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<SEC-DOCUMENT>0001021408-02-004307.txt : 20020415
<SEC-HEADER>0001021408-02-004307.hdr.sgml : 20020415
ACCESSION NUMBER: 0001021408-02-004307
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 20
CONFORMED PERIOD OF REPORT: 20011231
FILED AS OF DATE: 20020328
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: CAROLINA POWER & LIGHT CO
CENTRAL INDEX KEY: 0000017797
STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911]
IRS NUMBER: 560165465
STATE OF INCORPORATION: NC
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-03382
FILM NUMBER: 02591389
BUSINESS ADDRESS:
STREET 1: 411 FAYETTEVILLE ST
CITY: RALEIGH
STATE: NC
ZIP: 27601
BUSINESS PHONE: 9195466111
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: PROGRESS ENERGY INC
CENTRAL INDEX KEY: 0001094093
STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911]
IRS NUMBER: 562155481
STATE OF INCORPORATION: NC
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-15929
FILM NUMBER: 02591388
BUSINESS ADDRESS:
STREET 1: 410 S WILMINGTON ST
CITY: RALEIGH
STATE: NC
ZIP: 27601
BUSINESS PHONE: 9195466463
MAIL ADDRESS:
STREET 1: 410 S WILMINGTON ST
CITY: RALEIGH
STATE: NC
ZIP: 27601
FORMER COMPANY:
FORMER CONFORMED NAME: CP&L ENERGY INC
DATE OF NAME CHANGE: 20000314
FORMER COMPANY:
FORMER CONFORMED NAME: CP&L HOLDINGS INC
DATE OF NAME CHANGE: 19990830
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>d10k405.txt
<DESCRIPTION>FORM 10-K
<TEXT>
<PAGE>
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, 2001
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>
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
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:
-----------------------------------------------------------
<TABLE>
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
<S> <C>
Progress Energy, Inc.:
Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
-----------------------------------------------------------
<TABLE>
<S> <C>
Progress Energy, Inc.: None
Carolina Power & Light Company: $100 par value Preferred Stock, Cumulative
$100 par value Serial Preferred Stock, Cumulative
</TABLE>
Indicate by check mark whether the registrants (1) have filed all reports to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrants were
required to file such reports), and (2) have been subject to such filing
requirements for the past 90 days.
Yes [X]. No [ ].
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in PART III of this Form 10-K or any amendment to this
Form 10-K. [X]
This combined Form 10-K is filed separately by two registrants: Progress Energy,
Inc. (Progress Energy) and Carolina Power & Light Company (CP&L). Information
contained herein relating to either individual registrant is filed by such
registrant solely on its own behalf.
As of February 28, 2002, the aggregate market value of the voting and non-voting
common equity of Progress Energy, Inc. held by non-affiliates was
$9,757,790,063. All of the common stock of Carolina Power & Light Company is
owned by Progress Energy, Inc. As of February 28, 2002, each registrant had the
following shares of common stock outstanding:
1
<PAGE>
<TABLE>
<CAPTION>
Registrant Description Shares
- ------------------------------ -------------------------------- ------------------------------
<S> <C> <C>
Progress Energy, Inc. Common Stock (Without Par Value) 218,727,139
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055 (all of which were
held by Progress Energy, Inc.)
</TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
Portions of the Progress Energy and CP&L definitive proxy statements dated April
1, 2002 are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof.
2
<PAGE>
TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ITEM 7A. QUANTITIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES AND REPORTS ON FORM 8-K
3
<PAGE>
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-K are defined below:
<TABLE>
<CAPTION>
TERM DEFINITION
---- ----------
<S> <C>
AFUDC Allowance for funds used during construction
APEC Albemarle-Pamlico Economic Development Corporation
ASLB Atomic Safety and Licensing Board
Bain Bain Capital, Inc. and affiliates
BellSouth Carolinas PCS BellSouth Carolinas, PCS L.P.
Btu British thermal units
Caronet Caronet, Inc.
CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended
Code Internal Revenue Service Code
CP&L Carolina Power & Light Company
CP&L Energy CP&L Energy, Inc., now known as Progress Energy, Inc.
CR3 Crystal River Unit No. 3
CVO Contingent value obligation
DEP Florida Department of Environment and Protection
D&D Decommissioning and decontamination
DOE Department of Energy
dt Dekatherm
DWM North Carolina Department of Environment and Natural Resources, Division of
Waste Management
EasternNC Eastern North Carolina Natural Gas Company, formerly referred to as ENCNG
EPS Earnings per share
EPA United States Environmental Protection Agency
EPA of 1992 Energy Policy Act of 1992
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Florida Power Florida Power Corporation
FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Harris Plant Shearon Harris Nuclear Plant
Interpath Interpath Communications, Inc.
IRS Internal Revenue Service
kWh Kilowatt-hour
kV Kilovolt
kVA Kilovolt-ampere
LIBOR London Inter Bank Offering Rate
LNG Liquefied natural gas
MEMCO MEMCO Barge Line, Inc.
MGP Manufactured Gas Plant
Monroe Power Monroe Power Company
MW Megawatt
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NEIL Nuclear Electric Insurance Limited
NOx SIP Call EPA rule which requires 22 states including North and South Carolina to further
reduce nitrogen oxide emissions.
NRC United States Nuclear Regulatory Commission
NSP Northern States Power
Nuclear Waste Act Nuclear Waste Policy Act of 1982
OPEB Contributory postretirement benefits
Pine Needle Pine Needle LNG Company, LLC
PLR's Private Letter Rulings
Pollution control bonds Pollution control revenue refunding bonds
Power Agency North Carolina Eastern Municipal Power Agency
Progress Capital Progress Capital Holdings, Inc.
</TABLE>
4
<PAGE>
<TABLE>
<S> <C>
Progress Energy Progress Energy, Inc.
Progress Rail Progress Rail Services Corporation
Progress Telecom Progress Telecommunications Corporation
Progress Ventures Business segment of Progress Energy primarily made up of merchant energy
generation, coal and synthetic fuel operations and energy marketing and
trading, formerly referred to as Energy Ventures
Progress Ventures, Inc. Legal entity of Progress Ventures (formerly referred to as CPL Energy
Ventures, Inc.)
PSSP Performance Share Sub-Plan
PSVA Price sensitive volume adjustment
PUHCA Public Utility Holding Company Act of 1935, as amended
PURPA Public Utilities Regulatory Policies Act of 1978
PWR Pressurized water reactor
QF Qualifying facilities
RSA Restricted Stock Awards program
RTO Regional Transmission Organization
SCE&G South Carolina Electric & Gas
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
SFAS No. 71 Statement of Financial Accounting Standards No. 71, Accounting for the
Effects of Certain Types of Regulation
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. 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. 141 Statement of Financial Accounting Standards No. 141, Business Combinations
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
SO2 Sulfur dioxide
SPSP Stock Purchase-Savings Plan
SRS Strategic Resource Solutions Corp.
the Company Progress Energy, Inc. and subsidiaries
Transco Transcontinental Gas Pipeline Corporation
</TABLE>
5
<PAGE>
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
In addition, examples of forward-looking statements discussed in this Form 10-K,
PART II, ITEM 7, "Management's Discussion and Analysis of Financial Condition
and Results of Operations" include, but are not limited to, statements under the
following headings: 1) "Liquidity and Capital Resources" about operating cash
flows, estimated capital requirements through the year 2004 and future financing
plans, 2) "Future Outlook" about Progress Energy's future earnings potential,
and 3) "Other Matters" about the effects of new environmental regulations,
nuclear decommissioning costs and the effect of electric utility industry
restructuring.
Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy nor CP&L undertakes any obligation to
update any forward-looking statement or statements to reflect events or
circumstances after the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: governmental policies and regulatory actions (including those of the
Federal Energy Regulatory Commission, the Environmental Protection Agency, the
Nuclear Regulatory Commission, the Department of Energy, the Securities and
Exchange Commission under the Public Utility Holding Company Act of 1935, as
amended, the North Carolina Utilities Commission, the Public Service Commission
of South Carolina and the Florida Public Service Commission), particularly
legislative and regulatory initiatives that may impact the speed and degree of
the restructuring of the electricity industry and the results of negotiations
related to the expiration of Florida Power's rate stipulation; the outcome of
legal and administrative proceedings, including proceedings before our principal
regulators; risks associated with operating nuclear power facilities,
availability of nuclear waste storage facilities, and nuclear decommissioning
costs; terrorist threats and activities, particularly with respect to our
facilities, economic uncertainty caused by recent terror attacks on the United
States, and potential adverse reactions to United States anti-terrorism
activities; changes in the economy of areas served by CP&L, Florida Power or
NCNG; the extent to which we are able to obtain adequate and timely rate
recovery of costs, including potential stranded costs arising from the
restructuring of the electricity industry; weather conditions and catastrophic
weather-related damage; general industry trends, increased competition from
energy and gas suppliers, and market demand for energy; inflation and capital
market conditions; the extent to which we are able to realize the potential
benefits of our acquisition of Florida Progress Corporation and successfully
integrate it with the remainder of our business; the extent to which we are able
to realize the potential benefits of the conversion of Carolina Power & Light
Company to a non-regulated holding company structure and the success of our
direct and indirect subsidiaries; the extent to which we are able to use tax
credits associated with the operations of the synthetic fuel facilities; the
extent to which we are able to reduce our capital expenditures through the
utilization of the natural gas expansion fund established by the North Carolina
Utilities Commission; and unanticipated changes in operating expenses and
capital expenditures.
All such factors are difficult to predict, contain uncertainties that may
materially affect actual results, and may be beyond the control of Progress
Energy and CP&L. New factors emerge from time to time, and it is not possible
for management to predict all such factors, nor can it assess the effect of each
such factor on Progress Energy and CP&L.
6
<PAGE>
PART I
ITEM 1. BUSINESS
- ------- --------
GENERAL
- -------
COMPANY
- -------
Progress Energy, Inc. (Progress Energy, or the Company, which term includes
consolidated subsidiaries unless otherwise indicated), is a registered holding
company under the Public Utility Holding Company Act (PUHCA) of 1935. Both the
Company and its subsidiaries are subject to the regulatory provisions of PUHCA.
Progress Energy was initially formed as CP&L Energy, Inc. (CP&L Energy), which
became the holding company for Carolina Power & Light Company (CP&L) on June 19,
2000. All shares of common stock of CP&L were exchanged for an equal number of
shares of CP&L Energy common stock.
On July 1, 2000, CP&L distributed its ownership interest in the stock of North
Carolina Natural Gas Corporation (NCNG), Strategic Resource Solutions Corp.
(SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc. to CP&L
Energy. As a result, those companies became direct subsidiaries of CP&L Energy
and are not included in CP&L's results of operations and financial position
since that date.
Subsequent to the acquisition of Florida Progress Corporation (FPC) (see
"Significant Transactions" below), the Company changed its name from CP&L Energy
to Progress Energy, Inc. on December 4, 2000.
Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation
(Florida Power) and NCNG, Progress Energy is primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida; and the transport, distribution and
sale of natural gas in portions of North Carolina. Through the Progress Ventures
business segment, Progress Energy is involved in merchant energy generation,
coal and synthetic fuel operations and energy marketing and trading. Through
other business units, Progress Energy engages in other non-regulated business
areas including energy management and related services, rail services and
telecommunications.
Progress Energy is a regional energy company focusing on the high-growth
Southeast region of the United States. The Company has more than 20,000
megawatts of electric generation capacity and serves approximately 2.9 million
electric and gas customers in portions of North Carolina, South Carolina and
Florida. CP&L's and Florida Power's utility operations are complementary: CP&L
has a summer peaking demand, while Florida Power has a winter peaking demand. In
addition, CP&L's greater proportion of commercial and industrial customers
combined with Florida Power's greater proportion of residential customers
creates a more balanced customer base. The Company is dedicated to expanding the
region's electric generation capacity and delivering reliable, competitively
priced energy.
Progress Energy revenues for the year ended December 31, 2001, were $8.5
billion, and assets at year-end were $20.7 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 a part of this document. Progress Energy was incorporated on August 19,
1999.
The operations of Progress Energy and its subsidiaries are divided into five
major segments: two electric utilities (CP&L and Florida Power), Progress
Ventures, Rail Services and Other. Progress Energy's legal structure is not
currently aligned with the functional management and financial reporting of its
segments. Whether, and when, the legal and functional structures will converge
depends upon legislative and regulatory action, which cannot currently be
anticipated. The Other segment primarily includes natural gas operations,
telecommunication services, energy management services, miscellaneous
non-regulated activities, holding company operations and elimination entries.
For information regarding the revenues, income and assets attributable to the
Company's business segments, see Note 3 to the Progress Energy consolidated
financial statements.
SIGNIFICANT TRANSACTIONS
- ------------------------
Florida Progress Acquisition
On November 30, 2000, the Company completed its acquisition of FPC for an
aggregate purchase price of approximately $5.4 billion. The Company paid cash
consideration of approximately $3.5 billion and issued 46.5 million common
shares valued at approximately $1.9 billion. In addition, the Company issued
98.6 million
7
<PAGE>
contingent value obligations (CVO) valued at approximately $49.3 million. See
Note 2A to the Progress Energy financial statements for additional discussion of
the FPC acquisition.
FPC is a diversified, exempt electric utility holding company. Florida Power,
FPC's largest subsidiary is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity. FPC also has
diversified non-utility operations owned through Progress Capital Holdings, Inc.
Included in diversified operations are Progress Fuels Corporation, an energy and
transportation company, and Progress Telecommunications Corporation, a wholesale
telecommunications service provider. As of the acquisition date, the primary
segments of Progress Fuels were energy and related services, rail services, and
inland marine transportation. During 2001, Progress Energy sold the inland
marine transportation segment to AEP Resources, Inc., as more fully discussed
below.
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.
Identifiable assets acquired and liabilities assumed have been recorded at their
fair values of $6.7 billion and $4.9 billion, respectively. The excess of the
purchase price over the fair value of the net identifiable assets and
liabilities acquired has been recorded as goodwill. The goodwill, of
approximately $3.6 billion, was being amortized on a straight-line basis over a
period of 40 years. Effective January 1, 2002, goodwill is no longer subject to
amortization.
Sale of MEMCO Barge Line, Inc.
On July 23, 2001, Progress Energy announced the disposition of the Inland Marine
Transportation segment of FPC, which was operated by MEMCO Barge Line, Inc.
Inland Marine provided transportation of coal, agricultural and other dry-bulk
commodities as well as fleet management services. On November 1, 2001, the
Company completed the sale of the Inland Marine Transportation segment to AEP
Resources, Inc., a wholly owned subsidiary of American Electric Power. See Note
4 to the Progress Energy consolidated financial statements for additional
discussion of this transaction.
LG&E Energy Corp. Acquisition
During February 2002, Progress Ventures, Inc. completed the acquisition of two
electric generating projects totaling nearly 1,100 megawatts in Georgia. See
Item 7, "Other Matters" for additional discussion of this transaction.
Westchester Gas Company Acquisition
On January 11, 2002, Progress Energy announced that it had entered into a letter
of intent with Westchester Gas Company to acquire approximately 215 producing
natural gas wells, 52 miles of intrastate gas pipeline and 170 miles of
gas-gathering systems. See Item 7, "Other Matters" for additional discussion of
this transaction.
COMPETITION
- -----------
GENERAL
- -------
In recent years, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. Several states have also decided to restructure aspects
of retail electric service. The issue of retail restructuring and competition is
being reviewed by a number of states and bills have been introduced in past
sessions of Congress that sought to introduce such restructuring in all states.
Allowing increased competition in the generation and sale of electric power will
require resolution of many complex issues. One of the major issues to be
resolved is who would pay for stranded costs. Stranded costs are those costs and
investments made by utilities in order to meet their statutory obligation to
provide electric service, but which could not be recovered through the market
price of electricity following industry restructuring. The amount of such
stranded costs that the Company might experience would depend on the timing of,
and the extent to which, direct competition is introduced, and the then-existing
market price of energy. If both electric utilities and the gas utility were no
longer subject to cost-based regulation and it was not possible to recover
stranded costs, the financial position and results of operations of the Company
could be adversely affected.
Several electric industry restructuring bills introduced during the 106th
Congress died upon adjournment in 2000. During the 107th Congress, attention has
turned more toward a comprehensive energy policy as opposed to restructuring of
the electric industry. However, restructuring could eventually become part of
any legislation and/or
8
<PAGE>
specific electric industry restructuring legislation could be introduced and
considered by Congress. The Company cannot predict the outcome of this matter.
As a result of the Public Utilities Regulatory Policies Act of 1978 (PURPA) and
the Energy Policy Act of 1992 (EPA of 1992), competition in the wholesale
electricity market has greatly increased, especially from non-utility generators
of electricity. In 1996, the Federal Energy Regulatory Commission (FERC) issued
new rules on transmission service to facilitate competition in the wholesale
market on a nationwide basis. The rules give greater flexibility and more
choices to wholesale power customers.
On December 20, 1999, FERC issued Order No. 2000 on Regional Transmission
Organizations (RTO), which sets forth four minimum characteristics and eight
functions for transmission entities, including independent system operators and
transmission companies, that are required to become FERC-approved RTOs. The rule
stated that public utilities that own, operate or control interstate
transmission facilities had to have filed, by October 15, 2000, either a
proposal to participate in an RTO or an alternative filing describing efforts
and plans to participate in an RTO. The order provided guidance and specified
minimum characteristics and functions required of an RTO and also stated that
all RTOs should be operational by December 15, 2001. During 2001, the deadline
for RTO's to be operational was extended. See PART I, ITEM 1, "Competition" of
CP&L Electric and Florida Power Electric for a discussion of the development
activities for the GridSouth RTO and GridFlorida RTO, respectively.
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.
The developments described above have created changing markets for energy. As a
strategy for competing in these changing markets, the Company is becoming a
total energy provider in the region by providing a full array of energy-related
services to its current customers and expanding its market reach. The Company
took a major step towards implementing this strategy through its acquisition of
FPC.
See PART I, ITEM 1, "Competition" discussion under Electric-CP&L,
Electric-Florida Power and Other for further discussion of competitive
developments within these segments.
PUHCA
- -----
As a result of the acquisition of FPC, Progress Energy is now a registered
holding company subject to regulation by the Securities and Exchange Commission
(SEC) under PUHCA. Therefore, Progress Energy and its subsidiaries are subject
to the regulatory provisions of PUHCA, including provisions relating to the
issuance of securities, sales and acquisitions of securities and utility assets,
and services performed by Progress Energy Service Company LLC.
While various proposals have been introduced in Congress regarding PUHCA, the
prospects for legislative reform or repeal are uncertain at this time.
ENVIRONMENTAL
- -------------
GENERAL
- -------
In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and local authorities. The
Company considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and operations
and believes it has all necessary permits to conduct such operations.
Environmental laws and regulations constantly evolve and the ultimate costs of
compliance cannot always be accurately estimated. The capital costs associated
with compliance with pollution control laws and regulations at the Company's
existing fossil facilities that the Company expects to incur from 2002 through
2004 are included in the estimates under the "Investing Activities" discussion
under PART II, ITEM 7, "Liquidity and Capital Resources."
CLEAN AIR LEGISLATION
- ---------------------
The 1990 amendments to the Clean Air Act require substantial reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric
generating plants. The Clean Air Act required the Company to meet more stringent
provisions effective January 1, 2000. The Company meets the sulfur dioxide
emissions requirements by maintaining sufficient sulfur dioxide emission
allowances. Installation of additional equipment was necessary to
9
<PAGE>
reduce nitrogen oxide emissions. Increased operation and maintenance costs,
including emission allowance expense, installation of additional equipment and
increased fuel costs are not expected to be material to the consolidated
financial position or results of operations of the Company.
The U.S. Environmental Protection Agency (EPA) has been conducting an
enforcement initiative related to a number of coal-fired utility power plants in
an effort to determine whether modifications at those facilities were subject to
New Source Review requirements or New Source Performance Standards under the
Clean Air Act. Both CP&L and Florida Power were asked to provide information to
the EPA as part of this initiative and cooperated in providing the requested
information. The EPA has initiated enforcement actions against other
unaffiliated utilities as part of this initiative, some of which have resulted
in settlement agreements calling for expenditures, ranging from $1.0 billion to
$1.4 billion. A utility that was not subject to a civil enforcement action
settled its New Source Review issues with the EPA for $300 million. These
settlement agreements have generally called for expenditures to be made over
extended time periods, and some of the companies may seek recovery of the
related cost through rate adjustments. The Company cannot predict the outcome of
this matter.
