and service
for electric  energy sold at retail,  retail service  territory and issuances of
securities.  In addition our operating  utilities are subject to regulation with
respect to  transmission  and sales of wholesale  power,  accounting and certain
other  matters.  We are also  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 2004 working on a  comprehensive  energy bill.
While  that  legislation  passed  the  House,  the  Senate  failed  to pass  the
legislation  in  2004.  There  will  probably  be an  effort  to  resurrect  the
legislation in 2005. 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 the Public Utility  Holding  Company Act of 1935  ("PUHCA").  We cannot
predict the outcome or impact of the proposed or any future energy bill.

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  PUHCA,  we are  subject  to  many of the
regulatory provisions of PUHCA.

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, financial condition and results of operations.

We are subject to  numerous  environmental  laws and  regulations  that  require
significant capital expenditures, increase our cost of operations, and which may
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.

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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.

Our compliance  with  environmental  regulations  requires  significant  capital
expenditures  that impact our financial  condition.  For example,  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.  We expect the capital costs required to
meet these emission targets will total  approximately $895 million by 2013. Over
the next three  years,  we expect to incur  approximately  $510 million of total
capital costs associated with this legislation.

Congress currently considering further legislation that would require reductions
in air  emissions  of 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 our  consolidated
financial  position or results of  operations.  However,  we cannot  predict the
outcome,  costs or impact of this matter. In December 2003, the EPA released its
proposed  Interstate  Air Quality Rule,  currently  referred to as the Clean Air
Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions,  including
North  Carolina,  South  Carolina,  Georgia and  Florida,  to reduce NOx and SO2
emissions in order to attain preset state NOx and SO2 emissions levels. The rule
is  expected  to become  final in March  2005.  While the air  quality  controls
already  installed and currently  planned for installation to comply with the NC
Clean  Air  legislation  will  reduce  the  costs  required  to  meet  the  CAIR
requirements for the our North Carolina units,  additional compliance costs will
be determined  once the rule is  finalized.  In March 2004,  the North  Carolina
Attorney  General  filed a petition  with the EPA under Section 126 of the Clean
Air Act,  asking the federal  government  to force  coal-fired  power  plants in
thirteen  other  states,  including  South  Carolina to reduce their NOx and SO2
emissions.  The state of North Carolina  contends these  out-of-state  emissions
interfere with North Carolina's  ability to meet national air quality  standards
for ozone and particulate  matter. The EPA has agreed to make a determination on
the  petition  by August 1,  2005.  PEC  cannot  predict  the  outcome  or costs
associated with the matter.

See  additional  discussion  of these  environmental  matters  in Note 17 to the
Progress Energy Carolinas Consolidated Financial Statements.

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 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 SMD NOPR could  materially
alter the manner in which transmission and generation  services are provided and
paid for, and includes structural  separation of transmission from other utility
functions  and the FERC's  assertion of  jurisdiction  over  certain  aspects of
retail  service.  We cannot  predict the outcome or timing of any final rules or
the effect that they may have on the GridSouth proceedings.

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<PAGE>

At the state level,  significant uncertainty exists with respect to what action,
if any, the NCUC will ultimately  take. The Company has $33 million  invested in
GridSouth  related to startup  costs at December  31,  2004.  These  amounts are
included as a  regulatory  asset at December 31,  2004.  The Company  expects to
recover  these  startup  costs  in  conjunction  with  the  GridSouth   original
structures or in conjunction with any alternate combined transmission structures
that may be required.  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.

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 it will be created,  or whether it 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,  cash flows and ability to pay
dividends  on our common stock may be affected by changing  weather  conditions.
Weather  conditions  in our  service  territories  in North  Carolina  and South
Carolina  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 and market prices peak during the hot summer  months.
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.  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,  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 ability to recover significant costs resulting from severe weather events is
subject to  regulatory  oversight and the timing and amount of any such recovery
is uncertain and may impact our financial conditions.

PEC is not required to maintain a storm damage reserve account and does not have
an ongoing regulatory mechanism to recover storm costs and; therefore, hurricane
restoration  costs  recorded  in the  third  quarter  of 2004  were  charged  to
operations and maintenance  expenses or capital expenditures based on the nature
of the work  performed.  In  connection  with other storms,  PEC has  previously
sought  and  received  permission  from the NCUC  and the  SCPSC to defer  storm
expenses and amortize them over a five-year period. PEC did not seek recovery of
2004 storm costs from the NCUC.

Our revenues,  operating results and financial  condition may fluctuate with the
economy and its corresponding  impact on our commercial and industrial customers
as well as the demand and competitive state of the wholesale market.

Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2004, commercial and industrial customers represented approximately
25% and 19%, respectively, of our billed 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 recent years,  in North and South  Carolina,  sales to
industrial customers have been affected by downturns in the textile and chemical
industries.

For the year ended December 31, 2004, 16% of our billed  electric  revenues were
from wholesale sales.  Wholesale revenues  fluctuate with regional demand,  fuel
prices, and contracted capacity.  Our wholesale  profitability is dependent upon
our ability to renew or replace expiring wholesale contracts on favorable terms.
During  2004,   wholesale  revenues  decreased  from  expiring  contracts  being
renegotiated by us at less favorable terms due to slightly depressed markets and
from increased  competition in the wholesale markets served by us. If this trend
market environment persists, we may experience further declines in our wholesale
revenues.

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<PAGE>

In April 2004, the FERC issued two orders concerning  utilities' ability to sell
wholesale  electricity  at  market-based  rates.  In the first  order,  the FERC
adopted two new interim screens for assessing potential  generation market power
of  applicants  for  wholesale  market-based  rates,  and  described  additional
analyses and  mitigation  measures that could be presented if an applicant  does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider  whether the FERC's current  methodology
for  determining  whether a public  utility  should be allowed to sell wholesale
electricity  at  market-based  rates  should be modified  in any way.  Given the
difficulty  PEC  believes  it would  experience  in passing  one of the  interim
screens,  on August 12,  2004,  PEC  notified  the FERC that it would revise its
Market-based  Rate tariff to restrict it to sales  outside our control  area and
file a new cost-based tariff for sales within our control area that incorporates
the FERC's default  cost-based rate methodologies for sales of one year or less.
We anticipate  making this filing the first  quarter of 2005. We cannot  predict
what impact our  requirement  to implement  cost-based  tariffs will have on our
future financial condition, results of operations or cash flows.

Deregulation or restructuring  in the electric  industry may result in increased
competition  and  unrecovered  costs that could  adversely  affect our financial
condition, results of operations or cash flows.

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 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.

Increased commodity prices may adversely affect the financial condition, results
of operations or cash flows of us and our utilities' businesses.

We are  exposed to the  effects of market  fluctuations  in the price of natural
gas, coal, fuel oil, electricity and other energy-related  products marketed and
purchased as a result of its  ownership  of  energy-related  assets.  While each
state  commission  allows  electric  utilities to recover certain of these costs
through various cost recovery clauses,  there is the potential that these future
costs could be deemed imprudent by the respective  commissions.  There is also a
delay  between the timing of when these costs are incurred by the  utilities and
when these costs are recovered from the ratepayers,  which can adversely  impact
our cash flows.

Prices for SO2  emission  allowance  credits  under the EPA's  emission  trading
program increased  significantly  during 2004. While SO2 allowances are eligible
for annual  recovery  in our  jurisdiction  in South  Carolina,  no such  annual
recovery  exists  in  North  Carolina.  Future  increases  in the  price  of SO2
allowances  could  have  a  significant  adverse  financial  impact  on  us  and
consequently on our results of operations and cash flows.

Risks Related to Us and Our Business

The rates that we 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 do not control operating costs.

The NCUC and the  SCPSC  each  exercise  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.

Additionally,  under the NC Clean Air legislation in North  Carolina,  passed in
2002,  PEC's base  retail  rates were  frozen  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,  and we
have agreed not to seek a base retail  electric rate increase in South  Carolina

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<PAGE>

through 2005. The same  legislation  required a significant  increase in capital
expenditures  over the next several years for clean air  improvements.  The cash
costs incurred by us is 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 3,448 MW, or
28%, of our  generation  capacity  for the year ended  December  31,  2004.  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.

From time to time,  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 as required. 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.

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   hurricanes,   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.