In 1998, the EPA published a final rule addressing the issue of regional
transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's
rule requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to
attain a pre-set state NOx emission level by May 31, 2004. CP&L is evaluating
necessary measures to comply with the rule and estimates its related capital
expenditures could be approximately $370 million, which has not been adjusted
for inflation. The Company spent approximately $46.3 million in 2001 related to
these expenditures. Increased operation and maintenance costs relating to the
NOx SIP Call are not expected to be material to the Company's results of
operations. Further controls are anticipated as electricity demand increases.
The Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act, which requires certain sources to make reductions in nitrogen
oxide emissions by May 1, 2003. The final rule also includes a set of
regulations that affect nitrogen oxide emissions from sources included in the
petitions. The North Carolina fossil-fueled electric generating plants are
included in these petitions. Acceptable state plans under the NOx SIP Call can
be approved in lieu of the final rules the EPA approved as part of the Section
126 petitions. CP&L, other utilities, trade organizations and other states
participated in litigation challenging the EPA's action. On May 15, 2001, the
District of Columbia Circuit Court of Appeals ruled in favor of the EPA, which
will require North Carolina to make reductions in nitrogen oxide emissions by
May 1, 2003. However, the Court in its May 15th decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in calculating
the emissions limits for utilities. In August 2001, the court granted a request
by CP&L and other utilities to delay the implementation of the Section 126 Rule
for electric generating units pending resolution by the EPA of the growth factor
issue. The Court's order tolls the three-year compliance period (originally set
to end on May 1, 2003) for electric generating units as of May 15, 2001. On
January 16, 2002, the EPA issued a memo to harmonize the compliance dates for
the Section 126 Rule and the NOx SIP Call. The new compliance date for all
affected sources is now May 31, 2004, rather than May 1, 2003, subject to the
completion of the EPA's response to the related court decision on the growth
factor issue. The Company cannot predict the outcome of this matter.
SUPERFUND
- ---------
The provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
clean up of hazardous waste sites. This statute imposes retroactive joint and
several liability. Some states, including North and South Carolina, have similar
types of legislation. There are presently several sites with respect to which
the Company has been notified by the EPA, the State of North Carolina or the
State of Florida of its potential liability, as described below in greater
detail.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under various federal and state
laws. The lead or sole regulatory agency that is responsible for a particular
former coal tar site depends largely upon the state in which the site is
located. There are several manufactured gas plant (MGP) sites to which both
electric utilities and the gas utility have some connection. In this regard,
both electric utilities and the gas utility, with other potentially responsible
parties, are participating in investigating and, if necessary, remediating
former coal tar sites with several regulatory agencies, including, but not
limited to, the EPA, the Florida Department of Environmental Protection (DEP)
and the North Carolina Department of Environment and Natural Resources, Division
of Waste Management (DWM). Although the Company may incur costs at these sites
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about which it has been notified, based upon current status of these sites, the
Company does not expect those costs to be material to its consolidated financial
position or results of operations.
Both electric utilities, the gas utility and Progress Ventures are periodically
notified by regulators such as the EPA and various state agencies of their
involvement or potential involvement in sites, other than MGP sites, that may
require investigation and/or remediation. Although the Company's subsidiaries
may incur costs at the sites about which they have been notified, based upon the
current status of these sites, the Company does not expect those costs to be
material to the consolidated financial position or results of operations of the
Company.
OTHER ENVIRONMENTAL MATTERS
- ---------------------------
On November 1, 2001, Progress Energy completed the sale of the Inland Marine
Transportation segment to AEP Resources, Inc. In connection with the sale,
Progress Energy entered into environmental indemnification provisions covering
both unknown and known sites. Progress Energy has recorded an accrual to cover
estimated probable future environmental expenditures. Progress Energy believes
that it is reasonably possible that additional costs, which cannot be currently
estimated, may be incurred related to the environmental indemnification
provision beyond the amounts accrued. Progress Energy cannot predict the outcome
of this matter.
Both electric utilities, the gas utility and Progress Ventures have filed claims
with the Company's general liability insurance carriers to recover costs arising
out of actual or potential environmental liabilities. Some claims have been
settled and others are still pending. While management cannot predict the
outcome of these matters, the outcome is not expected to have a material effect
on the Company's consolidated financial position or results of operations.
EMPLOYEES
- ---------
As of February 28, 2002, Progress Energy and its subsidiaries employed
approximately 16,200 full-time employees. Of this total, approximately 2,100
employees at Florida Power are represented by the International Brotherhood of
Electrical Workers. The current union contract was ratified in December 1999 and
expires in December 2002. The Company and some of its subsidiaries have a
non-contributory defined benefit retirement (pension) plan for substantially all
full-time employees and an employee stock purchase plan among other employee
benefits. The Company and some of its subsidiaries also provide contributory
postretirement benefits, including certain health care and life insurance
benefits, for substantially all retired employees.
As of February 28, 2002, CP&L employed approximately 5,600 full-time employees.
ELECTRIC - CP&L
- ---------------
GENERAL
- -------
CP&L is a public service corporation formed under the laws of North Carolina in
1926, and is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North and South Carolina. As of December 31,
2001, CP&L had a total summer generating capacity (including jointly-owned
capacity) of approximately 12,040 megawatts (MW).
CP&L distributes and sells electricity in 57 of the 100 counties in North
Carolina, and 14 counties in northeastern South Carolina. The territory served
is an area of approximately 34,000 square miles, including a substantial portion
of the coastal plain of North Carolina extending to the Atlantic coast between
the Pamlico River and the South Carolina border, the lower Piedmont section of
North Carolina, an area in northeastern South Carolina and an area in western
North Carolina in and around the city of Asheville. The estimated total
population of the territory served is more than 4.0 million. At December 31,
2001, CP&L was providing electric services, retail and wholesale, to
approximately 1.3 million customers. CP&L is subject to the rules and
regulations of FERC, the North Carolina Utilities Commission (NCUC) and the
Public Service Commission of South Carolina (SCPSC).
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BILLED ELECTRIC REVENUES
- ------------------------
CP&L's electric revenues billed by customer class, for the last three years, is
shown as a percentage of total CP&L electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2001 2000 1999
- ------------- ---- ---- ----
Residential 34% 33% 34%
Commercial 23% 22% 22%
Industrial 21% 23% 24%
Wholesale (a) 19% 18% 18%
Other retail 3% 4% 2%
(a) These revenues are managed by Progress Ventures on behalf of CP&L
Major industries in CP&L's service area include textiles, chemicals, metals,
paper, food, rubber and plastics, wood products, and electronic machinery and
equipment.
FUEL AND PURCHASED POWER
- ------------------------
Sources of Generation
CP&L's total system generation (including the North Carolina Eastern Municipal
Power Agency's (Power Agency) share) by primary energy source, along with
purchased power, for the last three years is set forth below:
ENERGY MIX PERCENTAGES
2001 2000 1999
---- ---- ----
Coal 49% 48% 48%
Nuclear 41% 43% 42%
Hydro 0% 1% 1%
Oil/Gas 2% 1% 1%
Purchased Power 8% 7% 8%
CP&L is generally permitted to pass the cost of recoverable fuel and purchased
power to its customers through fuel adjustment clauses. The future prices for
and availability of various fuels discussed in this report cannot be predicted
with complete certainty. However, CP&L believes that its fuel supply contracts,
as described below, will be adequate to meet its fuel supply needs.
CP&L's average fuel costs per million British thermal units (Btu) for the last
three years were as follows:
AVERAGE FUEL COST
(per million Btu)
2001 2000 1999
---- ---- ----
Coal $1.78 $1.70 $1.70
Nuclear 0.44 0.45 0.46
Hydro -- -- --
Oil (a) 6.38 5.51 3.70
Gas (a) 4.69 5.41 3.37
Weighted Average 1.26 1.21 1.16
(a) Changes in the unit price for oil and gas are due to market
conditions. Since these costs are primarily recovered through recovery
clauses established by regulators, the fluctuation does not materially
affect net income.
Coal
CP&L has short-term, intermediate and long-term agreements from which it expects
to receive approximately 100% of its coal burn requirements in 2002. These
agreements have expiration dates ranging from 2002 to 2006. All of the
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<PAGE>
coal that CP&L is currently purchasing under intermediate and long-term
agreements is considered to be low sulfur coal by industry standards. The
pending expiration of a railway contract on March 31, 2002, may result in
increases in the freight rates for the shipment of coal.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a concentrate and
the conversion of this uranium concentrate into uranium hexafluoride. Stages III
and IV entail the enrichment of the uranium hexafluoride and the fabrication of
the enriched uranium hexafluoride into usable fuel assemblies.
CP&L expects to meet its future nuclear fuel requirements from inventory on hand
and amounts received under contract. Although CP&L cannot predict the future
availability of uranium and nuclear fuel services, CP&L does not currently
expect to have difficulty obtaining uranium oxide concentrate and the services
necessary for its conversion, enrichment and fabrication into nuclear fuel. For
a discussion of CP&L's plans with respect to spent fuel storage, see PART I,
ITEM 1, "Nuclear Matters" for CP&L Electric.
Hydro
Hydroelectric power is electric energy generated by the force of falling water.
CP&L has four hydroelectric generating plants licensed by FERC: Walters,
Tillery, Blewett and Marshall. The total installed capacity for these units is
218 MW.
Oil & Gas
Oil is purchased under contracts and in the spot market from several suppliers.
The cost of CP&L's oil and gas is determined by market conditions. Management
believes that CP&L has access to an adequate supply of oil for the reasonably
foreseeable future. CP&L's natural gas supply is purchased under firm supply and
delivery contracts as well as spot market purchases from numerous suppliers.
CP&L believes that existing contracts for oil are sufficient to cover its
requirements when natural gas is unavailable during the winter period for CP&L's
combustion turbine peaker fleet.
Purchased Power
CP&L purchased 4,996,645 MWh in 2001, 4,467,802 MWh in 2000 and 4,730,657 MWh in
1999 of its system energy requirements (including Power Agency's share) and had
available 1,756 MW in 2001, 1,036 MW in 2000, and 1,489 MW in 1999 of firm
purchased capacity under contract at the time of peak load. CP&L may acquire
purchased power capacity in the future to accommodate a portion of its system
load needs.
COMPETITION
- -----------
Electric Industry Restructuring
CP&L continues to monitor progress toward a more competitive environment and has
actively participated in regulatory reform deliberations in North Carolina and
South Carolina. Movement toward deregulation in these states has been affected
by recent developments, including developments related to deregulation of the
electric industry in California and other states.
. North Carolina. On January 23, 2001, the Commission on the Future of
Electric Service in North Carolina announced that it would not
recommend any new laws on electricity deregulation to the 2001 session
of the North Carolina General Assembly, citing the commission's
determination that more research is needed. The commission's initial
report to the General Assembly, issued on May 16, 2000, had contained
several proposals, including a recommendation that electric retail
competition should begin in North Carolina by 2006. At its January 23,
2001, meeting, the commission requested that the NCUC consider
regulatory changes to facilitate the construction of wholesale
generation facilities by private companies, including the elimination
of requirements that such companies provide proof of a committed
customer base and need for additional power in order to obtain
operating licenses. Subsequently on May 21, 2001, the NCUC adopted a
revised rule that streamlined the certification process for wholesale
merchant generating plants. The Company cannot predict the outcome of
this matter.
13
<PAGE>
. South Carolina. CP&L expects the South Carolina General Assembly will
continue to monitor the experiences of states that have implemented
electric restructuring legislation.
Regional Transmission Organizations
In October 2000, CP&L, along with Duke Energy Corporation and South Carolina
Electric & Gas Company, filed with FERC an application for approval of a
for-profit transmission company, currently named GridSouth. On July 12, 2001,
FERC issued an order granting GridSouth RTO status and directing that certain
modifications to the RTO documents be made and filed within 90 days. In February
2002, CP&L and the other GridSouth applicants withdrew the GridSouth application
from the NCUC and SCPSC for purposes of making certain revisions to the
GridSouth proposal. The GridSouth applicants plan to refile their application
once those changes have been made.
See PART II, Item 7, "Other Matters," for additional discussion of GridSouth
RTO.
Franchises
CP&L has nonexclusive franchises with varying expiration dates in most of the
municipalities in which it distributes electric energy in North Carolina and
South Carolina. Of these 239 franchises, 194 have expiration dates ranging from
2008 to 2061 and 45 of these have no specific expiration dates. All but ten of
the 194 franchises with expiration dates have a term of sixty years. The
exceptions include one franchise with a term of ten years, one with a term of
twenty years, five with a term of thirty years, two with a term of forty years
and one with a term of fifty years. However, CP&L also serves within a number of
municipalities and in all of its unincorporated areas without existing franchise
ordinances.
Wholesale Competition
Since passage of the EPA of 1992, competition in the wholesale electric utility
industry has significantly increased due to a greater participation by
traditional electricity suppliers, wholesale power marketers and brokers, and
due to the trading of energy futures contracts on various commodities exchanges.
This increased competition could affect CP&L's load forecasts, plans for power
supply and wholesale energy sales and related revenues. The impact could vary
depending on the extent to which additional generation is built to compete in
the wholesale market, new opportunities are created for CP&L to expand its
wholesale load, or current wholesale customers elect to purchase from other
suppliers after existing contracts expire.
To assist in the development of wholesale competition, FERC, in 1996, issued
standards for wholesale wheeling of electric power through its rules on open
access transmission and stranded costs and on information systems and standards
of conduct (Orders 888 and 889). The rules require all transmitting utilities to
have on file an open access transmission tariff, which contains provisions for
the recovery of stranded costs and numerous other provisions that could affect
the sale of electric energy at the wholesale level. CP&L filed its open access
transmission tariff with FERC in mid-1996. Several wholesale and retail
customers filed protests challenging numerous aspects of CP&L's tariff and
requesting that an evidentiary proceeding be held. In July 1997, CP&L filed an
offer of settlement in this case which was certified by an administrative law
judge in September 1997. In February 2000, FERC issued a basket order for
several utilities including CP&L to file a compliance filing stating whether
there were any remaining undisputed issues surrounding CP&L's open access
transmission tariff. On May 1, 2000, CP&L made the compliance filing setting
forth the remaining undisputed issues and a plan for settling those issues. On
August 25, 2000, CP&L filed modifications to its open access transmission tariff
as a result of settlement negotiations with the remaining intervenors. In
November 2000 FERC approved the open access transmission tariff of CP&L with the
settlement modifications.
In February 2000 CP&L filed a joint open access tariff to reflect the merger
with FPC. FERC approved the joint tariff in July 2000 effective with completion
of the merger, which occurred on November 30, 2000. In April 2001, CP&L and FPC
each filed separate transmission tariffs as a result of FERC Order 614. FERC
approved the CP&L transmission tariff in June 2001. In April 2001, CP&L filed
changes to the Energy Imbalance provision of the transmission tariff. FERC has
yet to issue a final order on this filing. CP&L cannot predict the outcome of
this matter.
During 2001, legislation was introduced in South Carolina that would impose a
moratorium on the certification and construction of merchant plants until 2003
and prohibit the transfer or sale of a merchant plant certificate. Hearings
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<PAGE>
have been held on these bills but no action has been taken. In addition, the
Department of Health and Environmental Control of South Carolina has halted the
issuance of any air permits for merchant plants applying for such permits. The
SCPSC has contracted with a consulting firm to conduct a study on the impact of
merchant plants in South Carolina which is scheduled to be completed in June of
2002. No new construction of merchant plants has begun. CP&L cannot predict the
outcome of this matter.
REGULATORY MATTERS
- ------------------
General
CP&L is subject to regulation in North Carolina by the NCUC and in South
Carolina by the SCPSC with respect to, among other things, rates and service for
electric energy sold at retail, retail service territory and issuances of
securities. In addition, CP&L is subject to regulation by FERC with respect to
transmission and sales of wholesale power, accounting and certain other matters.
The underlying concept of utility ratemaking is to set rates at a level that
allows the utility to collect revenues equal to its cost of providing service
including a reasonable rate of return on its equity. Increased competition, as a
result of industry restructuring, may affect the ratemaking process.
Electric Retail Rates
The NCUC and the SCPSC authorize retail "base rates" that are designed to
provide a utility with the opportunity to earn a specific rate of return on its
"rate base", or investment in utility plant. These rates are intended to cover
all reasonable and prudent expenses of utility operations and to provide
investors with a fair rate of return. In its most recent rate cases in 1988, the
NCUC and the SCPSC each authorized a return on equity of 12.75% for CP&L.
See Note 13B and Note 8B to the Progress Energy and CP&L consolidated financial
statements, respectively, for additional discussion of CP&L's retail rate
developments during 2001.
Wholesale Rate Matters
CP&L is subject to regulation by FERC with respect to rates for transmission and
sale of electric energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the event of certain
emergency situations), the licensing and operation of hydroelectric projects
and, to the extent FERC determines, accounting policies and practices. CP&L and
its wholesale customers last agreed to a general increase in wholesale rates in
1988; however, wholesale rates have been adjusted since that time through
contractual negotiations.
Other Rate Matters
With approval from the NCUC and the SCPSC, CP&L accelerated the cost recovery of
its nuclear generating assets beginning January 1, 2000 and continuing through
2004. Also in 2000, CP&L received approval from the commissions to further
accelerate the cost recovery of its nuclear generation facilities in 2000. The
accelerated cost recovery of these assets resulted in additional depreciation
expense of approximately $75 million and $275 million in 2001 and 2000,
respectively. Recovering the costs of its nuclear generating assets on an
accelerated basis will better position CP&L for the uncertainties associated
with potential restructuring of the electric utility industry.
Fuel Cost Recovery
CP&L's operating costs not covered by the utility's base rates include fuel and
purchased power. Each state commission allows electric utilities to recover
certain of these costs through various cost recovery clauses, to the extent the
respective commission determines in an annual hearing that such costs are
prudent. Costs recovered by CP&L, by state, are as follows:
. North Carolina - fuel costs and the fuel portion of purchased power;
. South Carolina - fuel costs, purchased power costs, and emission
allowance expense
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<PAGE>
Each state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
- ---------------
General
CP&L owns and operates four nuclear units, which are regulated by the U.S.
Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954 and the
Energy Reorganization Act of 1974. In the event of noncompliance, the NRC has
the authority to impose fines, set license conditions, or shut down a nuclear
unit, or some combination of these, depending upon its assessment of the
severity of the situation, until compliance is achieved. NRC operating licenses
currently expire in December 2014 and September 2016 for Brunswick Units 2 and
1, respectively, in July 2010 for Robinson Unit No. 2 and in October 2026 for
the Harris Plant. Plans are in place to request the extension of the Robinson
and Brunswick operating licenses in 2002 and 2004, respectively. An extension
will also be sought for the Harris Plant, but the submittal date has not been
determined. A condition of the operating license for each unit requires an
approved plan for decontamination and decommissioning. The nuclear units are
periodically removed from service to accommodate normal refueling and
maintenance outages, repairs and certain other modifications.
CP&L is currently evaluating and implementing power uprate projects at its
nuclear facilities to increase electrical generation output. A power uprate was
completed at the Harris Plant during 2001 and power uprates are in progress at
the Brunswick and Robinson Nuclear Plants, which will be implemented in phases
over the next several years following regulatory approval. The total increased
generation from these projects is estimated to be approximately 250 megawatts.
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.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking of
Reactor Vessel Head Penetration Nozzles," requesting that all pressurized water
reactors (PWR) provide their plans for inspecting the reactor vessel head for
the conditions described in the bulletin. While performing this inspection,
FirstEnergy Corp.'s Davis Besse plant in Ohio found three penetrations with
evidence of leakage and further evidence of some wastage of the reactor vessel
head around two of these penetrations. As a result of finding the wastage of the
vessel head, the NRC issued Bulletin 2002-01, requesting licensees to assess
previous inspections of the reactor head and determine the potential for the
existence of conditions similar to that found at the Davis Besse plant.
The CP&L PWRs have completed the inspections requested by Bulletin 2001-01. Any
indications of leakage have been inspected and repaired, and no wastage of the
reactor vessel head has been observed at any of the plants. Based on these
inspections, responses to Bulletin 2002-01 are being prepared. CP&L does not
anticipate any adverse impact from this regulatory action.
Spent Fuel and Other High-Level Radioactive Waste
The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework
for development by the federal government of interim storage and permanent
disposal facilities for high-level radioactive waste materials. The Nuclear
Waste Act promotes increased usage of interim storage of spent nuclear fuel at
existing nuclear plants. CP&L will continue to maximize the use of spent fuel
storage capability within its own facilities for as long as feasible. With
certain modifications and additional approval by the NRC, CP&L's spent nuclear
fuel storage facilities will be sufficient to provide storage space for spent
fuel generated on CP&L's system through the expiration of the current operating
licenses for all of CP&L's nuclear generating units. Subsequent to the
expiration of these licenses, dry storage may be necessary.