We rely on access to both short-term and long-term capital markets, and lines of
credit with  commercial  banks 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 these sources of liquidity, 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 to below investment grade
would  increase our cost of borrowing  and may  adversely  affect our ability to
access  one or more  financial  markets.  Market  disruptions  create  a  unique
uncertainty  as they  typically  result from factors  beyond are  control.  Such
market disruptions could include:

     o    an economic downturn;
     o    the bankruptcy of an unrelated energy company;
     o    capital market conditions generally;

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<PAGE>

     o    allegations of corporate scandal at unrelated companies;
     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.

In  addition,  we  believe  that  these  market  disruptions,  unrelated  to our
business, could result in a ratings downgrade and, correspondingly, increase our
cost of capital.  Additional  risks regarding the impact of a ratings  downgrade
are discussed below. 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, 2004, our commercial paper
and bank borrowings and long-term debt balances were as follows (in millions):

  ----------------------------------------------------------------------
                            Outstanding
                          Commercial Paper             Total Long-Term
  Company                and Bank Borrowings             Debt, Net
  ----------------------------------------------------------------------
   PEC                             221                     2,750 (a)
  ----------------------------------------------------------------------
  (a) Net of current portion, which at December 31, 2004, was $300 million.

At  December  31,  2004,  we had two  committed  credit  lines that  support our
commercial  paper  programs  totaling $450 million.  While our financial  policy
precludes us from issuing  commercial  paper in excess of our credit  lines,  at
December 31, 2004, we had outstanding borrowings on our credit facilities of $90
million and an outstanding commercial paper balance of $131 million,  leaving an
additional $229 million available for future borrowing under our credit lines.

Our credit lines impose various limitations that could impact our liquidity. Our
credit  facilities  include  a  defined  maximum  total  debt to  total  capital
(leverage)  ratio. At December 31, 2004, the maximum and actual leverage ratios,
pursuant  to  the  terms  of  the  credit   facilities,   were  65%  and  52.3%,
respectively. Under the credit facilities, indebtedness includes certain letters
of credit and  guarantees  which are not  recorded on our  Consolidated  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 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.   Our  credit  lines  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.  Our cross-default  provisions only apply to defaults of
indebtedness, but not defaults by our affiliates.

                                      209
<PAGE>

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  which  would  cause us to be rated below
investment grade would likely 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.

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),  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.  In October 2004, S&P reduced our  short-term  debt rating to A-3 from
A-2.  As a result  of the  impact  of these  actions,  we have  borrowed  on our
revolving credit  agreements.  Due to the lower short-term debt rating issued by
S&P, we may continue to borrow under our revolving credit facilities  instead of
issuing   commercial  paper  due  to  the  difference  in  investor  demand  for
lower-rated  commercial paper. 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.

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<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 16, 2005                     (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.
                                         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/ Robert B. McGehee                Director              March 16, 2005
---------------------
(Robert B. McGehee,
 Chairman)


/s/ Edwin B. Borden                 Director               March 16, 2005
-------------------
(Edwin B. Borden)


/s/ James E. Bostic, Jr.            Director               March 16, 2005
-----------------------
(James E. Bostic, Jr.)


/s/ David L. Burner                 Director               March 16, 2005
-------------------
(David L. Burner)

                                      211
<PAGE>


/s/ Charles W. Coker                Director               March 16, 2005
---------------------
(Charles W. Coker)


/s/ Richard L. Daugherty            Director               March 16, 2005
(Richard L. Daugherty)


/s/ W.D. Frederick, Jr.             Director               March 16, 2005
-----------------------
(W.D. Frederick, Jr.)


/s/ William O. McCoy                Director               March 16, 2005
---------------------
(William O. McCoy)


/s/ E. Marie McKee                  Director               March 16, 2005
-------------------
(E. Marie McKee)


/s/ John H. Mullin, III             Director               March 16, 2005
-----------------------
(John H. Mullin, III)


/s/ Richard A. Nunis                Director               March 16, 2005
(Richard A. Nunis)

/s/Peter S. Rummell                 Director               March 16, 2005
(Peter S. Rummell)

/s/ Carlos A. Saladrigas            Director               March 16, 2005
------------------------
(Carlos A. Saladrigas)


/s/ Jean Giles Wittner              Director               March 16, 2005
----------------------
(Jean Giles Wittner)


                                      212
<PAGE>

                                                   EXHIBIT INDEX

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
                                                                                Progress
Number                     Exhibit                                              Energy, Inc.         PEC

*2(a)             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(b)             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).