On December 21, 2000, CP&L received permission from the NRC to increase its
storage capacity for spent fuel rods in Wake County, North Carolina. The NRC's
decision came two years after CP&L asked for permission to open two unused
storage pools at the Harris Plant. The approval means CP&L can complete cooling
systems and install
16
<PAGE>
storage racks in its third and fourth storage pools at the Harris Plant. Counsel
for the Board of Commissioners of Orange County, North Carolina, filed a
petition for review of the staff's decision by the NRC, which was rejected, and
then filed an appeal of the decision with the District of Columbia Circuit Court
of Appeals. On March 1, 2001, the Atomic Safety and Licensing Board (ASLB)
issued its order dismissing Orange County's contention that an environmental
impact statement was required for the additional storage plan at the Harris
plant, and ruling in CP&L's favor to permit CP&L to proceed with the pool
storage plan. On March 16, 2001, the Orange County Commissioners petitioned the
NRC for review of the ASLB order and filed a request for a stay of that order.
CP&L and the NRC staff responded to the petition and the request for stay. CP&L
cannot predict the outcome of this matter.
See PART II, ITEM 8, footnote 15 to the CP&L consolidated financial statements
for a discussion of CP&L's contract with the U.S. Department of Energy (DOE) for
spent nuclear waste.
Low-Level Radioactive Waste
Disposal costs for low-level radioactive waste that result from normal operation
of nuclear units have increased significantly in recent years and are expected
to continue to rise. Pursuant to the Low-Level Radioactive Waste Policy Act of
1980, as amended in 1985, each state is responsible for disposal of low-level
waste generated in that state. States that do not have existing sites may join
in regional compacts. The States of North Carolina and South Carolina were
participants in the Southeast Regional Compact and disposed of waste at a
disposal site in South Carolina along with other members of the compact.
Effective July 1, 1995, South Carolina withdrew from the Southeast regional
compact and excluded North Carolina waste generators from the existing disposal
site in South Carolina. Effective July 1, 2000, South Carolina joined with the
states of Connecticut and New Jersey to form the Atlantic Compact. With this
action the South Carolina law prohibiting North Carolina's access to Barnwell
was repealed. The new compact allows importation of out of region waste on a
limited basis until 2008. This includes access for the Company's North Carolina
nuclear plants, which had not had access to Barnwell since June 1995. CP&L's
nuclear plant in South Carolina has access to the existing disposal site in
South Carolina. In addition, the Envirocare disposal facility in Utah continues
to accept lower activity low-level waste.
Although CP&L does not control the future availability of low-level waste
disposal facilities, the cost of waste disposal or the development process, it
supports the development of new facilities and is committed to a timely and
cost-effective solution to low-level waste disposal. Although CP&L cannot
predict the outcome of this matter, it does not expect the cost of providing
additional on-site storage capacity for low-level radioactive waste to be
material to its consolidated financial position or results of operations.
Decommissioning
In CP&L's retail jurisdictions, provisions for nuclear decommissioning costs are
approved by the NCUC and the SCPSC and are based on site-specific estimates that
include the costs for removal of all radioactive and other structures at the
site. In the wholesale jurisdiction, the provisions for nuclear decommissioning
costs are approved by FERC. See PART II, ITEM 8, footnote 1G to the CP&L
consolidated financial statements for a discussion of CP&L's nuclear
decommissioning costs.
Enrichment Facilities Decontamination
CP&L and a number of other utilities are involved in litigation against the
United States challenging certain retroactive assessments imposed by the federal
government on domestic nuclear power companies to fund the decommissioning and
decontamination of the government's uranium enrichment facilities.
On March 21, 1997, CP&L filed suit against the U.S. Government in the U.S. Court
of Claims alleging breach of contract and illegal taking of property without
just compensation. In the alternative, CP&L alleges that the assessments are
illegally exacted in violation of the Due Process Clause of the U.S.
Constitution. CP&L also alleges that the assessments result in an
unconstitutional taking of its contractual benefits.
The suit arises out of several contracts under which the government provided
uranium enrichment services at fixed prices. After CP&L paid for enrichment
services provided under the contracts, the government, through federal
legislation enacted in 1992, imposed a retroactive price increase in order to
fund the decontamination and
17
<PAGE>
decommissioning of the government's gaseous diffusion uranium enrichment
facilities. The government is collecting this increase through an annual
"special assessment" levied upon all domestic utilities that had enrichment
services contracts with the government. Collection of the special assessments
began in 1992 and is scheduled to continue for a fifteen-year period.
To date, CP&L has paid over $57.6 million in special assessments, including
Power Agency's share of $6.7 million, and if continued throughout the
anticipated fifteen-year life, the special assessments would increase the cost
of CP&L's contracts by more than $97 million. CP&L seeks an order declaring that
all such special assessments are unlawful, an injunction prohibiting the
government from collecting future special assessments, and a refund of the
special assessments.
On February 9, 1999, the government moved to dismiss CP&L's complaint.
Subsequently, CP&L requested an order to stay the Claims Court action, pending
resolution of another case being heard in the Southern District of New York.
Following oral argument, and without benefit of any discovery, the Claims Court
denied CP&L's motion to stay, converted the government's motion to a motion for
summary judgment, and ordered the parties to submit additional briefing
regarding the motion for summary judgment. Following oral argument, on October
17, 2000, the Claims Court issued a decision granting the government's motion
for summary judgment on all counts. The Claims Court decision was appealed to
the Court of Appeals for the Federal Circuit on December 26, 2000. The Federal
Circuit has stayed the consideration of the case pending a decision by the
Supreme Court on a petition for writ of certiorari that was filed by
Commonwealth Edison in their case against the government. CP&L cannot predict
the outcome of this matter.
ELECTRIC - FLORIDA POWER
- ------------------------
GENERAL
- -------
Florida Power was incorporated in Florida in 1899, and is an operating public
utility engaged in the generation, purchase, transmission, distribution and sale
of electricity. At December 31, 2001, Florida Power had a total summer
generating capacity (including jointly-owned capacity) of approximately 8,012
MW.
Florida Power provided electric service during 2001 to an average of 1.4 million
customers in west central Florida. Its service area covers approximately 20,000
square miles and includes the densely populated areas around Orlando, as well as
the cities of St. Petersburg and Clearwater. Florida Power is interconnected
with 20 municipal and 9 rural electric cooperative systems. Major wholesale
power sales customers include Seminole Electric Cooperative, Inc. (Seminole) and
Florida Municipal Power Agency. Florida Power is subject to the rules and
regulations of FERC and the Florida Public Service Commission (FPSC).
BILLED ELECTRIC REVENUES
- ------------------------
Florida Power's electric revenues billed by customer class, for 2001 and 2000,
is shown as a percentage of total Florida Power electric revenues in the table
below:
BILLED ELECTRIC REVENUES
Revenue Class 2001 2000(a)
- ------------- ---- -------
Residential 54% 53%
Commercial 24% 24%
Industrial 7% 8%
Other retail 6% 5%
Wholesale (b) 9% 10%
(a) These figures reflect Florida Power's billed electric for the full year
ended December 31, 2000, which is generally representative of the period
Progress Energy owned Florida Power.
(b) These revenues are managed by Progress Ventures on behalf of Florida Power.
Important industries in Florida Power's territory include phosphate and 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.
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FUEL AND PURCHASED POWER
- ------------------------
General
Florida Power's consumption of various types of fuel depends on several factors,
the most important of which are the demand for electricity by Florida Power's
customers, the availability of various generating units, the availability and
cost of fuel and the requirements of federal and state regulatory agencies.
Florida Power's energy mix for 2001 and 2000 is presented in the following
table:
ENERGY MIX PERCENTAGES
Fuel Type 2001 2000 (a)
- --------- ---- --------
Coal (b) 33% 34%
Oil 16% 15%
Nuclear 15% 15%
Gas 14% 14%
Purchased Power 22% 22%
(a) These figures reflect Florida Power's energy mix percentages for the full
year ended December 31, 2000, which is generally representative of the
period Progress Energy owned Florida Power.
(b) Includes synthetic fuel from unrelated third parties and petroleum coke.
Florida Power is generally permitted to pass the cost of recoverable fuel and
purchased power to its customers through fuel adjustment clauses. The future
prices for and availability of various fuels discussed in this report cannot be
predicted with complete certainty. However, Florida Power believes that its fuel
supply contracts, as described below, will be adequate to meet its fuel supply
needs.
Florida Power's average fuel costs per million Btu for 2001 and 2000 were as
follows:
AVERAGE FUEL COST
(per million Btu)
2001 2000 (a)
----- -------
Coal (b) (c) $2.16 $1.89
Oil (c) 3.81 4.15
Nuclear .47 .47
Gas (c) 4.52 4.32
Weighted Average 2.59 2.46
(a) These figures reflect Florida Power's average fuel cost for the year ended
December 31, 2000, which is representative of the period Progress Energy
owned Florida Power.
(b) Includes synthetic fuel from unrelated third parties and petroleum coke.
(c) 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, the fluctuation does not materially
affect net income.
Coal
Florida Power anticipates a combined requirement of approximately 5.5 million to
6.0 million tons of coal and synthetic fuel in 2002. Most of the coal is
expected to be supplied from the Appalachian coal fields of the United States.
Approximately two-thirds of the fuel is expected to be delivered by rail and the
remainder by barge. The fuel is supplied by Progress Fuels, an affiliate of
Progress Energy, pursuant to contracts between Florida Power and Progress Fuels.
For 2002, Progress Fuels has medium and long-term contracts with various sources
for approximately 100% of the fuel requirements of Florida Power's coal units.
These contracts have price adjustment provisions. All the coal to be purchased
for Florida Power is considered to be low sulfur coal by industry standards.
Oil and Gas
Oil is purchased under contracts and in the spot market from several suppliers.
The cost of Florida Power's oil and gas is determined by market conditions.
Management believes that Florida Power has access to an adequate supply
19
<PAGE>
of oil for the reasonably foreseeable future. Florida Power's natural gas supply
is purchased under firm contracts and in the spot market from numerous suppliers
and is delivered under firm, released firm and interruptible transportation
contracts. Florida Power believes that existing contracts for oil are sufficient
to cover its requirements when natural gas transmission purchased on an
interruptible basis is not available.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a concentrate and
the conversion of this uranium concentrate into uranium hexafluoride. Stages III
and IV entail the enrichment of the uranium hexafluoride and the fabrication of
the enriched uranium hexafluoride into usable fuel assemblies.
Florida Power expects to meet its future nuclear fuel requirements from
inventory on hand and amounts received under contract. Although Florida Power
cannot predict the future availability of uranium and nuclear fuel services,
Florida Power does not currently expect to have difficulty obtaining uranium
oxide concentrate and the services necessary for its conversion, enrichment and
fabrication into nuclear fuel.
Purchased Power
Florida Power, along with other Florida utilities, buys and sells economy power
through the Florida energy brokering system. Florida Power also purchases 1,304
MW of firm power under a variety of purchase power agreements. As of December
31, 2001, Florida Power had long-term contracts for the purchase of about 460 MW
of purchased power with other investor-owned utilities, including a contract
with The Southern Company for approximately 400 MW. Florida Power also purchased
831 megawatts of its total capacity from certain qualifying facilities (QFs).
The capacity currently available from QFs represents about 10% of Florida
Power's total installed system capacity.
COMPETITION
- -----------
Electric Industry Restructuring
Florida Power continues to monitor progress toward a more competitive
environment and has actively participated in regulatory reform deliberations in
Florida. Movement toward deregulation in this state has been affected by recent
developments related to deregulation of the electric industry in California.
On January 31, 2001, the Florida 2020 Study Commission voted to forward a
"proposed outline for wholesale restructuring" to the Florida legislature for
its consideration in the 2001 session. The wholesale restructuring outline is
intended to facilitate the evolution of a more robust wholesale marketplace in
Florida. On December 11, 2001, the study commission issued its final report. The
report covered a number of issues with recommendations in the areas of wholesale
competition and reliability, efficiency, transmission infrastructure,
environmental issues and new technologies. One key recommendation related to
wholesale competition & reliability is to permit the transfer or sale of
existing generation assets as follows:
. Sales and transfers of generation assets and the related timing are
discretionary on the part of the investor-owned utility on a
plant-by-plant basis.
. Transfers of generation assets are recorded at book value.
. Load-serving entities (LSE's) have the right to a 6-year cost based
transition contract on all transferred capacity with unilateral
cancellation rights and a share of the profits from off-system sales.
. Gains on sales of existing plants or those transferred and still under
transition contracts must be shared 50/50 with customers.
. Losses on sales must be absorbed fully by shareholder.
. New units under construction and included in the company's 10-Year
Site Plan are subject to 6-year transition contract requirement but
not the gain/loss sharing.
. The FPSC has the authority to review LSE's decision to terminate
transition contracts, including prior to actual termination.
Although the Company believes that the current system of regulation in Florida
is working well, Florida Power has supported the study commission's efforts.
While the Company does not see any compelling reason to change, the study
commission's proposal is generally consistent with principles the Company
believes any sound restructuring plan should adhere to if the state does decide
to restructure.
20
<PAGE>
The Florida legislature did not take any action on the proposed outline or final
report during the 2001 session. There is no way for the Company to know what
restructuring legislation will be enacted or if the Company would be able to
support it in its final form.
Regional Transmission Organizations
In October 2000, Florida Power, along with Florida Power & Light Company and
Tampa Electric Company filed with FERC an application for approval of a regional
transmission organization, or RTO, for peninsular Florida, currently named
GridFlorida. On March 28, 2001, FERC issued an order provisionally granting
GridFlorida RTO status and directing the GridFlorida applicants to make certain
changes in the RTO documents and to file such changes within 60 days. On May 29,
2001, the GridFlorida applicants made the compliance filing as directed by FERC,
but FERC has not yet issued an order on that compliance filing.
See PART II, Item 7, "Other Matters," for a discussion of current developments
of GridFlorida RTO.
Merchant Plants
In August 1998, Duke Energy filed a petition to build Florida's first merchant
power plant, a 514-megawatt facility to be located in Volusia County, Florida.
The plant would provide 30 megawatts of energy to the Utilities Commission of
the City of New Smyrna Beach and the remaining capacity would be available for
wholesale sales.
In a move Florida Power believes is contrary to existing state law, the Florida
Public Service Commission (FPSC) granted Duke Energy's petition. Florida Power
and other Florida utilities filed an appeal of the FPSC's decision with the
Florida Supreme Court. In April 2000, the Florida Supreme Court ruled in favor
of Florida Power and other utilities and reversed the FPSC's order. In December
2000, Duke Energy filed a petition for certiorari with the U.S. Supreme Court.
On March 5, 2001, the U.S. Supreme Court denied Duke Energy's petition for
certiorari.
Franchise Agreements
By virtue of municipal legislation, Florida Power holds franchises with varying
expiration dates in most of the municipalities in which it distributes electric
energy. However, Florida Power does serve within a number of municipalities and
in all its unincorporated areas without existing franchise ordinances. The
general effect of franchises is to provide for the manner in which Florida Power
occupies rights-of-way in incorporated areas of municipalities for the purpose
of constructing, operating and maintaining an energy transmission and
distribution system.
Approximately 39% of Florida Power's total utility revenues for 2001 were from
the incorporated areas of the 109 municipalities that had franchise ordinances
during the year. Of the 18 franchises that expired during 2001, four
municipalities have not yet renewed.
A new franchise ordinance was enacted during January 2002 with a municipality
that did not previously have a franchise with Florida Power bringing the current
number of existing franchises to 106. All but 17 of the existing franchises
cover a 30-year period from the date enacted. The exceptions are 15 franchises
each with a term of 10 years and expiring between 2011 and 2012; one 30-year
franchise that was extended in 1999 for five years expiring in 2005; and one
franchise with a term of 20 years expiring in 2020. Of the 106 franchises, 11
expire during 2002, 34 expire between January 1, 2003 and December 31, 2012 and
61 expire between January 1, 2013 and December 31, 2031.
Ongoing negotiations are taking place with the municipalities to reach agreement
on franchise terms and to enact new franchise ordinances.
Stranded Costs
An important 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 QFs.
Thus far, all states that have passed restructuring legislation have provided
for the opportunity to recover a substantial portion of stranded costs.
Assessing the amount of stranded costs for a utility requires various
assumptions about future market conditions including the future price of
electricity. For Florida Power, the single largest stranded cost exposure is its
commitment to QFs. Since 1996, Florida Power has been seeking ways to address
the impact of escalating payments from contracts it was obligated to sign under
provisions of PURPA. These efforts have resulted in Florida Power successfully
mitigating, through buy-outs and buy-downs of these contracts, more than 25
percent of its purchased power commitments to QFs.
21
<PAGE>
REGULATORY MATTERS
- ------------------
General
Florida Power is subject to the jurisdiction of the FPSC with respect to, among
other things, retail rates and issuance of securities. In addition, Florida
Power is subject to regulation by FERC with respect to transmission and sales of
wholesale power, accounting and certain other matters. The underlying concept of
utility ratemaking is to set rates at a level that allows the utility to collect
revenues equal to its cost of providing service plus a reasonable rate of return
on its equity. Increased competition, as a result of industry restructuring, may
affect the ratemaking process.
Electric Retail Rates
The FPSC authorizes retail "base rates" that are designed to provide a utility
with the opportunity to earn a specific rate of return on its "rate base", or
average investment in utility plant. These rates are intended to cover all
reasonable and prudent expenses of utility operations and to provide investors
with a fair rate of return. The FPSC has authorized a return on equity range for
Florida Power of 11-13% and its retail base rates are based on the mid-point of
that range - 12%.
Florida Power previously operated under an agreement committing several parties
not to seek any reduction in its base rates or authorized return on equity. That
agreement expired on June 30, 2001. During 2001, the FPSC required Florida Power
to submit minimum filing requirements, based on a 2002 projected test year, to
initiate a rate proceeding regarding its future base rates.
On September 14, 2001, Florida Power submitted its required rate filing,
including its revenue requirements and supporting testimony. Florida Power filed
supplemental minimum filing requirements and testimony on November 15, 2001.
Hearings were scheduled to begin on March 20, 2002, but were postponed to
accommodate pending settlement negotiations between the parties.
On March 27, 2002, the parties entered into a Stipulation and Settlement
Agreement (the Agreement) related to retail rate matters. The Agreement is to be
effective from May 1, 2002 through 2005; provided, however, that if Florida
Power's base rate earnings fall below a 10% return on equity, Florida Power may
petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from
the sale of electricity by $125 million annually through 2005. The Agreement
also provides that Florida Power will operate under a Revenue Sharing Incentive
Plan (the Plan) that establishes revenue caps and sharing thresholds for the
years 2002 through 2005. The Plan provides that retail base rate revenues
between the sharing thresholds and the retail base rate revenue caps will be
divided into two shares - a 1/3 share to be received by Florida Power's
shareholders, and a 2/3 share to be refunded to Florida Power's retail
customers; provided, however, that for the year 2002 only, the refund to
customers will be limited to 67.1% of the 2/3 customer share. The retail base
rate revenue sharing threshold amounts for 2002, 2003, 2004 and 2005 will be
$1,296 million, $1,333 million, $1,370 million and $1,407 million, respectively.
The Plan also provides that all retail base rate revenues above the retail base
rate revenue caps established for the years 2003, 2004 and 2005 will be refunded
to retail customers on an annual basis. For 2002, the refund to customers will
be limited to 67.1% of the retail base rate revenues that exceed the 2002 cap.
The retail base revenue caps for 2002, 2003, 2004 and 2005 will be $1,356
million, $1,393 million, $1,430 million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of Florida
Power's Hines Unit 2 and continuing through December 31, 2005, Florida Power
will be allowed to recover through the fuel cost recovery clause a return on
average investment and depreciation expense for Hines Unit 2, to the extent such
costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a mid-course
correction of its fuel cost recovery clause to reduce the fuel factor by $50
million for the remainder of 2002. The fuel cost recovery clause will operate as
it normally does, including, but not limited to any additional mid-course
adjustments that may become necessary, and the calculation of true-ups to actual
fuel clause expenses.