*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
                  March  17,  2004,   (filed  as  Exhibit  No.  3(ii)(b)  to
                  Quarterly  Report  on Form 10-Q for the  quarterly  period
                  ended March 31, 2004, File No. 1-3382 and 1-15929).

*3b(3)            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(4)            By-Laws of Progress Energy,  Inc., as amended on March 17,        X
                  2004,  (filed as Exhibit No. 3(ii)(a) to Quarterly  Report
                  on Form  10-Q for the  quarterly  period  ended  March 31,
                  2004, File No. 1-3382 and 1-15929).

*3b(5)            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).

                                      213
<PAGE>

*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,                          X
                  between  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  4(b) and  4(c),  File  No.  33-33431;
                  Exhibits 4(b) and 4(c), File No.  33-38298;  Exhibits 4(h)

                                      214
<PAGE>

                  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,  File No.  1-3382  and
                  1-15929);  and the Seventy-second  Supplemental  Indenture
                  (Exhibit 4 to PEC Report on Form 8-K dated  September  12,
                  2003, File No. 1-3382).

*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  and  Bankers  Trust  Company,  as
                  Trustee,  with  respect  to  Unsecured  Subordinated  Debt
                  Securities  (filed as Exhibit No.  4(c) to Current  Report
                  on Form 8-K dated April 13, 1995, File No. 1-3382).

*4c(3)            Resolutions  adopted  by the  Executive  Committee  of the                          X
                  Board of  Directors  at a meeting  held on April 13, 1995,
                  establishing  the  terms  of the  8.55%  Quarterly  Income
                  Capital  Securities  (Series  A  Subordinated   Deferrable
                  Interest  Debentures)  (filed as  Exhibit  4(b) to Current
                  Report on Form 8-K dated April 13, 1995, File No. 1-3382).

*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).

                                      215
<PAGE>

*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).

*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.   $600,000,000  364-Day  Revolving        X
                  Credit  Agreement dated as of January 31, 2005,  (filed as
                  Exhibit  10 to Current  Report on Form 8-K filed  February
                  4, 2005, File No. 1-15929).

*10b(2)           Progress  Energy,  Inc.   $1,130,000,000 5-Year  Revolving        X
                  Credit  Agreement  dated as of August 5,  2004,  (filed as
                  Exhibit  10(i) to  Quarterly  Report  on Form 10-Q for the
                  period ended June 30, 2004, File No. 1-3382 and 1-15929).

                                      216
<PAGE>

 *10b(3)          Amendment and  Restatement,  dated as of July 30, 2003, to                          X
                  the  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. 1-03382 and 1-15929).

*10b(4)           Notice,  dated  March  25,  2003,  to the  Agent  for  the                          X
                  Lenders  named  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(5)           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 $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. 1-03382 and 1-15929).

 *10b(6)          Carolina  Power  &  Light  Company   $272,500,000  364-Day                          X
                  Revolving  Credit  Agreement  dated as of July  31,  2002,
                  (filed as  Exhibit  10(iii)  to  Quarterly  Report on Form
                  10-Q for the period ended  September  30,  2002,  File No.
                  1-3382 and 1-15929).

 *10b(7)          Carolina  Power  &  Light  Company   $272,500,000   3-Year                          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
                  and 1-15929).

*10b(8)           PEF  364-Day  $200,000,000  Credit  Agreement  dated as of        X
                  April 1, 2003  (filed as Exhibit  10(ii) to Florida  Power
                  Corporation  Form  10-Q for the  quarter  ended  March 31,
                  2003).

*10b(9)           PEF  3-Year  $200,000,000  Credit  Agreement,  dated as of        X
                  April 1, 2003,  (filed as Exhibit  10(iii) to the  Florida
                  Power  Corporation  Form 10-Q for the quarter  ended March
                  31, 2003).

10b(10)           Amendment, dated as of March 11, 2005, to the $1,130,000,000      X
                  5-Year Revolving Credit Agreement among Progress Energy, Inc.,
                  and certain lenders, dated August 5, 2004.

-+*10c(1)         Retirement   Plan  for   Outside   Directors   (filed   as                          X
                  Exhibit 10(i), File No. 33-25560).

-+*10c(2)         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(3)          Resolutions  of Board of  Directors  dated  July 9,  1997,                          X
                  amending   the   Deferred   Compensation   Plan   for  Key
                  Management Employees of Carolina Power & Light Company.

-+*10c(4)         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.)

                                      217
<PAGE>

+*10c(5)          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(6)         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(7)          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(8)          Progress  Energy,  Inc.  Form of Stock Option Award (filed        X                 X
                  as Exhibit 4.5 to Form S-8 dated  September 27, 2001, File
                  No. 333-70332).

+*10c(9)          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(10)         Amended   Management   Incentive   Compensation   Plan  of        X                 X
                  Progress Energy,  Inc.,  effective January 1, 2005, (filed
                  as  Exhibit  10(i) to  current  report  on Form 8-K  dated
                  December 13, 2004, File Nos. 1-3382,  1-3274,  1-15929 and
                  1-8349).

+10c(11)          Progress Energy Inc., Amended and Restated Management             X                 X
                  Deferred Compensation Plan, Adopted as of January 1,
                  2000, as Revised and Restated, effective January 1, 2005.

+10c(12)          Progress Energy, Inc. Management  Change-in-Control  Plan,        X                 X
                  Amended and Restated Effective as of January 1, 2005.

+10c(13)          Amended  Performance  Share  Sub-Plan of the 2002 Progress        X                 X
                  Energy,   Inc.  Equity  Incentive  Plan  effective  as  of
                  January 1, 2005.

+*10c(14)         Form of Deferred Compensation Plan for Directors--Method          X                 X
                  of Payment Agreement of Progress Energy, Inc., effective
                  as of January 1, 2005 (filed as Exhibit 10(ii) to Current
                  Report on Form 8-K dated December 13, 2004, File Nos.
                  1-3382, 1-3274, 1-15929 and 1-8349).

+10c(15)          Amended and Restated  Progress  Energy,  Inc.  Restoration        X                 X
                  Retirement Plan, effective as of January 1, 2005.

+10c(16)          Amended  and  Restated   Supplemental   Senior   Executive        X                 X
                  Retirement  Plan  of  Progress  Energy,   Inc.,   amended,
                  effective January 1, 2005.

                                      218
<PAGE>


+*10c(17)         Amended Non-Employee  Director Stock Unit Plan of Progress        X                 X
                  Energy,  Inc., effective January 1, 2005 (filed as Exhibit
                  10(iii) to Current  Report on Form 8-K dated  December 13,
                  2004, File Nos. 1-3382, 1-3274, 1-15929 and 1-8349).

+10c(18)          Form of Progress Energy,  Inc.  Restricted Stock Agreement
                  pursuant  to  the  2002   Progress   Energy  Inc.   Equity
                  Incentive Plan, as amended July 2002.

+*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 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(22)         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(23)         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 (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(24)         Form  of  Employment   Agreement  dated  August  1,  2000,        X                 X
                  between  Carolina  Power & Light  Company and Fred Day IV,
                  C.S.  "Scotty"  Hinnant and E. Michael  Williams (filed as
                  Exhibit  10(vi) to  Quarterly  Report on Form 10-Q for the
                  quarterly  period  ended  September  30,  2000,  File  No.
                  1-15929 and No. 1-3382).

+*10c(25)         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(26)         Form of Employment  Agreement  between (i) Progress Energy        X                 X
                  Service  Company and John R. McArthur,  effective  January
                  2003; (ii) Progress  Energy  Florida,  Inc. and Jeffrey J.
                  Lyash,  dated December 15, 2003; and (iii) Progress Energy
                  Carolinas,  Inc.  and Lloyd M.  Yates,  effective  January
                  2005  (filed as Exhibit  10c(27) to Annual  Report on Form
                  10-K  for the  year  ended  December  31,  2002,  File No.
                  1-3382 and 1-5929).

                                      219
<PAGE>

+*10c(27)         Employment   Agreement  dated  October  1,  2003,  between        X                 X
                  Progress  Energy  Service  Company  LLC  and  Geoffrey  S.
                  Chatas (filed as Exhibit  10c(28) to the Progress  Energy,
                  Inc.  Annual  Report  on  Form  10-K  for  the  year-ended
                  December 31, 2003).