During the term of the Agreement, Florida Power will suspend accruals on its
reserves for nuclear decommissioning and fossil dismantlement. Additionally, for
each calendar year during the term of the Agreement, Florida Power
22
<PAGE>
will record a $62.5 million depreciation expense reduction, and may, at its
option, record up to an equal annual amount as an offsetting accelerated
depreciation expense. In addition, Florida Power 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, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan and
expects to achieve a 20% improvement in its annual System Average Interruption
Duration Index by no later than 2004. If this improvement level is not achieved
for calendar years 2004 or 2005, Florida Power will provide a refund of $3
million for each year the level is not achieved to 10% of its total retail
customers served by its worst performing distribution feeder lines.
The Agreement also provides that Florida Power will refund to customers $35
million of the $98 million in interim revenues Florida Power has collected
subject to refund since March 13, 2001. No other interim revenues that were
collected during that period will continue to be held subject to refund.
The Agreement was filed with the FPSC for approval on March 27, 2002. If the
FPSC approves the Agreement, the new rates will take effect May 1, 2002.
Progress Energy cannot predict the outcome of this matter.
Fuel Cost Recovery
Florida Power's operating costs not covered by the utility's base rates include
increases in fuel, purchased power and energy conservation expenses. The state
commission allows electric utilities to recover certain of these costs through
various cost recovery clauses, to the extent the respective commission
determines in an annual hearing that such costs are prudent. Costs recovered by
Florida Power include fuel costs, purchased power costs and energy conservation
expenses.
The state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
- ---------------
Florida Power has one nuclear generating plant, Crystal River Unit No. 3 (CR3),
which is subject to regulation by the NRC. The NRC's jurisdiction encompasses
broad supervisory and regulatory powers over the construction and operation of
nuclear reactors, including matters of health and safety, antitrust
considerations and environmental impact. Florida Power has a license to operate
the nuclear plant through December 3, 2016. Florida Power currently has a 91.8%
ownership interest in CR3.
Spent nuclear fuel is stored at CR3 pending disposal under a contract with the
DOE. At the present time, Florida Power has facilities on site for the temporary
storage of spent nuclear fuel generated through the year 2011. Florida Power
expanded the capacity of its facilities on site in 2001, after obtaining
regulatory approval, to allow for the temporary storage of spent nuclear fuel
generated through the end of the license in 2016.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking of
Reactor Vessel Head Penetration Nozzles," requesting that all pressurized water
reactors (PWR) provide their plans for inspecting the reactor vessel head for
the conditions described in the bulletin. While performing this inspection,
FirstEnergy Corp.'s Davis Besse plant in Ohio found three penetrations with
evidence of leakage and further evidence of some wastage of the reactor vessel
head around two of these penetrations. As a result of finding the wastage of the
vessel head, the NRC issued Bulletin 2002-01, requesting licensees to assess
previous inspections of the reactor head and determine the potential for the
existence of conditions similar to that found at the Davis Besse plant.
Florida Power's CR3 has completed the inspections requested by Bulletin 2001-01.
Any indications of leakage have been inspected and repaired, and no wastage of
the reactor vessel head has been observed. Based on these inspections, responses
to Bulletin 2002-01 are being prepared. Florida Power does not anticipate any
adverse impact from this regulatory action.
Enrichment Facilities Decontamination
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<PAGE>
Florida Power and a number of other utilities are involved in litigation against
the United States challenging certain retroactive assessments imposed by the
federal government on domestic nuclear power companies to fund the
decommissioning and decontamination of the government's uranium enrichment
facilities.
On November 1, 1996, Florida Power filed suit against the U.S. Government in the
U.S. Court of Claims alleging breach of contract and illegal taking of property
without just compensation. The suit arises out of several contracts under which
the government provided uranium enrichment services at fixed prices. After
Florida Power paid for all services provided under the contracts, the
government, through federal legislation enacted in 1992, imposed a retroactive
price increase in order to fund the decontamination and decommissioning of the
government's gaseous diffusion uranium enrichment facilities. The government is
collecting this increase through an annual "special assessment" levied upon all
utilities that had enrichment services contracts with the government. Collection
of the special assessments began in 1992 and is scheduled to continue for a
fifteen-year period.
To date, Florida Power has paid more than $18 million in special assessments,
including its co-owner's share of approximately $1.5 million, and if continued
throughout the anticipated fifteen-year life, the special assessments would
increase the cost of Florida Power's contracts by more than $23 million. Florida
Power seeks an order declaring that all such special assessments are unlawful,
and an injunction prohibiting the government from collecting future special
assessments and damages.
In June 1998, Florida Power, Consolidated Edison Co. and 15 other utilities
filed an action for declaratory judgement against the United States in the
Southern District Court of New York, challenging the constitutionality of the
$2.25 billion retroactive assessment imposed by the federal government on
domestic nuclear power companies to fund the decommissioning and decontamination
of the government's uranium enrichment facilities. In August 1998, the utilities
filed an amended complaint adding several additional utilities as plaintiffs.
In February 1999, the court granted Florida Power's motion to stay the Claims
Court action, pending resolution of the District Court case. In April 1999, the
District Court ruled that it had subject matter jurisdiction, and denied the
government's motion to transfer the action to the Claims Court. The government
appealed the decision to the U.S. Court of Appeals for the Federal Circuit,
which ultimately reversed the District Court's denial of the motion to transfer.
The matter was stayed pending the utilities' petition for a writ of certiorari
to the Supreme Court. The Supreme Court denied the utilities' petition for
certiorari on December 3, 2001. Consequently, on December 22, 2001, the Federal
Circuit issued a mandate remanding the case to the District Court with
instructions to transfer the case to the Court of Federal Claims. The Company
cannot predict the outcome of this matter.
PROGRESS VENTURES
- -----------------
GENERAL
- -------
The Progress Ventures business unit was created in 2000 to manage Progress
Energy's wholesale energy marketing and trading, merchant generation and fuel
properties, as well as an ocean barge partnership. The operations of the
Progress Ventures business unit can be broken down into three key areas: 1) fuel
extraction, manufacturing and delivery; 2) merchant generation ownership; and 3)
energy marketing and trading.
FUEL EXTRACTION, MANUFACTURING AND DELIVERY
- -------------------------------------------
The Progress Ventures business unit owns an array of assets that produce,
transport and deliver fuel for the open market. The Progress Ventures business
unit has subsidiaries that mine coal and others that produce synthetic
coal-based fuel, a chemically changed product made from waste coal and coal
byproducts. Because this process is accomplished through a significant chemical
reaction, the resulting product has been classified as a synthetic fuel within
the meaning of Section 29 of the Internal Revenue Code. Sales of synthetic fuel
therefore qualify for tax credits. See Progress Energy's PART II, ITEM 7, "Other
Matters" for a discussion of the synthetic fuel tax credits.
The combined assets of Progress Ventures which are involved in fuel extraction,
manufacturing and delivery include:
. Three coal-mining complexes, producing about 3 million tons per year;
. Seven synthetic fuel plants capable of producing 10 to 15 million tons
per year;
. Natural gas properties in Colorado producing about 5 billion cubic
feet per year;
. Six terminals on the Ohio River and its tributaries, part of the
trucking, rail and barge network for coal delivery;
. Part-ownership in a barge operation that moves coal from the mouth of
the Mississippi River to the Crystal River facility in Florida.
24
<PAGE>
MERCHANT GENERATION OWNERSHIP
- -----------------------------
Merchant generation represents power plants whose capacity and energy are sold
on the wholesale market outside the realm of retail regulation. A cornerstone of
Progress Ventures' business plan is to own a portfolio of approximately 3,100 MW
of merchant generation capacity by 2003. Much of this portfolio will be built by
Progress Ventures. In addition, Progress Ventures is pursuing acquisitions and
non-traditional ownership opportunities.
Progress Ventures had approximately 315 MW of merchant generation in commercial
operation as of December 31, 2001. Construction, acquisition and transfers of
generating assets from CP&L will increase this to approximately 3,100 MW over
the next two years. See Progress Energy's PART I, ITEM 2, "Properties" for
additional information on these planned additions. Progress Ventures has
flexible plans around an additional 2,800 MW's subsequent to 2003. A newly
established Progress Ventures function carefully examines competitive market
data to determine the best locations for future merchant plants, including those
planned subsequent to 2003.
ENERGY MARKETING AND TRADING
- ----------------------------
Within this business function, the energy produced by the merchant plants as
well as some capacity produced by the utility is sold under term contracts and
in the spot market. This area is divided into two departments: Energy Trading
and Term Marketing. Energy Trading markets and sells short-term contracts for
power while Term Marketing markets and sells long-term contracts. Currently,
Progress Ventures manages 5,300 MW of wholesale power contracts that primarily
include those for CP&L and Florida Power.
In addition to power contracts, this business area also purchases fuel for both
utility and merchant generation, and trades other sources of energy, such as
natural gas, oil and, in the future, coal. Progress Ventures also uses financial
instruments to manage the risks associated with fluctuating commodity prices and
increase the value of the Company's power generation assets.
COMPETITION
- -----------
Progress Ventures does not operate in the same environment as regulated
utilities. It operates specifically on the wholesale market, which means
competition is its primary driver. Progress Venture's synthetic fuel operations,
coal operations and merchant generation plants compete in the eastern United
States utility and industrial coal markets. Factors contributing to the success
in these markets include a competitive cost structure and strategic locations.
See PART II, ITEM 7, "Other Matters" for a discussion of risks associated with
synthetic fuel tax credits. There are, however, numerous competitors in each of
these markets, although no one competitor is dominant in any industry. The
business of Progress Ventures, taken as a whole, is not subject to significant
seasonal fluctuation.
RAIL SERVICES
- -------------
The largest component of Rail Services is led by Progress Rail Services
Corporation (Progress Rail). Progress Rail is one of the largest integrated and
diversified suppliers of railroad and transit system products and services in
North America and is headquartered in Albertville, Alabama. Rail Services'
principal business functions include the Mechanical Group, Rail and Trackwork
Group, and Recycling Group.
The Mechanical Group is primarily focused on railroad rolling stock that
includes freight cars, transit cars and locomotives, the repair and maintenance
of these units, and the manufacturing or reconditioning of major components for
these units. The Rail and Trackwork Group focuses on rail and other track
components, the infrastructure which supports the operation of rolling stock, as
well as the equipment used in maintaining the railroad infrastructure and
right-of-way. The Recycling Group supports the Mechanical and Rail and Trackwork
Groups through its reclamation of reconditionable material. In addition, the
Recycling Group is a major supplier of recyclable scrap metal to North American
steel mills and foundries through its processing locations as well as its scrap
brokerage operations.
Rail Services' key railroad industry customers are Class 1 railroads, regional
and shortline railroads, major North American transit systems, major railcar and
locomotive builders, and major railcar lessors. The U.S. operations are located
in 26 states and include further geographic coverage through mobile crews on a
selected basis. This coverage allows for Rail Services' customer base to be
dispersed throughout the U.S., Canada and Mexico.
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OTHER
- -----
GENERAL
- -------
The Other segment primarily includes the business of NCNG, SRS, Progress Telecom
and Caronet.
NCNG
- ----
General
NCNG transports, distributes and sells natural gas to over 107,400 residential
customers, over 14,300 commercial and agricultural customers and 477 industrial
and electric utility customers located in 110 towns and cities, primarily in
eastern and south central North Carolina. NCNG also sells and transports natural
gas to four municipal gas distribution systems that serve over 53,900 end users.
Natural Gas operations are subject to the rules and regulations of the NCUC.
Natural Gas Supply
NCNG has long-term firm gas supply contracts with major producers and national
natural gas marketers. During 2001, NCNG purchased 5,517,725 dekatherms (dt) of
natural gas under its firm sales contracts with Transcontinental Gas Pipeline
Corporation (Transco). NCNG also purchased 17,052,446 dt in the spot market or
under long-term contracts with producers or natural gas marketers. Additionally,
NCNG transported 29,872,334 dt of customer-owned gas in 2001. The outlook for
natural gas supplies in NCNG's service area remains favorable, and many sources
of gas are available on a firm basis.
Competition
The natural gas industry continues to evolve into a more competitive
environment. NCNG has competed successfully with other forms of energy such as
electricity, residual fuel, distillate fuel oil, propane and, to a lesser
extent, coal. The principal competitive considerations have been price and
accessibility. With the exception of four municipalities that operate municipal
gas distribution systems within its service territory, NCNG is the sole
distributor of natural gas in our franchised service territory.
Currently, NCNG's residential and commercial customers receive services under a
bundled rate, which includes charges for both the cost of gas and its delivery
to the customer. Unbundling of the services to commercial and residential
customers could increase competition for commodity sales services, but not for
the distribution of natural gas. Since NCNG does not earn any margin or income
from the commodity sale of natural gas, separating the cost of gas from the cost
of its delivery will not impact the operations. NCNG does not expect the NCUC to
require further unbundling in the near future. NCNG has adopted a policy that
requires that it have a balanced gas supply portfolio that provides security of
supply at the lowest reasonable cost, as determined by the NCUC in all of the
prior annual prudency reviews.
During 2001, approximately 55% of total throughput on NCNG's system was sold to
customers having alternative fuel usage capabilities under interruptible rates,
which allows NCNG to request that these customers discontinue gas service during
periods of heavy demand so that NCNG is able to maintain its obligation to serve
its firm market demand (residential and commercial). However, the purchased gas
adjustment rider, which was part of NCNG's tariffs approved by the NCUC, allows
NCNG to negotiate rates lower than the filed tariff rates and to recover the
lost margin from the other core market customers to encourage industrial
customers to remain on the system when the price of their alternative fuel is
lower than the gas tariff rate. The purchased gas adjustment rider also sets
forth NCNG's filing requirements with the NCUC, enables it to negotiate rates
with customers and establishes the procedures governing the monthly and annual
review of gas costs and corresponding rate changes.
Franchises
NCNG holds a certificate of public convenience and necessity granted by the NCUC
to provide service to NCNG's current service area. Under North Carolina law, no
company may construct or operate properties for the sale or distribution of
natural gas without such a certificate, except that no certificate is required
for construction in the ordinary course of business or for construction into
territory contiguous to that already occupied by a company and not receiving
similar service from another utility.
NCNG has nonexclusive franchises from 70 municipalities in which NCNG
distributes natural gas. The expiration dates of those franchises that have
specific expiration provisions range from 2004 to 2020. As of February 28, 2002,
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<PAGE>
NCNG is negotiating franchise agreements with two new towns, City of Whiteville
and Village of Pinehurst. NCNG expects all negotiations to result in 10 or
20-year agreements. In the event that these franchise agreements cannot be
negotiated, NCNG does not believe that it will experience any material adverse
effect. None of the remaining franchise agreements are scheduled to expire
within the next two years. The franchises are substantially uniform in nature.
They contain no restrictions of a materially burdensome nature and are adequate
for NCNG's business. In addition, NCNG serves 36 communities from which no
franchises are required.
Regulatory Matters
The NCUC regulates NCNG's rates, service area, adequacy of service, safety
standards, acquisition, extension and abandonment of facilities, accounting and
sales of securities. NCNG operates only in North Carolina and is not subject to
federal regulation as a "natural gas company" under the Natural Gas Act.
Retail Rates
On October 27, 1995, the NCUC issued an order that provides for a rate of return
of 10.09%, but did not state separately the rate of return on common equity or
the capital structure used to calculate revenue requirements. The order
established several new rate schedules, including an economic development rate
to assist in attracting new industry to NCNG's service area and a rate to
provide standby, on-peak gas supply service to industrial and other customers
whose gas service would otherwise be interrupted.
In conjunction with CP&L's acquisition of NCNG on July 15, 1999, NCNG signed a
joint stipulation agreement with the NCUC in which NCNG agreed to cap margin
rates for gas sales and transportation services, with limited exceptions,
through November 1, 2003. The Company believes that this agreement will not have
a material adverse effect on the results of operations, financial condition, or
cash flows. In February 2002, NCNG filed a general rate case with the NCUC
requesting an annual rate increase of $47.6 million, based upon its completion
of major expansion projects. Progress Energy cannot predict the final outcome of
this matter.
Expansion Projects
In March 2001, NCNG completed an 84-mile, 30-inch natural gas pipeline, named
the Sandhills Pipeline, which extends from Iredell County to Richmond County in
North Carolina. This pipeline cost approximately $100 million and will primarily
be used to transport natural gas to an electric generating plant currently under
construction in Richmond County by CP&L, an affiliate of NCNG.
In October 1999, CP&L and the Albemarle Pamlico Economic Development Corporation
(APEC) announced their intention to build an 850-mile, $197.5 million, natural
gas transmission and distribution system to the 14 currently unserved counties
in eastern North Carolina that were previously franchised to NCNG, as discussed
above. In furtherance of this project, Progress Energy and APEC formed Eastern
North Carolina Natural Gas Co. (EasternNC, formerly reported as ENCNG). Progress
Energy and APEC are joint owners of EasternNC, which is a public utility subject
to the rules and regulations of the NCUC. EasternNC contracted with CP&L to
construct, operate and maintain both the transmission and distribution systems.
EasternNC contracted with APEC to provide various services as well, including
but not limited to, managing all municipal and county franchise issues,
marketing and economic development and ensuring that the new facilities are
built in the most advantageous locations to promote development of the economic
base in the region. In conjunction with this project, EasternNC filed a request
with the NCUC for $186 million of a $200 million state bond package established
for natural gas infrastructure to pay for the portion of the project that likely
could not be recovered from future gas customers through rates. On June 15,
2000, the NCUC issued an order awarding EasternNC an exclusive franchise to all
14 counties and, in a further order issued on July 12, 2000, granted $38.7
million in state bond funding for phase one of the project. Phase one, which
will cost a total of $50.5 million, will bring gas service to 6 of the 14
counties. By order issued June 7, 2001 the NCUC approved construction of phases
2-7 of the project which addresses the remaining 8 counties and awarded
EasternNC an additional $149.6 million to finance the construction of the
facilities associated with these phases. EasternNC has begun construction of
phase one of the project and expects to complete construction of phase one in
the summer of 2002. EasternNC has also begun marketing natural gas service to
prospective customers in phase one. The schedule for the remaining phases calls
for construction of phase two to begin in the summer of 2002, and for all phases
to be completed by the summer of 2004.
Progress Energy has agreed to fund a portion of the project, which is currently
estimated to be approximately $22 million.
27
<PAGE>
SRS
- ---
SRS offers a comprehensive suite of innovative solutions for energy management
and building automation. SRS' portfolio of systems and services provides clients
with tools to integrate and centrally manage their energy usage and facility
needs. SRS delivers solutions for commercial, industrial, education and
government clients. Progress Energy is refocusing the SRS business on energy
services in the southeastern states.
PROGRESS TELECOM AND CARONET
- ----------------------------
Progress Telecom has data fiber network transport capabilities that stretch from
New York to Miami, Florida, with gateways to Latin America and conducts
primarily a carrier's carrier business. Progress Telecom markets wholesale
fiber-optic-based capacity service in the Eastern United States to long-distance
carriers, internet service providers and other telecommunications companies.
Progress Telecom also markets wireless structure attachments to wireless
communication companies and governmental entities. Caronet, Inc. (Caronet)
serves the telecommunications industry by providing fiber-optic
telecommunications services. As of December 31, 2001, Progress Telecom owned and
managed approximately 7,200 route miles and more than 130,000 fiber miles of
fiber optic cable, which includes Caronet. In December 2001, Progress Telecom
Corporation (Telecom) was formed. Assets, liabilities, and existing contracts of
Progress Telecom and Caronet will be transferred to Telecom upon regulatory
approval. Regulatory approval is expected during the first half of 2002.
Progress Telecom and Caronet compete with other providers of fiber-optic
telecommunications services, including local exchange carriers and competitive
access providers, in the Eastern United States.