+10c(28)          Agreement dated March 31, 2004,  between  Progress Energy,        X                 X
                  Inc. and William Cavanaugh III.

+10c(29)          Employment   Agreement  dated  January  1,  2005,  between        X                 X
                  Progress Energy Carolinas, Inc. and William D. Johnson.

+*10c(30)         Employment Agreement dated August 1, 2000, between                X                 X
                  Carolina 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).

10d(1)            Agreement  dated  November  18, 2004,  between  Winchester        X
                  Production  Company,  Ltd.,  TGG Pipeline  Ltd.,  Progress
                  Energy, Inc. and EnCana Oil & Gas (USA), Inc.

*10d(2)           Precedent  and  Related  Agreements  among  Florida  Power        X
                  Corporation  d/b/a Progress Energy Florida,  Inc. ("PEF"),
                  Southern   Natural  Gas  Company   ("SNG"),   Florida  Gas
                  Transmission  Company  ("FGT"),  and BG LNG Services,  LLC
                  ("BG"), including:

                  a)       Precedent  Agreement  by and between SNG and PEF,
                           dated December 2, 2004;
                  b)       Gas Sale and  Purchase  Contract  between  BG and
                           PEF, dated December 1, 2004;
                  c)       Interim Firm Transportation  Service Agreement by
                           and between FGT and PEF, dated December 2, 2004;
                  d)       Letter  Agreement  between  FGT  and  PEF,  dated
                           December   2,  2004,   and  Firm   Transportation
                           Service  Agreement  by and between FGT and PEF to
                           be  entered  into upon  satisfaction  of  certain
                           conditions precedent;
                  e)       Discount  Agreement  between  FGT and PEF,  dated
                           December 2, 2004;
                  f)       Amendment  to  Gas  Sale  and  Purchase  Contract
                           between BG and PEF, dated January 28, 2005; and
                  g)       Letter  Agreement  between  FGT  and  PEF,  dated
                           January 31, 2005,

                  (filed as  Exhibit  10.1 to  Current  Report on Form 8-K/A
                  filed March 15,  2005).  (Confidential  treatment has been
                  requested  for portions of this  exhibit.  These  portions
                  have  been  omitted  from  the  above-referenced   Current
                  Report and submitted separately to the SEC.)

                                      220
<PAGE>

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
</TABLE>


*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement required to be filed as
  an exhibit to this report pursuant to Item 14 (c) of Form 10-K.
-Sponsorship of this management contract or compensation plan or arrangement was
  transferred from Carolina Power & Light Company to Progress Energy, Inc.,
  effective August 1, 2000.


                                      221
<PAGE>




                              PROGRESS ENERGY, INC.
                                 EXHIBIT NO. 12
                COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

<TABLE>
<S>     <C>    <C>    <C>    <C>    <C>    <C>
--------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Years Ended December 31                                           2004         2003        2002         2001        2000
--------------------------------------------------------------------------------------------------------------------------

Earnings, as defined:
  Income from continuing operations before cumulative
    effect of changes in accounting principles              $      753   $      811   $     552  $       541  $      478
  Fixed charges, as below                                          689          682         711          719         275
  Amortization of capitalized interest                               1            1           -            -           -
  Preferred dividend requirements                                   (7)          (7)         (7)          (8)         (8)
  Minority interest                                                 17           (3)          -            -           -
  Capitalized interest                                              (7)         (20)        (38)           -           -
  Income taxes, as below                                           110         (119)       (166)        (162)        188
--------------------------------------------------------------------------------------------------------------------------
    Total earnings, as defined                              $    1,556   $    1,345   $   1,052  $     1,090  $      933
--------------------------------------------------------------------------------------------------------------------------

Fixed Charges, as defined:
  Interest on long-term debt                                $      598   $      613   $     600  $       578  $      224
  Other interest                                                    62           42          79          112          37
  Imputed interest factor in rentals - charged
    principally to operating expenses                               22           20          25           21           9
  Preferred dividend requirements of subsidiaries                    7            7           7            8           8
--------------------------------------------------------------------------------------------------------------------------
    Total fixed charges, as defined                         $      689   $      682   $     711  $       719  $      278
--------------------------------------------------------------------------------------------------------------------------

Income Taxes:
  Income tax expense (benefit)                              $      115   $     (111)  $    (158) $      (154)         196
  Included in AFUDC - deferred taxes in
    book depreciation                                               (5)          (8)         (8)          (8)         (8)
--------------------------------------------------------------------------------------------------------------------------
    Total income taxes                                      $      110   $     (119)  $    (166) $      (162) $      188
--------------------------------------------------------------------------------------------------------------------------

Ratio of Earnings to Fixed Charges                                2.26         1.97        1.48         1.52        3.36
--------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      222
<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>
------------------------------------------------------------------------------------------------------------------------
(million of dollars)
Years Ended December 31                                           2004        2003       2002         2001        2000
------------------------------------------------------------------------------------------------------------------------

Earnings, as defined:
  Income before cumulative effect of change in
   accounting principles                                    $      461  $      505  $     431  $       364  $      461
  Fixed charges, as below                                          202         205        224          264         246
  Income taxes, as below                                           234         233        199          215         282
------------------------------------------------------------------------------------------------------------------------
    Total earnings, as defined                              $      897  $      943  $     854  $       843  $      989
------------------------------------------------------------------------------------------------------------------------

Fixed Charges, as defined:
  Interest on long-term debt                                $      183  $      187  $     205  $       246  $      224
  Other interest                                                    12          11         12           11          17
  Imputed interest factor in rentals - charged
    principally to operating expenses                                7           7          7            7           5
------------------------------------------------------------------------------------------------------------------------
    Total fixed charges, as defined                         $      202  $      205  $     224  $       264  $      246
------------------------------------------------------------------------------------------------------------------------
  Preferred dividends, as defined                           $        5  $        4  $       4  $         5  $       5
------------------------------------------------------------------------------------------------------------------------
     Total fixed charges and preferred dividends combined   $      207  $      209  $     228  $       269  $      251
------------------------------------------------------------------------------------------------------------------------

Income Taxes:
  Income tax expense                                        $      239  $      241  $     207  $       223  $      290
  Included in AFUDC - deferred taxes in
    book depreciation                                               (5)         (8)        (8)          (8)         (8)
------------------------------------------------------------------------------------------------------------------------
    Total income taxes                                      $      234  $      233  $     199  $       215  $      282
------------------------------------------------------------------------------------------------------------------------

Ratio of Earnings to Fixed Charges                                4.44        4.60       3.81         3.19        4.02

Ratio of Earnings to Fixed Charges and Preferred
  Dividends Combined                                              4.33        4.51       3.75         3.13        3.94
------------------------------------------------------------------------------------------------------------------------
</TABLE>

                                      223
<PAGE>

                                                                     Exhibit 21


                      SUBSIDIARIES OF PROGRESS ENERGY, INC.
                              AT DECEMBER 31, 2004


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>

                                      224
<PAGE>


                                                                 Exhibit 23.(a)

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the  incorporation  by reference  in  Registration  Statement  No.
333-114237  on  Form  S-3,  Registration   Statement  No.  104952  on Form  S-8,
Registration  Statement  No.  33-33520 on Form S-8,  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
our  reports  dated  March 7, 2005,  relating to the  financial  statements  and
financial  statement  schedule of Progress  Energy,  Inc.  (which  report on the
consolidated  financial statements expresses an unqualified opinion and includes
an explanatory paragraph concerning the adoption of new accounting principles in
2003) and  management's  report on the  effectiveness  of internal  control over
financial  reporting,  appearing in this Annual  Report on Form 10-K of Progress
Energy, Inc. for the year ended December 31, 2004.

We also consent to the  incorporation by reference in  Post-Effective  Amendment
No. 1 to  Registration  Statement  No.  333-58800  on Form S-3 and  Registration
Statement  No.  333-103973  on Form S-3 of our  reports  dated  March  7,  2005,
relating  to the  financial  statements  and  financial  statement  schedule  of
Carolina  Power & Light Company d/b/a  Progress  Energy  Carolinas,  Inc.  (PEC)
(which report on the consolidated  financial statements expresses 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, 2004.

/s/ Deloitte & Touche LLP


Raleigh, North Carolina
March 15, 2005


                                      225