28
<PAGE>
OPERATING STATISTICS - PROGRESS ENERGY
- --------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31
2001 2000 (e) 1999 1998 1997
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - Steam 48,732 31,132 28,260 27,576 25,545
Nuclear 27,300 23,857 22,451 22,014 21,690
Hydro 245 441 520 790 799
Combustion Turbines 6,644 1,337 435 386 189
Purchased 14,469 5,724 5,132 5,675 6,318
---------- ---------- ---------- ---------- ----------
Total energy supply (Company share) 97,390 62,491 56,798 56,441 54,541
Jointly-owned share (a) 4,883 4,505 4,353 4,349 4,101
---------- ---------- ---------- ---------- ----------
Total system energy supply 102,273 66,996 61,151 60,790 58,642
========== ========== ========== ========== ==========
Average fuel cost (per million BTU)
Fossil $ 2.46 $ 1.96 $ 1.75 $ 1.71 $ 1.75
Nuclear fuel $ 0.45 $ 0.45 $ 0.46 $ 0.46 $ 0.46
All fuels $ 1.77 $ 1.30 $ 1.16 $ 1.14 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 31,976 15,365 13,348 13,207 12,348
Commercial 23,033 12,221 11,068 10,646 9,910
Industrial 17,204 14,762 14,568 14,899 14,958
Other Retail 4,149 1,626 1,359 1,357 1,281
Wholesale 17,715 15,012 14,526 14,461 13,875
Unbilled (1,045) 1,098 (110) (94) 393
---------- ---------- ---------- ---------- ----------
Total energy sales 93,032 60,084 54,759 54,476 52,765
Company uses and losses 3,478 2,286 2,039 1,964 1,776
---------- ---------- ---------- ---------- ----------
Total energy requirements 96,510 62,370 56,798 56,440 54,541
========== ========== ========== ========== ==========
Natural gas sales (millions of dt) (b) 52,442 57,026 27,564 -- --
Electric revenues (in thousands)
Retail $5,461,469 $2,799,422 $2,530,562 $2,536,693 $2,428,650
Wholesale 922,719 664,847 556,079 528,253 507,720
Miscellaneous revenue 172,373 85,552 59,517 65,099 87,719
---------- ---------- ---------- ---------- ----------
Total electric revenues $6,556,561 $3,549,821 $3,146,158 $3,130,045 $3,024,089
========== ========== ========== ========== ==========
Peak demand of firm load (thousands of kW)
System (c) 19,166 18,874 10,948 10,529 10,030
Company 18,564 18,272 10,344 9,875 9,344
Total capability at year-end (thousands of kW)
Fossil plants 16,141 14,902 6,891 6,571 6,571
Nuclear plants 4,008 4,008 3,174 3,174 3,064
Hydro plants 218 218 218 218 218
Purchased 2,890 2,278 1,088 1,538 1,588
---------- ---------- ---------- ---------- ----------
Total system capability 23,257 21,406 11,371 11,501 11,441
Less jointly-owned portion (d) 668 662 593 593 690
---------- ---------- ---------- ---------- ----------
Total Company capability 22,589 20,744 10,778 10,908 10,751
========== ========== ========== ========== ==========
</TABLE>
(a) Represents co-owner's share of the energy supplied from the five generating
facilities that are jointly owned.
(b) Reflects the acquisition of NCNG on July 15, 1999
(c) For 2001 and 2000, this represents the combined summer non-coincident
system net peaks for CP&L and Florida Power.
(d) Net of the Company's purchases from jointly-owned plants.
(e) Includes information for Florida Power since November 30, 2000, the date of
acquisition.
29
<PAGE>
OPERATING STATISTICS - CAROLINA POWER & LIGHT COMPANY
- -----------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31
2001 2000 1999 1998 1997
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - Steam 27,913 29,520 28,260 27,576 25,545
Nuclear 21,321 23,275 22,451 22,014 21,690
Hydro 245 441 520 790 799
Combustion Turbines 802 733 435 386 189
Purchased 5,296 4,878 5,132 5,675 6,318
---------- ---------- ---------- ---------- ----------
Total energy supply (Company share) 55,577 58,847 56,798 56,441 54,541
Power Agency share (a) 4,348 4,505 4,353 4,349 4,101
---------- ---------- ---------- ---------- ----------
Total system energy supply 59,925 63,352 61,151 60,790 58,642
========== ========== ========== ========== ==========
Average fuel cost (per million BTU)
Fossil $ 1.91 $ 1.83 $ 1.75 $ 1.71 $ 1.75
Nuclear fuel $ 0.44 $ 0.45 $ 0.46 $ 0.46 $ 0.46
All fuels $ 1.26 $ 1.21 $ 1.16 $ 1.14 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 14,372 14,091 13,348 13,207 12,348
Commercial 11,972 11,432 11,068 10,646 9,910
Industrial 13,332 14,446 14,568 14,899 14,958
Other Retail 1,423 1,423 1,359 1,357 1,281
Wholesale 12,996 14,582 14,526 14,461 13,875
Unbilled (534) 679 (110) (94) 393
---------- ---------- ---------- ---------- ----------
Total energy sales 53,561 56,653 54,759 54,476 52,765
Company uses and losses 2,017 2,194 2,039 1,964 1,776
---------- ---------- ---------- ---------- ----------
Total energy requirements 55,578 58,847 56,798 56,440 54,541
========== ========== ========== ========== ==========
Electric revenues (in thousands)
Retail $2,665,857 $2,608,727 $2,530,562 $2,536,693 $2,428,650
Wholesale 634,009 577,279 556,079 528,253 507,720
Miscellaneous revenue 43,854 122,209 59,518 65,099 87,719
---------- ---------- ---------- ---------- ----------
Total electric revenues $3,343,720 $3,308,215 $3,146,159 $3,130,045 $3,024,089
========== ========== ========== ========== ==========
Peak demand of firm load (thousands of kW)
System 11,376 11,157 10,948 10,529 10,030
Company 10,774 10,555 10,344 9,875 9,344
Total capability at year-end (thousands of kW)
Fossil plants (c) 8,648 7,569 6,891 6,571 6,571
Nuclear plants 3,174 3,174 3,174 3,174 3,064
Hydro plants 218 218 218 218 218
Purchased 1,586 978 1,088 1,538 1,588
---------- ---------- ---------- ---------- ----------
Total system capability 13,626 11,939 11,371 11,501 11,441
Less Power Agency-owned portion (b) 599 593 593 593 690
---------- ---------- ---------- ---------- ----------
Total Company capability 13,027 11,346 10,778 10,908 10,751
========== ========== ========== ========== ==========
</TABLE>
(a) Represents Power Agency's share of the energy supplied from the four
generating facilities that are jointly owned.
(b) Net of CP&L's purchases from Power Agency.
(c) Includes Rowan units that were transferred to Progress Ventures in February
2002.
30
<PAGE>
ITEM 2. PROPERTIES
- ------------------
The Company believes that its physical properties and those of its subsidiaries
are adequate to carry on its and their businesses as currently conducted. The
Company and its subsidiaries maintain property insurance against loss or damage
by fire or other perils to the extent that such property is usually insured.
ELECTRIC - CP&L
- ---------------
As of December 31, 2001, CP&L's nineteen generating plants represent a flexible
mix of fossil, nuclear and hydroelectric resources in addition to combustion
turbines and combined cycle units, with a total generating capacity (including
Power Agency's share) of 12,040 megawatts (MW). CP&L's strategic geographic
location facilitates purchases and sales of power with many other electric
utilities, allowing CP&L to serve its customers more economically and reliably.
At December 31, 2001, CP&L had the following generating facilities:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
Summer Net
No. of Capability (a)
Facility Location Units In-Service Date Fuel (in MW)
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
STEAM TURBINES
Asheville Skyland, N.C. 2 1964-1971 Coal 392
Cape Fear Moncure, N.C. 2 1956-1958 Coal 316
Lee Goldsboro, N.C. 3 1952-1962 Coal 407
Mayo Roxboro, N.C. 1 1983 Coal 745(b)
Robinson Hartsville, S.C. 1 1960 Coal 174
Roxboro Roxboro, N.C. 4 1966-1980 Coal 2,462(b)
Sutton Wilmington, N.C. 3 1954-1972 Coal 613
Weatherspoon Lumberton, N.C. 3 1949-1952 Coal 176
-- ------
Total 19 5,285
COMBINED CYCLE
Cape Fear Moncure, N.C. 2 1969 Oil 84
-- ------
Total 2 84
COMBUSTION TURBINES
Asheville Skyland, N.C. 2 1999-2000 Gas/Oil 330
Blewett Lilesville, N.C. 4 1971 Oil 52
Darlington Hartsville, S.C. 13 1974-1997 Gas/Oil 812
Lee Goldsboro, N.C. 4 1968-1971 Oil 91
Morehead City Morehead City, N.C. 1 1968 Oil 15
Richmond Hamlet, N.C. 4 2001 Gas/Oil 620
Robinson Hartsville, S.C. 1 1968 Gas/Oil 15
Rowan Salisbury, N.C. 3 2001 Gas/Oil 459(c)
Roxboro Roxboro, N.C. 1 1968 Oil 15
Sutton Wilmington, N.C. 3 1968-1969 Oil 64
Wayne County Goldsboro, N.C. 4 2000 Gas/Oil 668
Weatherspoon Lumberton, N.C. 4 1970-1971 Oil 138
-- ------
Total 44 3,279
NUCLEAR
Brunswick Southport, N.C. 2 1975-1977 Uranium 1,631(b)
Harris New Hill, N.C. 1 1987 Uranium 860(b)(d)
Robinson Hartsville, S.C. 1 1971 Uranium 683
-- ------
Total 4 3,174
HYDRO
Blewett Lilesville, N.C. 6 1912 Water 22
Marshall Marshall, N.C. 2 1910 Water 5
Tillery Mount Gilead, N.C. 4 1928-1960 Water 86
Walters Waterville, N.C. 3 1930 Water 105
-- ------
Total 15 218
TOTAL 84 12,040
- -----------------------------------------------------------------------------------------------
</TABLE>
(a) Represents CP&L's net summer peak rating, gross of co-ownership interest in
plant capacity
(b) Facilities are jointly owned by CP&L and Power Agency, and the capacities
shown include Power Agency's share
(c) This facility was transferred from CP&L to Progress Ventures in February
2002
(d) On January 1, 2002, a successful power uprate increased the summer net
capability of this facility to 900 MW
31
<PAGE>
As of December 31, 2001, including both the total generating capacity of 12,040
MW and the total firm contracts for purchased power of approximately 1,586 MW,
CP&L had total capacity resources of approximately 13,626 MW.
The Power Agency has acquired undivided ownership interests of 18.33% in
Brunswick Unit Nos. 1 and 2, 12.94%, in Roxboro Unit No. 4 and 16.17% in the
Harris Plant and Mayo Unit No. 1. Otherwise, CP&L has good and marketable title
to its principal plants and important units, subject to the lien of its mortgage
and deed of trust, with minor exceptions, restrictions, and reservations in
conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. CP&L also owns certain easements
over private property on which transmission and distribution lines are located.
As of December 31, 2001, CP&L had 5,894 pole miles of transmission lines
including 295 miles of 500 kilovolt (kV) lines and 3,033 miles of 230 kV lines,
and distribution lines of approximately 44,530 pole miles of overhead lines and
approximately 15,646 miles of underground lines. Distribution and transmission
substations in service had a transformer capacity of approximately 31,104,000
kilovolt-ampere (kVA) in 2,234 transformers. Distribution line transformers
numbered 488,064 with an aggregate 19,535,000 kVA capacity.
ELECTRIC - FLORIDA POWER
- ------------------------
As of December 31, 2001, the total summer generating capacity (including
jointly-owned capacity) of Florida Power's generating facilities was 8,012 MW.
Florida Power's generating plants and their summer capacities gross of
co-ownership interests at December 31, 2001, are as follows:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
Summer Net
No. of Capability (a)
Facility Location Units In-Service Date Fuel (in MW)
- --------------------------------------------------------------------------------------------------
STEAM TURBINES
<S> <C> <C> <C> <C> <C>
Anclote Holiday, FL 2 1974-1978 Gas/Oil 993
Bartow St. Petersburg, FL 3 1958-1963 Gas/Oil 444
Crystal River Crystal River, FL 4 1966-1984 Coal 2,302
Suwannee River Live Oak, FL 3 1953-1956 Gas/Oil 143
-- -----
Total 12 3,882
COMBINED CYCLE
Hines Bartow, FL 1 1999 Gas/Oil 482
Tiger Bay Fort Meade, FL 1 1997 Gas 207
-- -----
Total 2 689
COMBUSTION TURBINES
Avon Park Avon Park, FL 2 1968 Gas/Oil 52
Bartow St. Petersburg, FL 4 1958-1972 Gas/Oil 187
Bayboro St. Petersburg, FL 4 1973 Oil 184
DeBary DeBary, FL 10 1975-1992 Gas/Oil 667
Higgins Oldsmar, FL 4 1969-1970 Gas 122
Intercession City Intercession City, FL 14 1974-2000 Gas/Oil 1,029(b)
Rio Pinar Rio Pinar, FL 1 1970 Oil 13
Suwannee River Live Oak, FL 3 1980 Gas/Oil 164
Turner Enterprise, FL 4 1970-1974 Oil 154
University of Gainesville, FL 1 1994 Gas 35
Florida Cogeneration
-- -----
Total 47 2,607
NUCLEAR
Crystal River Crystal River, FL 1 1977 Uranium 834(c)
-- -----
Total 1 834
TOTAL 62 8,012
- --------------------------------------------------------------------------------------------------
</TABLE>
(a) Represents Florida Power's net summer peak rating, gross of co-ownership
interest in plant capacity
(b) Florida Power and Georgia Power Company ("Georgia Power") are co-owners of
a 143 MW advanced combustion turbine located at Florida Power's
Intercession City site. Georgia Power has the exclusive right to the output
of this unit during the months of June through September. Florida Power has
that right for the remainder of the year.
(c) Represents 100% gross of co-owners total plant capacity. Florida Power's
ownership percentage is approximately 91.8%.
As of December 31, 2001, including both the total generating capacity of 8,012
MW and the total firm contracts for purchased power of 1,304 MW, Florida Power
had total capacity resources of approximately 9,316 MW.
32
<PAGE>
Substantially all of Florida Power's utility plant is pledged as collateral for
Florida Power's First Mortgage Bonds.
As of December 31, 2001, Florida Power distributed electricity through 358
substations with an installed transformer capacity of 50,800,000 kVA. Of this
capacity, 37,243,000 kVA is located in transmission substations and 13,557,000
kVA in distribution substations. Florida Power has the second largest
transmission network in Florida. Florida Power has 4,696 circuit miles of
transmission lines, of which 2,577 circuit miles are operated at 500, 230, or
115 kV and the balance at 69 kV. Florida Power has 26,806 circuit miles of
distribution lines, which operate at various voltages ranging from 2.4 to 25 kV.
PROGRESS VENTURES
- -----------------
The Progress Ventures business unit controls, either directly or through
subsidiaries, coal reserves located in eastern Kentucky and southwestern
Virginia. Progress Ventures owns properties that contain estimated coal reserves
of approximately 13 million tons and controls, through mineral leases,
additional estimated coal reserves of approximately 20 million tons. The
reserves controlled include substantial quantities of high quality, low sulfur
coal that is appropriate for use at Florida Power's existing generating units.
Progress Ventures' total production of coal during 2001 was approximately 3.1
million tons.
In connection with its coal operations, Progress Venture's subsidiaries own and
operate an underground mining complex located in southeastern Kentucky and
southwestern Virginia. Other subsidiaries own and operate surface and
underground mines, coal processing and loadout facilities and a river terminal
facility in eastern Kentucky, a railcar-to-barge loading facility in West
Virginia, and three bulk commodity terminals: one on the Ohio River in
Cincinnati, Ohio, and two on the Kanawha River near Charleston, West Virginia.
Progress Ventures and its subsidiaries employ both company and contract miners
in their mining activities. Through a joint venture, Progress Ventures has four
oceangoing tug/barge units.
The Progress Ventures business unit, through direct and indirect subsidiaries,
owns all of the interests in five entities and a minority interest in one entity
that owns facilities that produce synthetic fuel. These entities own a total of
nine facilities in seven different locations in West Virginia, Virginia and
Kentucky.
A subsidiary of Progress Ventures has oil and gas leases on about 20,000 acres
in Garfield and Mesa Counties, Colorado, containing proven natural gas net
reserves of 67.5 billion cubic feet. This subsidiary currently operates 70 gas
wells on the properties. Total natural gas production in 2001 was 4.7 billion
cubic feet.
Another subsidiary of Progress Ventures owns and operates a manufacturing
facility at the Florida Power Energy Complex in Crystal River, Florida. The
manufacturing process utilizes the fly ash generated by the burning of coal as
the major raw material in the production of lightweight aggregate used in
construction building blocks.
As of December 31, 2001, Progress Ventures had the following merchant plants in
service, planned for construction or planned to be acquired.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
Construction Commercial Operation Configuration/Number
Project Start Date Date of Units MW (a)
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Monroe Units 1 and 2 4Q 1998/1Q 2000 1Q 2000/2Q 2001 Simple-Cycle, 2 315
-----
Total 315
Rowan Phase I (b) 1Q 2000 2Q 2001 Simple-Cycle, 3 459
Walton (c) 2Q 2000 2Q 2001 Simple-Cycle, 3 460
DeSoto Units 1 and 2 2Q 2001 2Q 2002 (d) Simple-Cycle, 2 320
-----
Total 1,239
Effingham 1Q 2001 2Q 2003 (d) Combined-Cycle, 1 480
Rowan Phase II (b) 4Q 2001 2Q 2003 (d) Combined-Cycle, 1 466
Washington (c) 2Q 2002 2Q 2003 (d) Simple-Cycle, 4 600
-----
Total 1,546
TOTAL 3,100
- ----------------------------------------------------------------------------------------------
</TABLE>
(a) Represents Progress Venture's summer rating.
(b) Transferred from CP&L to Progress Ventures in February 2002
(c) Purchased from LG&E Energy Corp. in February 2002
(d) Expected commercial operation date
33
<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 26 states, Mexico and Canada.
Progress Rail owns and/or operates approximately 5,300 railcars and 100
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.
OTHER
- -----
NCNG
- ----
NCNG owns and operates a liquefied natural gas storage plant which provides
97,200 dekatherms (dt) per day to NCNG's peak-day delivery capability.
NCNG owns approximately 1,225 miles of transmission pipelines of two to 30
inches in diameter which connect its distribution systems with the Texas-to-New
York transmission system of Transco and the southern end of Columbia's
transmission system. Transco delivers gas to NCNG at various points conveniently
located with respect to its distribution area. Columbia delivers gas to one
delivery point near the North Carolina - Virginia border. NCNG distributes
natural gas through its 3,026 miles of distribution mains. These transmission
pipelines and distribution mains are located primarily on rights-of-way held
under easement, license or permit on lands owned by others.
In March 2001, construction of a 30-inch natural gas pipeline, named the
Sandhills Pipeline, from Iredell County to Richmond County in North Carolina was
completed. This 84-mile pipeline is primarily used to transport natural gas to
an electric generating plant constructed in Richmond County by CP&L.
PROGRESS TELECOM AND CARONET
- ----------------------------
Progress Telecom provides wholesale telecommunications services throughout the
Southeastern United States. Progress Telecom incorporates more than 130,000
fiber miles in its network including over 150 Points-of-Presence, which includes
Caronet.
ITEM 3. LEGAL PROCEEDINGS
- ------ -----------------
Legal and regulatory proceedings are included in the discussion of the Company's
business in PART I, ITEM 1 under "Environmental", "Regulatory Matters" and
"Nuclear Matters" and incorporated by reference herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- ------ ---------------------------------------------------
NONE
34
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANTS
-------------------------------------
<TABLE>
<CAPTION>
Name Age Recent Business Experience
- ---- --- --------------------------
<S> <C> <C>
William Cavanaugh III 63 Chairman, President and Chief Executive Officer, Progress Energy, Inc.,
August 1999 to present; Chairman, Progress Energy Service Company, LLC,
August 2000 to present; Chairman, Florida Power Corporation, November 30,
2000 to present; Chairman, Progress Ventures, Inc., March 2000 to present;
Chairman, President and Chief Executive Officer, Carolina Power & Light
Company ("CP&L"), May 1999 to present; President and Chief Executive
Officer, CP&L, October 1996 to May 1999; President and Chief Operating
Officer, CP&L, September 1992 to October 1996. Member of the Board of
Directors of the Company since 1993.
William S. Orser 57 Group President, CP&L and Florida Power Corporation, November 2000 to
present; Executive Vice President, CP&L, Energy Supply, June 1998 to
November 2000; Executive Vice President and Chief Nuclear Officer, CP&L,
December 1996 to June 1998; Executive Vice President, CP&L, Nuclear
Generation, April 1993 to December 1996.
Robert B. McGehee 59 Executive Vice President, Progress Energy, Inc. and CP&L, February, 2001
to present; Executive Vice President, Florida Progress Company, December
2000 to present; President and Chief Executive Officer, Progress Energy
Service Company, LLC, from August, 2000 to present; Executive Vice
President and General Counsel, Progress Energy Inc., August, 1999 to
February, 2001; Executive Vice President and General Counsel, CP&L, May
2000 to February 2001; Executive Vice President, General Counsel, Chief
Administrative Officer and Interim Chief Financial Officer, CP&L, March 3,
2000 to May 2000; Executive Vice President, General Counsel and Chief
Administrative Officer, CP&L, March 1999 to March 3, 2000; Senior Vice
President and General Counsel, CP&L, May 1997 to March 1999. From 1974 to
May 1997, Mr. McGehee was a practicing attorney with Wise Carter Child &
Caraway, a law firm in Jackson, Mississippi. He primarily handled
corporate, contract, nuclear regulatory and employment matters. From 1987
to 1997 he managed the firm, serving as chairman of its Board from 1992 to
May 1997.
Peter M. Scott III 52 Executive Vice President and Chief Financial Officer, Progress Energy,
Inc., June 2000 to present; Executive Vice President and CFO, Florida
Power Corporation and Florida Progress Corporation, November 2000 to
present; Executive Vice President and CFO, Progress Energy Service
Company, LLC, August 2000 to present; Executive Vice President and CFO,
CP&L, May 2000 to present; Executive Vice President and CFO, NCNG,
December 2000 to present. Before joining the Company, Mr. Scott was
President of Scott, Madden & Associates, Inc., a management consulting
firm he founded in 1983. The firm advises companies on key strategic
initiatives for growing shareholder value.
</TABLE>
35
<PAGE>
<TABLE>
<S> <C> <C>
William D. Johnson 48 Executive Vice President, General Counsel and Secretary, Progress Energy,
Inc, February 2001 to present; Executive Vice President and Corporate
Secretary, Progress Energy, Inc., June 2000 to February 2001; Senior Vice
President and Secretary, Progress Energy, Inc., August 1999 to June 2000;
Executive Vice President, General Counsel and Corporate Secretary,
Progress Energy Service Company, LLC, August 2000 to present; Executive
Vice President, General Counsel and Corporate Secretary, CP&L, November
2000 to present; Senior Vice President and Corporate Secretary, CP&L,
Legal and Risk Management, March 1999 to November 2000; Vice
President-Legal Department and Corporate Secretary, CP&L, 1997 to 1999;
Vice President, Senior Counsel and Manager-Legal Department, CP&L, 1995 to
1997.
Robert H. Bazemore, Jr. 47 Controller, Progress Energy, Inc., June 2000 to present; Controller,
Florida Power Corporation and Florida Progress Corporation, November 2000
to present; Vice President and Controller, Progress Energy Service
Company, LLC, August 2000 to present; Chief Accounting Officer and
Controller, CP&L, May 2000 to present; Chief Accounting Officer and
Controller, North Carolina Natural Gas Corporation ("NCNG"), December 2000
to present; Director, CP&L, Operations & Environmental Support Department,
December 1998 to May 2000; Manager, CP&L, Financial & Regulatory
Accounting, September 1995 to December 1998.
Donald K. Davis 56 Executive Vice President, CP&L, May 2000 to present; President and Chief
Executive Officer, NCNG, July 2000 to present; Chief Executive Officer,
Strategic Resource Solutions, June 2000 to present; Executive Vice
President, Florida Power Corporation, February 2001 to present. Before
joining the Company, Mr. Davis was Chairman, President and Chief Executive
Officer of Yankee Atomic Electric Company, and served as Chairman,
President and Chief Executive Officer of Connecticut Atomic Power Company
from 1997 to May 2000.
Fred N. Day, IV 58 Executive Vice President, CP&L and Florida Power Corporation, November
2000 to present; Senior Vice President, CP&L, Energy Delivery, July 1997
to November 2000; Vice President, CP&L, Western Region, 1995 to July 1997.
Cecil L. Goodnight 59 Senior Vice President, Progress Energy Service Company, LLC, August 2000
to present; Senior Vice President, Florida Power Corporation, June 2001 to
present; Senior Vice President, CP&L, December 1998 to present; Senior
Vice President and Chief Administrative Officer, CP&L, December 1996 to
December 1998.
*H. William Habermeyer, Jr. 59 President and Chief Executive Officer, Florida Power Corporation, November
2000 to present; Vice President, CP&L, Western Region, July 1997 to
November 2000; Vice President, CP&L, Nuclear Engineering, August 1995 to
July 1997.
*Bonnie V. Hancock 40 Senior Vice President, Progress Energy Service Company, LLC, November 2000
to present; Vice President, CP&L, Strategic Planning, February 1999 to
November 2000; Vice President and Controller, CP&L, February 1997 to
February 1999; Manager, Tax Department, CP&L, September 1995 to February
1997.
</TABLE>
36
<PAGE>
<TABLE>
<S> <C> <C>
C.S. Hinnant 57 Senior Vice President, Florida Power Corporation, November 2000 to present;
Senior Vice President and Chief Nuclear Officer, CP&L, June 1998 to present;
Vice President, CP&L, Brunswick Nuclear Plant, April 1997 to June 1998; Vice
President, CP&L, Robinson Nuclear Plant, March 1994 to March 1997.
Tom D. Kilgore 54 Group President, CP&L, November 2000 to present; President and CEO, Progress
Ventures, Inc., March 2000 to present; Senior Vice President, CP&L, Power
Operations, August 1998 to November 2000; President and Chief Executive Officer,
Oglethorpe Power Corporation, Georgia Transmission Corporation and Georgia
Operations Corporation, July 1991 to August 1998. These three companies provide
power generation, transmission and system operations services, respectively, to
39 of Georgia's 42 customer-owned Electric Membership Corporations. From 1984 to
July 1991, Mr. Kilgore held numerous management positions at Oglethorpe.
E. Michael Williams 53 Senior Vice President, Florida Power Corporation, November 2000 to present;
Senior Vice President, CP&L, June 2000 to present. President,. Before joining
the Company, Mr. Williams held the position of Vice President, Fossil
Generation, Central and South West Corp., an investor-owned utility from March
1994 to June 2000.
</TABLE>
* Indicates individual is an executive officer of Progress Energy, Inc., but not
CP&L.
37
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
- ------ -----------------------------------------------------------------
MATTERS
- -------
Progress Energy's Common Stock is listed on the New York and Pacific Stock
Exchanges. The high and low stock prices for CP&L (for periods prior to the
consummation of the holding company restructuring on June 19, 2000) and for
Progress Energy (for periods following the consummation of the holding company
restructuring on June 19, 2000) for each quarter for the past two years, and the
dividends declared per share are as follows:
2001 High Low Dividends Declared
- ---- ------ ------ ------------------
First Quarter $49.25 $38.78 .530
Second Quarter 45.00 40.36 .530
Third Quarter 45.79 39.25 .530
Fourth Quarter 45.60 40.50 .545
2000 High Low Dividends Declared
- ---- ------ ------ ------------------
First Quarter $37.00 $28.25 .515
Second Quarter 38.00 31.00 .515
Third Quarter 41.94 31.50 .515
Fourth Quarter 49.38 38.00 .530
The December 31 closing price of the Company's Common Stock was $45.03 in 2001
and $49.19 in 2000.
As of February 28, 2002, the Company had 218,727,139 holders of record of Common
Stock.
Progress Energy holds all 159,608,055 shares outstanding of CP&L common stock
and, therefore, no public trading market exists for the common stock of CP&L.
38
<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>
<CAPTION>
Years Ended December 31
2001 2000 (a) 1999 (b) 1998 1997
----------- ----------- ---------- ---------- ----------
(dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
Operating results
- -----------------
Operating revenues $ 8,461,459 $ 4,103,413 $3,364,927 $3,211,552 $3,038,159
Net income $ 541,610 $ 478,361 $ 379,288 $ 396,271 $ 382,265
Per share data
Basic earnings per
common share $ 2.65 $ 3.04 $ 2.56 $ 2.75 $ 2.66
Diluted earnings per
common share $ 2.64 $ 3.03 $ 2.55 $ 2.75 $ 2.66
Dividends declared per common
share $ 2.135 $ 2.075 $ 2.015 $ 1.955 $ 1.895
Assets $20,739,791 $20,110,701 $9,494,019 $8,401,406 $8,220,728
- ------
Capitalization
- --------------
Common stock equity $ 6,003,533 $ 5,424,201 $3,412,647 $2,949,305 $2,818,807
Preferred stock - redemption
not required 92,831 92,831 59,376 59,376 59,376
Long-term debt, net 9,483,745 5,890,099 3,028,561 2,614,414 2,415,656
----------- ----------- ---------- ---------- ----------
Total capitalization $15,580,109 $11,407,131 $6,500,584 $5,623,095 $5,293,839
=========== =========== ========== ========== ==========
</TABLE>
(a) Operating results and balance sheet data includes information for FPC since
November 30, 2000, the date of acquisition.
(b) Operating results and balance sheet data includes information for NCNG
since July 15, 1999, the date of acquisition.
39
<PAGE>
CAROLINA POWER & LIGHT COMPANY
- ------------------------------
The selected consolidated financial data should be read in conjunction with the
consolidated financial statements and the notes thereto included elsewhere in
this report.
<TABLE>
<CAPTION>
Years Ended December 31
2001 2000 (a) 1999 (b) 1998 1997
---------- ---------- ---------- ---------- ----------
(dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating results
- -----------------
Operating revenues $3,360,161 $3,543,907 $3,357,615 $3,211,552 $3,038,159
Net income $ 364,231 $ 461,028 $ 382,255 $ 399,238 $ 388,317
Earnings for common stock $ 361,267 $ 458,062 $ 379,288 $ 396,271 $ 382,265
Assets $9,263,212 $9,239,486 $9,494,019 $8,401,406 $8,220,728
- ------
Capitalization
- --------------
Common stock equity $3,095,456 $2,852,038 $3,412,647 $2,949,305 $2,818,807
Preferred stock - redemption
not required 59,334 59,334 59,376 59,376 59,376
Long-term debt, net 2,958,853 3,619,984 3,028,561 2,614,414 2,415,656
---------- ---------- ---------- ---------- ----------
Total capitalization $6,113,643 $6,531,356 $6,500,584 $5,623,095 $5,293,839
========== ========== ========== ========== ==========
</TABLE>
(a) Operating results and balance sheet data do not include information for
NCNG, SRS, Monroe Power and Progress Ventures, Inc. subsequent to July 1,
2000, the date CP&L distributed its ownership interest in the stock of
these companies to Progress Energy.
(b) Operating results and balance sheet data includes information for NCNG
since July 15, 1999, the date of acquisition.
40
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- ------ ------------------------------------------------------------------------
OF OPERATIONS
- -------------
PROGRESS ENERGY, INC.
- ---------------------
RESULTS OF OPERATIONS
- ---------------------
For 2001 as compared to 2000 and 2000 as compared to 1999
In this section, earnings and the factors affecting them are discussed. The
discussion begins with a general overview, then separately discusses earnings by
business segment.
Overview
Progress Energy, Inc. (Progress Energy or the Company) is a registered holding
company under the Public Utility Holding Company Act of 1935, as amended
(PUHCA). Both Progress Energy and its subsidiaries are subject to the regulatory
provisions of PUHCA. Progress Energy was formed as a result of the
reorganization of Carolina Power & Light Company (CP&L) into a holding company
structure on June 19, 2000. All shares of common stock of CP&L were exchanged
for an equal number of shares of CP&L Energy, Inc (CP&L Energy). On December 4,
2000, CP&L Energy changed its name to Progress Energy, Inc.
The Company's acquisition of Florida Progress Corporation (FPC) became effective
on November 30, 2000. The acquisition was accounted for using the purchase
method of accounting. As a result, the consolidated financial statements only
reflect FPC's operations subsequent to November 30, 2000.
Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation
(Florida Power) and North Carolina Natural Gas Corporation (NCNG), Progress
Energy is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North Carolina, South Carolina and Florida;
and the transport, distribution and sale of natural gas in portions of North
Carolina. Through the Progress Ventures business segment, Progress Energy is
involved in merchant energy generation, coal and synthetic fuel operations and
energy marketing and trading. Through other business units, Progress Energy
engages in other non-regulated business areas including energy management and
related services, rail services and telecommunications.
Progress Energy is a regional energy company focusing on the high-growth
Southeast region of the United States. The Company has more than 20,000
megawatts of generation capacity and serves approximately 2.9 million electric
and gas customers in portions of North Carolina, South Carolina and Florida.
CP&L's and Florida Power's utility operations are complementary: CP&L has a
summer peaking demand, while Florida Power has a winter peaking demand. In
addition, CP&L's greater proportion of commercial and industrial customers
combined with Florida Power's greater proportion of residential customers
creates a more balanced customer base. The Company is dedicated to expanding the
region's electric generation capacity and delivering reliable, competitively
priced energy.
The operations of Progress Energy and its subsidiaries are divided into five
major segments: two electric utilities (CP&L and Florida Power), Progress
Ventures, Rail Services and Other. The Other segment includes natural gas
operations, telecommunication services, energy management services,
miscellaneous non-regulated activities, holding company operations and
elimination entries.
In 2001, net income was $541.6 million, a 13.2% increase over $478.4 million in
2000. Net income increased in 2001 primarily due to a full year of FPC's
operations being included in the 2001 results, as FPC contributed net income of
$398.3 million for the year ended December 31, 2001. Other factors contributing
to the increase in net income in 2001 include increases in tax credits from
Progress Energy's share of synthetic fuel facilities, continued customer growth
at the electric utilities and decreases in depreciation expense related to
CP&L's accelerated cost recovery program. Partially offsetting these increases
were impairment and one-time after-tax charges totaling $152.8 million primarily
attributable to Strategic Resource Solutions Corp. (SRS) and the Company's
investment in Interpath, as well as increases in interest expense and goodwill
amortization related to the FPC acquisition. Basic earnings per share decreased
from $3.04 per share in 2000 to $2.65 per share in 2001 due to the factors
outlined above and also from an increase in the number of shares outstanding
resulting from the FPC acquisition and an additional common stock issuance in
August 2001.
In 2000, net income was $478.4 million, a 26.1% increase over $379.3 million in
1999. Basic earnings per share increased from $2.56 per share in 1999 to $3.04
per share in 2000. Continued customer growth, increased usage by CP&L Electric
customers and tax credits from Progress Energy's share of synthetic fuel
facilities positively affected earnings. Other significant events included the
sale of a 10% limited partnership interest in BellSouth Carolinas PCS for a
$121.1 million after-tax gain, additional accelerated depreciation of CP&L
nuclear generation facilities for a
41
<PAGE>
$192.5 million after-tax effect and the December operations of FPC, which
contributed net income of $28.7 million for the month of December 2000.
Note 1 to the Progress Energy consolidated financial statements discusses the
Company's significant accounting policies. The most critical accounting policies
and estimates that impact the Company's financial statements are the economic
impacts of utility regulation, which are described in more detail in Note 13 and
the impact of synthetic fuel tax credits, which are described in more detail in
Note 18 to the Progress Energy consolidated financial statements.
Electric Segments
The electric segments are primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North and South Carolina by
CP&L and, since November 30, 2000, in portions of Florida by Florida Power. CP&L
serves an area of approximately 34,000 square miles, with a population of more
than 4.0 million. As of December 31, 2001, CP&L provided electricity to
approximately 1.3 million customers. Florida Power serves an area of
approximately 20,000 square miles, with a population of more than 5.0 million.
As of December 31, 2001, Florida Power provided electricity to approximately 1.4
million customers.
The operating results of both electric utilities are primarily influenced by
customer demand for electricity, the ability to control costs and the authorized
regulatory return on equity. Annual demand for electricity is based on the
number of customers and their annual usage, with usage largely impacted by
weather. In addition, the current economic conditions in the service territories
can impact the annual demand for electricity.
CP&L Electric
- -------------
CP&L Electric operations contributed net income of $468.3 million, $373.8
million and $430.3 million in 2001, 2000 and 1999, respectively. Included in
these amounts are energy marketing and trading activities, which are managed by
Progress Ventures on behalf of CP&L, that had net income of $62.7 million, $84.0
million and $69.5 million in 2001, 2000 and 1999, respectively.
Revenues
CP&L's electric revenues for the years ended December 31, 2001, 2000 and 1999
and the percentage change by year by customer class are as follows (in
millions):
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Customer Class 2001 % Change 2000 % Change 1999
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential $1,152 3.5% $1,113 5.3% $1,057
Commercial 785 5.9 741 4.8 707
Industrial 654 (3.7) 679 (1.7) 691
Governmental 75 (1.3) 76 -- 76
- ----------------------------- ------ ------ ------
Total Retail Revenues 2,666 2.2 2,609 3.1 2,531
Wholesale 634 9.9 577 3.8 556
Miscellaneous 44 (63.9) 122 106.8 59
- ----------------------------- ------ ------ ------
Total Electric Revenues $3,344 1.1% $3,308 5.1% $3,146
- ----------------------------------------------------------------------------------
</TABLE>
CP&L electric energy sales for 2001, 2000 and 1999 and the percentage change by
year by customer class are as follows (in thousands of mWh):
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Customer Class 2001 % Change 2000 % Change 1999
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Residential 14,372 2.0% 14,091 5.6% 13,348
Commercial 11,972 4.7 11,432 3.3 11,068
Industrial 13,332 (7.7) 14,446 (0.8) 14,568
Governmental 1,423 -- 1,423 4.7 1,359
- ----------------------------- ------ ------ ------
Total Retail Energy Sales 41,099 (0.7) 41,392 2.6 40,343
Wholesale 12,996 (10.9) 14,582 0.4 14,526
Unbilled (534) -- 679 -- (110)
- ----------------------------- ------ ------ ------
Total mWh sales 53,561 (5.5%) 56,653 3.5% 54,759
- ----------------------------------------------------------------------------------
</TABLE>
During 2001, residential and commercial sales reflected continued growth in the
number of customers served by CP&L, partially offset by mild weather. CP&L added
over 30,500 new customers in 2001. Cooler-than-normal weather in the summer and
milder-than-normal weather in the fourth quarter of 2001 accounted for a
decrease in retail sales for the year compared to 2000. Colder-than-normal
weather in the fourth quarter of 2000 accounted for
42
<PAGE>
an increase in retail sales for 2000 when compared to 1999. The 2000 favorable
variances over 1999 were also attributable to customer growth and usage as CP&L
added over 33,000 new customers in 2000.
Downturns in the economy during 2001 impacted energy usage throughout most of
the industrial customer class. Total industrial sales fell during 2001 and the
number of customers decreased due to slowdowns and plant closings. The decline
was primarily due to a downturn in the textile industry, with other usage
decreases noted in the chemical, rubber, and plastic industries. Energy used by
the industrial class was relatively flat from 1999 to 2000. Total mWh sales to
wholesale customers decreased in 2001 from 2000 primarily due to mild weather.
However, revenues from wholesale customers increased in 2001 over 2000 due to
the establishment of new long-term contracts and the receipt of a termination
payment on a long-term contract in December 2001. In 2000, sales to wholesale
customers were slightly higher than 1999 due to colder-than-normal weather and
competitive prices in fourth quarter of 2000.
Expenses
CP&L Electric's fuel expense increased $19.8 million in 2001 when compared to
$627.5 million in 2000 primarily due to increases in the price of coal,
partially offset by decreases in generation. CP&L Electric's fuel expense
increased $46.2 million in 2000 when compared to $581.3 million in 1999
primarily due to increases in generation and increases in fuel prices associated
with gas and oil-fired units.
For 2001, purchased power increased $28.2 million when compared to $325.4
million in 2000 mainly due to favorable market conditions in the first quarter
of 2001. For 2000, purchased power decreased $40.0 million when compared to
$365.4 million in 1999 primarily due to the expiration of CP&L's long-term
purchase power agreement with Duke Energy in mid-1999. Additionally, 2000
reflects a decrease in purchases from cogeneration facilities when compared to
1999.
Fuel and purchased power expenses are recovered primarily through cost recovery
clauses and, as such, have no material impact on operating results.
CP&L Electric's other operation and maintenance expenses decreased $24.6 million
in 2001 when compared to $726.3 million in 2000 primarily due to the absence of
restoration costs associated with the severe winter storm and record-breaking
snowfall in January 2000, as well as cost control efforts. These amounts were
partially offset by increases in planned nuclear outage costs and transmission
expenses in 2001. In 2000, other operation and maintenance expense increased
$57.7 million when compared to $668.6 million in 1999 due to increases in
benefit plan-related expenses and emission allowances. A total of $23 million of
emission allowances was expensed in 2000.
Depreciation and amortization expense decreased $176.7 million in 2001 when
compared to $698.6 million in 2000 and increased $204.7 million in 2000 when
compared to $493.9 million in 1999. CP&L's accelerated cost recovery program for
nuclear generating assets allows flexibility in recording accelerated
depreciation expense. In 2001, CP&L recorded $75 million to depreciation
expense, the minimum amount of accelerated depreciation allowed under the
program. In 2000, as approved by regulators, CP&L recorded $275 million to
depreciation expense under this program. See Note 1G to the Progress Energy
consolidated financial statements for additional information about this program.
Net interest expense increased $19.6 million in 2001 when compared to $221.9
million in 2000 and increased $38.8 million in 2000 when compared to $183.1
million in 1999 primarily due to higher debt balances. Debt balances increased
over these periods in order to fund construction programs.
Florida Power Electric
- ----------------------
The results shown in the Progress Energy consolidated financial statements for
the Florida Power Electric segment are not comparable to the prior year as the
operating results of Florida Power have only been included in Progress Energy's
results of operations since the date of acquisition, November 30, 2000.
Therefore, the results of operations for 2000 only include one month of Florida
Power operations and the results of operations for 2001 include a full year of
Florida Power operations.
Florida Power Electric contributed net income of $309.6 million for the year
ended December 31, 2001 and $21.8 million for the month of December 2000.
Included in these amounts are energy marketing and trading activities, which are
managed by Progress Ventures on behalf of Florida Power, that had net income of
$24.0 million for the year ended December 31, 2001 and $1.7 million for the
month of December 2000.
43
<PAGE>
A comparison of the results of operations of Florida Power Electric for a full
year 2001 compared to a full year 2000 follows.
Revenues
Florida Power's electric revenues for the years ended December 31, 2001 and 2000
and the percentage change by customer class are as follows (in millions):
- ---------------------------------------------------------------------
Customer Class 2001 % Change 2000/(a)/
- ---------------------------------------------------------------------
Residential $1,643 11.3% $1,476
Commercial 754 13.9 662
Industrial 223 5.2 212
Governmental 176 15.8 152
- ------------------------------------------ ------
Total Retail Revenues 2,796 11.8 2,502
Wholesale 288 4.3 276
Miscellaneous 129 37.2 94
- ------------------------------------------ ------
Total Electric Revenues $3,213 11.9% $2,872
- --------------------------------------------------------------------
(a) Florida Power electric revenues are included in the Company's results
of operations since November 30, 2000, the date of acquisition.
Florida Power's electric energy sales for the years ended December 31, 2001 and
2000 and the percentage change by customer class are as follows (in thousands of
mWh):
- ---------------------------------------------------------------------
Customer Class 2001 % Change 2000/(a)/
- ---------------------------------------------------------------------
Residential 17,604 2.9% 17,116
Commercial 11,061 2.3 10,813
Industrial 3,872 (8.9) 4,249
Governmental 2,726 2.7 2,654
- ------------------------------------------ ------
Total Retail Energy Sales 35,263 1.2 34,832
Wholesale 4,719 (9.4) 5,209
Unbilled (511) -- 344
- ------------------------------------------ ------
Total mWh sales 39,471 (2.3%) 40,385
- --------------------------------------------------------------------
(a) Florida Power electric energy sales are included in the Company's
results of operations since November 30, 2000, the date of
acquisition.
Residential and commercial sales increased in 2001 and reflected continued
growth in the number of customers served by Florida Power, partially offset by
milder-than-normal weather and a downturn in the Florida economy. Florida Power
added over 35,000 new customers in 2001. Industrial sales declined due to
weakness in the manufacturing sector and phosphate industry, which continue to
be affected by the economic downturn. Sales to wholesale customers decreased for
2001, primarily due to the mild weather.
Expenses
Fuel used in generation and purchased power was $1.4 billion for the year ended
December 31, 2001. Fuel used in generation increased $230.9 million when
compared to 2000 primarily due to increases in coal prices and recovery of
previously deferred fuel costs, and purchased power expense was consistent
between 2000 and 2001. Fuel and purchased power expenses are recovered primarily
through cost recovery clauses and, as such, have no material impact on operating
results. Other operation and maintenance expense was $425.5 million for the year
ended December 31, 2001 and decreased when compared to 2000 due primarily to
merger-related costs recorded in the prior year. Excluding these costs, other
operation and maintenance expense was consistent between years.
Depreciation and amortization expense was $453.0 million in 2001 and increased
$50.3 million when compared to 2000. During 2001, Florida Power recorded
additional amortization on the Tiger Bay regulatory asset, which was created as
a result of the early termination of certain long-term cogeneration contracts.
Florida Power amortizes the regulatory asset according to a plan approved by the
Florida Public Service Commission in 1997. In 2001, $97 million of accelerated
amortization was recorded on the Tiger Bay regulatory asset, of which $63
million was associated with deferred revenue from 2000 and had no impact on 2001
earnings.
Progress Ventures
The Progress Ventures segment operations include fuel extraction, manufacturing
and delivery, synthetic fuels production, merchant generation, and energy
marketing and trading activities on behalf of the utility operating
44
<PAGE>
companies. Due to the creation of Progress Ventures in 2000 and the acquisition
of Electric Fuels' subsidiaries (renamed Progress Fuels on January 2, 2002)
through the FPC acquisition, the results of operations for the Progress Ventures
segment are not comparable to the prior year.
Progress Ventures contributed segment income, including allocation of energy
marketing and trading on behalf of the utilities, of $288.7 million, $125.6
million and $69.5 million for 2001, 2000 and 1999, respectively. Of these
amounts, energy marketing and trading net income on behalf of the utilities was
$86.7 million, $85.7 million and $69.5 million in 2001, 2000 and 1999,
respectively.
The increase in earnings for this segment is primarily due to the tax credits
generated by Progress Energy's synthetic fuel operations. The Progress Ventures
segment sold 13.3 million tons of synthetic fuel for the year ended December 31,
2001, and 2.9 million tons for the year ended December 31, 2000. The production
of synthetic fuel generates an operating loss and the sale of this alternative
fuel qualifies for tax credits under Section 29 of the Internal Revenue Code
(See "Synthetic Fuels" discussion under OTHER MATTERS below). These credits are
determined by the BTU content of product sold to third parties and resulted in
tax credits of $349.3 million and $83.6 million being recorded for 2001 and
2000, respectively. The Company is exploring the possible sale of an interest in
its synthetic fuel facilities in order to optimize the total value of this line
of business.
Progress Ventures' energy marketing and trading activities on behalf of CP&L
generated net income of $62.7 million, $84.0 million, and $69.5 million for
2001, 2000 and 1999, respectively. Earnings from the term marketing operations
were relatively flat across these periods. Earnings from the trading operations
decreased in 2001 from 2000 primarily due to a decline in market prices and
transfer of available trading volumes to long-term contracts. The fair value of
the Company's open trading positions was less than $0.2 million at December 31,
2001. Earnings from the trading operations increased in 2000 from 1999 primarily
due to trading profits and strong prices during periods when CP&L had unused
capacity available for sale. Progress Ventures' energy marketing and trading
activities on behalf of Florida Power for the year ended December 31, 2001 and
month of December 2000 were $24.0 million and $1.7 million, respectively. On an
annual basis, these earnings have increased over the prior year primarily due to
increased term marketing sales to Seminole Electric Cooperative, Florida Power's
largest wholesale customer.
The fuel extraction, manufacturing and delivery results are not comparable to
the prior year due to the acquisition of FPC in November 2000. Merchant
generation operations for the current year were consistent with the prior period
results. Progress Energy expects earnings in merchant generation to increase in
the future through the addition of a plant in Florida, transfer of generating
assets in Rowan County from CP&L to Progress Ventures and additional acquisition
and construction of electric generating projects. See OTHER MATTERS below for a
detail of Progress Ventures' plant developments and acquisitions.
Rail Services
Rail Services' operations represent the activities of Progress Rail Services
Corporation (Progress Rail) and include railcar repair, rail parts
reconditioning and sales, scrap metal recycling and other rail related services.
Rail Services' results for the year ended December 31, 2001, include Rail
Services' cumulative revenues and net loss from the date of acquisition,
November 30, 2000.
Due to the acquisition of Progress Rail through the FPC acquisition, the results
of operations for the Rail Services segment are not comparable to the prior
year. The current year net loss of $12.1 million was negatively affected by a
decrease in rail service procurement by major railroads and the significant
downturn in the domestic scrap market.
Other
Progress Energy's Other segment primarily includes the operations of NCNG, SRS,
Progress Telecommunications Corporation (Progress Telecom) and Caronet, Inc.
(Caronet). This segment also includes other non-regulated operations of CP&L and
FPC as well as holding company results. The Other segment had a net loss of
$426.2 million in 2001 and net income of $43.0 million in 2000. The decrease in
earnings for 2001 when compared to 2000 is primarily due to one-time after-tax
charges of $148.1 million from the assessment of the recoverability of the
Interpath investment and certain assets in the SRS subsidiary, increases in
after-tax interest expense for holding company debt of $159.0 million and
goodwill amortization of $89.7 million resulting from the acquisition of FPC. In
addition, the Other segment net income in 2000 includes a $121.1 million
after-tax gain on sale of assets, as described more fully below.
In 1999, the Other segment had a net loss of $51.1 million. The increase in
earnings in 2000 when compared to 1999 is primarily due to a $121.1 million
after-tax gain on the sale of Caronet's 10% limited partnership interest in
45
<PAGE>
BellSouth Carolinas PCS in September 2000. Caronet sold its interest for a
pre-tax gain of $200 million, which was recorded as other income.
SRS is engaged in software sales and energy services to help industrial,
commercial and institutional customers manage energy costs. Progress Energy is
refocusing the business on energy services in the southeastern states and is
consolidating remaining operations with other retail activities. SRS net losses,
excluding after-tax impairments and other one-time charges discussed below, were
$7.2 million, $0.8 million and $10.4 million for 2001, 2000 and 1999,
respectively. Due to the historical and current year losses at SRS and the
decline of the market value for technology companies, the company obtained a
valuation study to help assess the recoverability of SRS's long-lived assets.
Based on this assessment, the Company recorded after-tax asset impairments and
other one-time charges of $40.7 million in the fourth quarter of 2001. In
addition, the Company recorded after-tax investment impairments of $4.9 million
for other-than-temporary declines in certain investments of SRS in the fourth
quarter of 2001. These writedowns constitute a significant reduction in the book
value of these assets, and the ongoing operations are expected to have a
negligible impact on Progress Energy's net income.
Effective June 28, 2000, Caronet contributed the net assets used in its
application service provider business to a newly formed company named Interpath
Communications, Inc. (Interpath) for a 35% ownership interest (15% voting
interest). Therefore, the application service provider revenues are not
reflected in the Progress Energy consolidated financial statements subsequent to
that date. Due to the decline in the market value for technology companies,
Progress Energy obtained a valuation study to assess its investment in
Interpath. Based on this valuation, the company recorded an after-tax impairment
of $102.4 million for other-than-temporary declines in the fair value of its
investment in Interpath.
NCNG had gross margins of $77.9 million and $70.5 million and net income of $2.5
million and $6.5 million for the years ended December 31, 2001 and 2000,
respectively. The increase in margin is mainly attributable to the Sandhills
pipeline that was completed in March 2001, which was partially offset by
declines in industrial sales. The decrease in net income is primarily due to
higher overall operating expenses. The operations from 2000 to 1999 are not
comparative as NCNG was acquired on July 15, 1999. In February 2002, NCNG filed
a general rate case with the North Carolina Utilities Commission (NCUC)
requesting an annual rate increase of $47.6 million, based upon its completion
of major expansion projects. Progress Energy cannot predict the final outcome of
this matter.
Progress Telecom, acquired as part of the FPC acquisition, provides broadband
capacity services, dark fiber and wireless services in Florida and the Eastern
United States. Progress Telecom and certain assets and liabilities of Caronet
will be combined into a new entity named Progress Telecom Corporation (Telecom)
in the first half of 2002. All existing contracts for Progress Telecom and
Caronet will be transferred to this entity in the first half of 2002, subject to
regulatory approval. The combined operating losses for Progress Telecom and
Caronet were $9.1 million in 2001.
The Other segment also includes Progress Energy's holding company results. As
part of the acquisition of FPC, goodwill of approximately $3.6 billion was
recorded, and amortization of $89.7 million in 2001 and $7.0 million in 2000 is
included in the Other segment. See Note 1L to the Progress Energy consolidated
financial statements for information on recent developments related to goodwill
amortization. Interest expense of $265.1 million in 2001 and $28.0 million in
2000, primarily related to the debt used to finance the acquisition of FPC, is
also included in these results.
Progress Energy issued 98.6 million contingent value obligations (CVOs) in
connection with the FPC acquisition. Each CVO represents the right to receive
contingent payments based on the performance of four synthetic fuel facilities
owned by Progress Energy. The payments, if any, are based on the net after-tax
cash flows the facilities generate. At December 31, 2001, the CVOs had a fair
market value of approximately $41.9 million. Progress Energy recorded an
unrealized loss of $1.5 million for the year ended December 31, 2001, and an
unrealized gain of $8.9 million for the month ended December 31, 2000, to record
the change in fair value of CVOs.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Overview
Progress Energy is a registered holding company and, as such, has no operations
of its own. The ability to meet its obligations is primarily dependent on the
earnings and cash flows of its two electric utilities and the ability of those
subsidiaries to pay dividends or to advance or repay funds to Progress Energy.
Progress Energy continues to focus on its strategy of becoming a diversified
electric and gas holding company. The cash requirements of Progress Energy arise
primarily from the capital intensive nature of its electric utility operations
as well as the expansion of its diversified businesses, primarily those of
Progress Ventures.
46
<PAGE>
Progress Energy relies upon its operating cash flow, commercial paper facilities
and its ability to access long-term capital markets for its liquidity needs.
Since a substantial majority of Progress Energy's operating costs are related to
its two regulated electric utilities, a significant portion of these costs are
recovered from customers through fuel and energy cost recovery clauses.
Progress Energy expects its operating cash flow to exceed its projected capital
expenditures beginning in 2003. Due to the significant portion of cash flows
derived from its regulated businesses and an excess of operating cash flow over
capital expenditures beginning in 2003, Progress Energy expects its liquidity
resources to be sufficient to fund its current business plans. Risk factors
associated with commercial paper back up credit facilities and credit ratings
are discussed below.
The following discussion of Progress Energy's liquidity and capital resources is
on a consolidated basis.
Cash Flows from Operations
Cash from operations is the primary source used to meet operating requirements
and capital expenditures. The increase in cash from operating activities for
2001 when compared with 2000 is largely the result of the November 30, 2000,
acquisition of FPC. The prior year results reflected one month's cash from
operations of FPC.
Progress Energy's two electric utilities produced approximately 125% of
consolidated cash from operations in 2001. This is expected to continue over the
next several years as its non-regulated investments, primarily generation
assets, are placed into service and begin generating operating cash flows. In
addition, Progress Venture's synthetic fuel operations do not currently produce
positive operating cash flow primarily due to the difference in timing of when
tax credits are recognized for financial reporting purposes and when tax credits
are realized for tax purposes.
Total cash from operations of $1.4 billion provided the funding for
approximately 86% of the Company's property additions, nuclear fuel expenditures
and diversified business property additions during 2001. For 2002, it is
expected that approximately 80% of capital expenditures will be funded
internally, which is a decrease from 2001 due to increases in projected
non-regulated capital expenditures. For 2003 and 2004, cash from operations is
expected to be up to 140% of the Company's projected capital expenditures.
Investing Activities
Cash used in investing was $1.7 billion in 2001, up $603 million when compared
with 2000 after adjusting for the acquisition of FPC. The increase is due
primarily to the expansion of Progress Ventures' generation portfolio and the
absence of proceeds from the sale in 2000 of the BellSouth Carolinas PCS limited
partnership interest.
Capital expenditures for Progress Energy's regulated operations were $1.2
billion or approximately 78% of consolidated capital expenditures in 2001. As
shown in the table below, the Company anticipates that the proportion of
non-regulated capital spending to total capital expenditures will increase
substantially in 2002, primarily due to generation and other additions at
Progress Ventures (See OTHER MATTERS below for a detail of these projects).
Subsequent to 2002, the Company expects its proportion of regulated capital
expenditures to range between 70% and 90% of total capital expenditures.
(Amounts in millions):
Actual Forecasted
------ ------------------------
2001 2002 2003 2004
------ ------ ------ ------
Regulated capital expenditures $1,216 $1,145 $1,043 $1,169
Nuclear fuel expenditures 116 62 108 60
AFUDC (18) (28) (52) (36)
Non-regulated capital expenditures 350 1,033 407 202
------ ------ ------ ------
Total $1,664 $2,212 $1,506 $1,395
====== ====== ====== ======
The table includes expenditures from 2002 through 2004 of approximately
$230 million expected to be incurred at regulated fossil-fueled electric
generating facilities to comply with the Clean Air Act.
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.
47
<PAGE>
Financing Activities
Cash provided by financing activities decreased approximately $3.4 billion
over 2000, primarily due to the November 30, 2000 acquisition of FPC, which
was funded from the sale of short-term commercial paper. This funding was
converted to long-term debt during 2001. Excluding the effect of the
acquisition financing, cash from financing activities increased slightly in
2001 when compared with 2000, primarily due to the expansion of Progress
Energy's non-regulated operations.
In February 2001, Progress Energy issued $3.2 billion of senior unsecured
notes with maturities ranging from three to thirty years. These notes were
issued with a weighted-average coupon rate of 7.06%. Proceeds from the
issuance were used to retire commercial paper and other short-term
indebtedness issued in connection with the FPC acquisition.
In April 2001, CP&L issued $300 million of medium-term notes due 2008 with
a coupon of 6.65%. Proceeds from the issuance were primarily used to retire
commercial paper.
In July 2001, Florida Power issued $300 million of first mortgage bonds due
2011 with a coupon of 6.65%. Proceeds from the issuance were primarily used
to retire commercial paper.
In August 2001, Progress Energy issued 12.65 million shares of common stock
at $40 per share for net proceeds of $488 million. Proceeds from the
issuance were primarily used to retire commercial paper, including amounts
issued in connection with the FPC acquisition.
In October 2001, Progress Energy issued $400 million of senior unsecured
notes due 2008 with a coupon of 5.85% and $400 million of senior secured
notes due 2031 with a coupon of 7.00%. Approximately $600 million of the
proceeds from this issuance were used to retire commercial paper
outstanding at Progress Capital Holdings, Inc. (PCH). PCH is the holding
company for certain non-regulated businesses of FPC. In November 2001, the
Company terminated the PCH commercial paper program.
In November 2001, CP&L redeemed $125 million of 8.55% quarterly income
capital securities at 100% of the principal amount of such securities. The
redemption was funded primarily through the issuance of commercial paper.
In March 2002, Progress Ventures obtained a $440 million bank facility that
will be used exclusively for expansion of its non-regulated generation
portfolio. Borrowings under this facility will be non-recourse to Progress
Energy; however, the Company entered into certain support and guarantee
agreements to ensure performance under generation construction and
operating agreements.
Progress Energy uses interest rate derivative instruments to manage the
fixed and variable rate debt components of its debt portfolio. The
Company's long-term objective is to maintain a debt portfolio mix of
approximately 30 percent variable rate debt with the balance fixed rate. As
of December 31, 2001, Progress Energy's variable rate and fixed rate debt
comprised 15 percent and 85 percent, respectively.
During March 2002, Progress Energy converted $800 million of fixed rate
debt into variable rate debt by executing interest rate derivative
agreements with a group of five banks. This increased the amount of
variable rate debt in its portfolio to 27 percent. Under the terms of the
agreements, Progress Energy will receive a fixed rate of 4.87% and will pay
a floating rate based on three-month LIBOR. These instruments were
designated as fair value hedges for accounting purposes.
As a registered holding company under PUHCA, Progress Energy obtains
approval from the SEC for the issuance and sale of securities as well as
the establishment of intracompany extensions of credit. In January 2002,
Progress Energy requested an increase of $2.5 billion in its authority to
issue long-term securities, increasing the limit from $5 billion to $7.5
billion. Upon the approval of this increase, Progress Energy will have
authority to issue approximately $3 billion of long-term securities.
At December 31, 2001, the Company and its subsidiaries had committed lines
of credit totaling $1.945 billion. These lines of credit support the
Company's commercial paper borrowings. The following table summarizes the
Company's credit facilities:
48
<PAGE>
Subsidiary Description Short-term Long-term Total
- ------------------------------------------------------------------------------
Progress Energy 364-Day $550 $ -- $ 550
Progress Energy 3-Year (3 years remaining) -- 450 450
CP&L 364-Day -- 200 200
CP&L 5-Year (2 years remaining) -- 375 375
Florida Power 364-Day 170 -- 170
Florida Power 5-Year (2 years remaining) -- 200 200
-------------------------------
$720 $1,225 $1,945
===============================
The Company's financial policy precludes issuing commercial paper in excess
of its supporting lines of credit. At December 31, 2001, the total amount
of commercial paper outstanding was $942 million, leaving approximately $1
billion available for issuance. The Company is required to pay minimal
annual commitment fees to maintain its credit facilities.
In addition, these credit agreements contain various terms and conditions
that could affect the Company's ability to borrow under these facilities.
These include a maximum debt to total capital ratio, a material adverse
change clause and a cross-default provision.
All of the credit facilities include a maximum total debt to total capital
ratio. As of December 31, 2001, the calculated ratio for these three
companies, pursuant to the terms of the agreement, was as follows:
- ------------------------------------------------------
Company Maximum Ratio Actual Ratio
- ------------------------------------------------------
Progress Energy, Inc. 70% 63.1%
CP&L 65% 53.2%
Florida Power 65% 44.6%
- ------------------------------------------------------
Progress Energy's and Florida Power's credit facilities include a provision
under which lenders could refuse to advance funds in the event of a
material adverse change in the borrower's financial condition. CP&L's
credit facilities do not contain this provision.
Each of these credit agreements contains a cross-default provision for
defaults of indebtedness in excess of $10 million. Under these provisions,
if the applicable borrower or certain subsidiaries fail to pay various debt
obligations in excess of $10 million the lenders could accelerate payment
of any outstanding borrowing and terminate their commitments to the credit
facility.
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, not its subsidiaries. In the event that these provisions are
triggered, debt holders could accelerate the payment of approximately $4
billion in long-term debt.
The Company has on file with the SEC a shelf registration statement under
which senior notes, junior debentures, common and preferred stock and other
trust preferred securities are available for issuance by the Company. As of
December 31, 2001, the Company had $500 million available under this shelf
registration. In 2002, the Company filed an additional shelf registration
with the SEC and now has approximately $2.5 billion of senior notes, junior
debentures, common and preferred stock and other trust preferred securities
available for issuance.
Florida Power and PCH have two uncommitted bank bid facilities authorizing
them to borrow and re-borrow, and have loans outstanding at any time, up to
$100 million and $300 million, respectively. At December 31, 2001, there
were no outstanding loans against these facilities.
CP&L currently has on file with the SEC a shelf registration statement
under which it can issue up to $1 billion of various long-term securities.
Florida Power currently has filed registration statements under which it
can issue an aggregate of $700 million of various long-term debt
securities.
The following table shows Progress Energy's capital structure as of
December 31, 2001 and 2000:
2001 2000
---- ----
Common Stock 36.7% 34.9%
Preferred Stock 0.6% 0.6%
Total Debt 62.7% 64.5%
49
<PAGE>
The amount and timing of future sales of Company securities will depend on
market conditions, operating cash flow, asset sales and the specific needs
of the Company. The Company may from time to time sell securities beyond
the amount needed to meet capital requirements in order to allow for the
early redemption of long-term debt, the redemption of preferred stock, the
reduction of short-term debt or for other general corporate purposes.
Credit Ratings
As of December 31, 2001, the major credit rating agencies rated the
Company's securities as follows:
Moody's
-------
Investors Service Standard and Poor's
----------------- -------------------
Progress Energy, Inc.
Corporate Credit Rating Baa1 BBB+/A-2
Senior Unsecured Baa1 BBB
Commercial Paper P-2 A-2
Carolina Power & Light Company
Corporate Credit Rating Baa1 BBB+
Commercial Paper P-2 A-2
Senior Secured Debt A3 BBB+
Senior Unsecured Debt Baa1 BBB+
Subordinate Debt Baa2 BBB
Preferred Stock Baa3 BBB-
Florida Power Corporation
Corporate Credit Rating A2 BBB+/A-2
Commercial Paper P-1 A-2
Senior Secured Debt A1 BBB+
Senior Unsecured Debt A2 BBB+
Preferred Stock Baa1 BBB-
FPC Capital I
Preferred Stock* A3 BBB-
Progress Capital Holdings, Inc.
Senior Unsecured Debt* A3 BBB
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no
assurances can be given that these ratings will continue for any given
period of time. However, the Company monitors its financial condition as
well as market conditions that could ultimately affect its credit ratings.
The Company is committed to maintaining its current credit ratings.
Neither the Company's debt indentures nor its credit agreements contain any
"ratings triggers" which would cause the acceleration of interest and
principal payments in the event of a ratings downgrade. However, in the
event of a downgrade the Company and/or its subsidiaries may be subject to
increased interest costs on the credit facilities backing up the commercial
paper programs. The Company and its subsidiaries have certain contracts
which have provisions that are triggered by a ratings downgrade. These
contracts include counterparty trade agreements, derivative contracts and
various types of third party purchase agreements. None of these contracts
would require any action on the part of Progress Energy or its subsidiaries
unless the ratings downgrade results in a rating below investment grade.
50
<PAGE>
Future Commitments
The following tables reflect Progress Energy's contractual cash obligations
and other commercial commitments in the respective periods in which they
are due.
<TABLE>
<CAPTION>
Contractual Cash Total Amounts
Obligations Committed 2002 2003 2004 2005 2006 Thereafter
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term debt $10,261 $ 688 $ 698 $1,319 $ 348 $ 909 $ 6,299
Capital Lease 53 4 4 4 4 4 33
Obligations
Operating Leases 308 52 66 50 30 22 88
Purchase Obligations 498 498 -- -- -- -- --
Fuel 5,620 1,459 1,200 993 942 944 82
Purchased Power 7,525 384 391 380 393 404 5,573
- ----------------------------------------------------------------------------------------------
Total $24,265 $3,085 $2,359 $2,746 $1,717 $2,283 $12,075
</TABLE>
<TABLE>
<CAPTION>
Other Commercial Total Amounts
Commitments Committed 2002 2003 2004 2005 2006 Thereafter
- ------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Standby Letters of $ 29 $29 $-- $-- $-- $-- $ --
Credit
Guarantees and Other 245 31 28 25 22 20 119
Commitments
- ------------------------------------------------------------------------------------
Total $274 $60 $28 $25 $22 $20 $119
</TABLE>
Information on the Company's contractual obligations at December 31, 2001,
is included in the notes to the Progress Energy consolidated financial
statements. Future debt maturities and lease obligations are included in
Note 6 and Note 10, respectively. The Company's fuel, purchased power and
purchase obligations are included in Note 20A and Note 20B to the Progress
Energy consolidated financial statements.
FUTURE OUTLOOK
- --------------
The results of operations for the past three years are not necessarily
indicative of future earnings potential. The level of Progress Energy's
future earnings depends on numerous factors. See SAFE HARBOR FOR
FORWARD-LOOKING STATEMENTS for a discussion of factors to be considered
with regard to forward-looking statements.
The traditional business of the electric and gas utilities is providing
electricity and natural gas to customers within their service areas in the
Carolinas and Florida. Prices for electricity and natural gas provided to
retail customers are set by the state regulatory commissions under
cost-based regulatory principles. See Note 13 to the Progress Energy
consolidated financial statements for additional information about these
and other regulatory matters.
Future earnings for the electric and gas utilities will depend upon growth
in electric energy and gas sales, which is subject to a number of factors.
These factors include weather, customer growth, competition, energy
conservation practiced by customers, the elasticity of demand and the rate
of economic growth in the traditional service area.
Regulatory issues facing Progress Energy are discussed in the "Current
Regulatory Environment" discussion under OTHER MATTERS below.
Progress Energy's longer-term strategic focus will encompass four lines of
business: Upstream Energy, Transmission, Downstream Energy and Telecom. In
support of these strategic lines of business, credit quality and a strong
balance sheet will remain a priority. The Company will strive to reduce
consolidated leverage through asset divestitures, synergy realization, and
controlled capital spending. Progress Energy's legal structure is not
currently aligned with the future functional management of these lines of
business. Whether, and when, the legal and functional structures will
converge depends upon legislative and regulatory action, which cannot
currently be anticipated.
Upstream Energy will focus on both regulated and non-regulated generation
expansion, energy marketing and trading, and fuel extraction, manufacturing
and delivery. The Energy Supply function of Upstream Energy will manage our
regulated and non-regulated generation fleet. The Company will continue to
prepare for deregulation as it grows Progress Energy's generation fleet.
Additional generation capacity is planned to serve the growth expected in
the Company's service territories, to increase capacity reserve margins at
the regulated subsidiaries, and to take advantage of merchant generation
opportunities.
51
<PAGE>
The Progress Ventures business unit of Upstream Energy will manage the
Company's competitive energy businesses and certain functions on behalf of
the utilities, including wholesale contracts and fuel procurement.
Non-regulated generation opportunities will be focused in the Southeast.
Progress Ventures expects to have 3,100 MW of merchant generation by the
end of 2003 and flexible plans are in place for an additional 2,800 MW of
merchant generation subsequent to 2003. The energy marketing and trading
activities include 5,300 MW of wholesale contracts currently, primarily on
behalf of the utilities, and will include additional contracts for
non-regulated generation in the future.
Transmission will focus on meeting FERC's commitment for regional
transmission organizations ("RTO"). The Company has already participated in
the preliminary development of the GridSouth RTO with Duke Energy and South
Carolina Electric and Gas and the GridFlorida RTO with Florida Power &
Light and Tampa Electric. Progress Energy continues to assess the
structural options that may be available to optimize the value of the
Company's transmission assets. Please refer to the "Current Regulatory
Environment" section under OTHER MATTERS below for further discussion of
transmission and the Company's compliance with FERC Order No. 2000.
Downstream Energy will focus on both the distribution and retail components
and will continue to deliver a high level of customer service while
offering products and services, both regulated and non-regulated, to the
Company's customers. Progress Energy will continue to grow its customer
base and focus on value-added services and technologies to enhance customer
relationships. Downstream Energy will operate within the electric utilities
as an integrated delivery business until any potential restructuring of the
utility business occurs.
Telecom will transport voice and data for major carriers, and will focus
its expansion on the "local loop" within the Company's existing service
territories. While Telecom's long-haul backbone is essentially complete, it
will continue its metro expansion into second and third tier cities and
provide customers in those areas with access to the world's primary
telecommunication centers on the East Coast.
Compliance costs related to current and future environmental laws and
regulations could affect earnings if such costs are not fully recovered.
The Clean Air Act and other important environmental items are discussed in
"Environmental Matters" under OTHER MATTERS below.
As regulated entities, both electric utilities and the gas utility are
subject to the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, the utilities record certain assets and liabilities resulting
from the effects of the ratemaking process, which would not be recorded
under generally accepted accounting principles for non-regulated 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 utilities' operations,
related regulatory assets and liabilities would be eliminated unless an
appropriate regulatory recovery mechanism is provided. Additionally, these
factors could result in an impairment of utility plant assets as determined
pursuant to SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of." Effective January 1,
2002, the Company adopted SFAS No. 144, which supersedes SFAS No. 121 (See
Note 1L).
OTHER MATTERS
- -------------
Progress Ventures - Generation
In July 2001, Progress Ventures announced that it is building a plant to
include two 160 MW combustion turbine peaking generators at a site in
DeSoto County, Florida, about 50 miles east of Sarasota. Plant capacity has
been sold to another utility through May 2005. Environmental permits and
zoning have been approved for the plant site, and construction is under
way. The plant is expected to be completed in June 2002.
In June 2001, the NCUC held a hearing concerning Progress Energy's
application to transfer certificates granted for generating units in Rowan
County, N.C., from the regulated electric utility, CP&L, to Progress
Ventures. In October 2001, the NCUC approved the transfer of three
combustion turbine generators and related generation infrastructure at the
Rowan County facility from CP&L to Progress Ventures. These assets were
transferred in February 2002. The generating units were completed in May
2001 and the majority of their output is sold under long-term wholesale
contracts.
During February 2002, Progress Ventures, Inc. completed the acquisition of
two electric generating projects totaling nearly 1,100 megawatts in Georgia
from LG&E Energy Corp., a subsidiary of Powergen plc, for a total cash
consideration of $345 million. The two projects consist of 1) the Walton
project in Monroe, Georgia, a 460 MW natural gas-fired plant placed in
service in June 2001 and 2) the Washington project in Washington County,
Georgia,
52
<PAGE>
a planned 600 MW natural gas-fired plant expected to be operational by June
2003. The transaction included a power purchase agreement with LG&E
Marketing for both projects through December 31, 2004. In addition, there
is a project management completion agreement with LG&E whereby Progress
Ventures assumed certain liabilities to facilitate buildout of the
Washington project. The estimated costs to complete the Washington project
are approximately $165 million.
Progress Ventures - Fuel Acquisition
On January 11, 2002, Progress Energy announced that it had entered into a
letter of intent with Westchester Gas Company to acquire approximately 215
producing natural gas wells, 52 miles of intrastate gas pipeline and 170
miles of gas-gathering systems. The properties are located within a 25-mile
radius of Jonesville, Texas, on the Texas-Louisiana border. This will add
140 billion cubic feet (Bcf) of gas reserves to Progress Ventures' fuel
business, which more than doubles its gas reserves and potential annual
production levels. Total consideration of $153 million is expected to
include $135 million in Company common stock and $18 million in cash. This
transaction is expected to be completed in the first half of 2002.
Natural Gas Activities
The Eastern North Carolina Natural Gas Co. (EasternNC) is a corporation
formed equally between the Albemarle Pamlico Economic Development
Corporation (APEC) and Progress Energy to build an 850-mile natural gas
pipeline system to serve 14 eastern North Carolina counties. EasternNC has
begun surveying, designing, engineering and environmental permitting for
the first phase of the project. The initial phase consists of about 125
miles of transmission (6- to 12-inch diameter) pipeline and about 75 miles
of distribution (2- to 6-inch diameter) pipe. Construction of the first
phase began in October 2001 and is scheduled to be completed by mid-summer
2002. The entire project is expected to be completed by the end of 2004.
Progress Energy has agreed to fund a portion of the project, currently
estimated to be approximately $22 million. EasternNC plans to obtain
additional capital through funding from general obligation bonds issued by
the State of North Carolina. The NCUC approved $38.7 million from bond
funds for Phase I of the project in July 2000. On March 20, 2001, EasternNC
filed its amended application for approval of the route design for Phases
2-7 of the project and additional bond funds of $149.6 million to construct
this system. By order issued June 7, 2001, the NCUC approved construction
of Phases 2-7 of the project which addresses the remaining counties and
awarded EasternNC an additional $149.6 million in bond funds to finance the
construction of the facilities associated with these phases.
Current Regulatory Environment
General
The Company's electric and gas utility operations in North Carolina, South
Carolina and Florida are regulated by the NCUC, the Public Service
Commission of South Carolina (SCPSC) and the Florida Public Service
Commission (FPSC), respectively. The electric businesses are also subject
to regulation by the Federal Energy Regulatory Commission (FERC), the U.S.
Nuclear Regulatory Commission (NRC) and other federal and state agencies
common to the utility business. In addition, the Company is subject to
regulation by the U.S. Securities and Exchange Commission (SEC) as a
registered holding company under PUHCA. As a result of regulation, many of
the fundamental business decisions, as well as the rate of return the
electric utilities and the gas utility are permitted to earn, are subject
to the approval of governmental agencies.
Electric Industry Restructuring
CP&L and Florida Power continue to monitor progress toward a more
competitive environment and have actively participated in regulatory reform
deliberations in North Carolina, South Carolina and Florida. Movement
toward deregulation in these states has been affected by recent
developments, including developments related to deregulation of the
electric industry in California and other states.
. North Carolina. On January 23, 2001, the Commission on the Future
of Electric Service in North Carolina announced that it would not
recommend any new laws on electricity deregulation to the 2001
session of the North Carolina General Assembly, citing the
commission's determination that more research is needed. The
commission's initial report to the General Assembly, issued on
May 16, 2000, had contained several proposals, including a
recommendation that electric retail competition should begin in
North Carolina by 2006. At its January 23, 2001, meeting, the
commission requested that the NCUC consider regulatory changes to
facilitate the construction of wholesale generation facilities by
private companies, including the elimination of requirements that
such companies provide proof of a committed customer base and
need for
53
<PAGE>
additional power in order to obtain operating licenses. On May
21, 2001, the NCUC adopted a revised rule which streamlined the
certification process for wholesale merchant generating plants.
. South Carolina. The Company expects the South Carolina General
Assembly will continue to monitor the experiences of states that
have implemented electric restructuring legislation.
. Florida. On January 31, 2001, the Florida 2020 Study Commission
voted to forward a "proposed outline for wholesale restructuring"
to the Florida legislature for its consideration in the 2001
session. The wholesale restructuring outline is intended to
facilitate the evolution of a more robust wholesale marketplace
in Florida. On December 11, 2001 the study commission issued its
final report. The report covered a number of issues with
recommendations in the areas of wholesale competition and
reliability, efficiency, transmission infrastructure,
environmental issues and new technologies. A key recommendation
related to wholesale competition and reliability permits the
transfer or sale of existing generation at book value and on a
plant-by-plant basis, with the sale and transfer being at the
discretion of the investor-owned utility. The Florida legislature
did not take any action on the proposed outline or final report
during the 2001 session.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
Florida Retail Rate Proceeding
Florida Power previously operated under an agreement committing several
parties not to seek any reduction in its base rates or authorized return on
equity. That agreement expired on June 30, 2001. During 2001, the FPSC
required Florida Power to submit minimum filing requirements, based on a
2002 projected test year, to initiate a rate proceeding regarding its
future base rates.
On September 14, 2001, Florida Power submitted its required rate filing,
including its revenue requirements and supporting testimony. Florida Power
filed supplemental minimum filing requirements and testimony on November
15, 2001. Hearings were scheduled to begin on March 20, 2002, but were
postponed to accommodate pending settlement negotiations between the
parties.
On March 27, 2002, the parties entered into a Stipulation and Settlement
Agreement (the Agreement) related to retail rate matters. The Agreement is to be
effective from May 1, 2002 through 2005; provided, however, that if Florida
Power's base rate earnings fall below a 10% return on equity, Florida Power may
petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues
from the sale of electricity by $125 million annually through 2005. The
Agreement also provides that Florida Power will operate under a Revenue
Sharing Incentive Plan (the Plan) that establishes revenue caps and sharing
thresholds for the years 2002 through 2005. The Plan provides that retail
base rate revenues between the sharing thresholds and the retail base rate
revenue caps will be divided into two shares - a 1/3 share to be received
by Florida Power's shareholders, and a 2/3 share to be refunded to Florida
Power's retail customers; provided, however, that for the year 2002 only,
the refund to customers will be limited to 67.1% of the 2/3 customer share.
The retail base rate revenue sharing threshold amounts for 2002, 2003, 2004
and 2005 will be $1,296 million, $1,333 million, $1,370 million and $1,407
million, respectively. The Plan also provides that all retail base rate
revenues above the retail base rate revenue caps established for the years
2003, 2004 and 2005 will be refunded to retail customers on an annual
basis. For 2002, the refund to customers will be limited to 67.1% of the
retail base rate revenues that exceed the 2002 cap. The retail base revenue
caps for 2002, 2003, 2004 and 2005 will be $1,356 million, $1,393 million,
$1,430 million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of
Florida Power's Hines Unit 2 and continuing through December 31, 2005,
Florida Power will be allowed to recover through the fuel cost recovery
clause a return on average investment and depreciation expense for Hines
Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel
savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a mid-course
correction of its fuel cost recovery clause to reduce the fuel factor by $50
million for the remainder of 2002. The fuel cost recovery clause will operate as
it normally does, including, but not limited to any additional mid-course
adjustments that may become necessary, and the calculation of true-ups to actual
fuel clause expenses.
54
<PAGE>
During the term of the Agreement, Florida Power will suspend accruals on
its reserves for nuclear decommissioning and fossil dismantlement.
Additionally, for each calendar year during the term of the Agreement,
Florida Power will record a $62.5 million depreciation expense reduction,
and may, at its option, record up to an equal annual amount as an
offsetting accelerated depreciation expense. In addition, Florida Power 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, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan
and expects to achieve a 20% improvement in its annual System Average
Interruption Duration Index by no later than 2004. If this improvement
level is not achieved for calendar years 2004 or 2005, Florida Power will
provide a refund of $3 million for each year the level is not achieved to 10% of
its total retail customers served by its worst performing distribution feeder
lines.
The Agreement also provides that Florida Power will refund to customers $35
million of the $98 million in interim revenues Florida Power has collected
subject to refund since March 13, 2001. No other interim revenues that were
collected during that period will continue to be held subject to refund.
The agreement was filed with the FPSC for approval on March 27, 2002. If
the FPSC approves the Agreement, the new rates will take effect May 1,
2002. Progress Energy cannot predict the outcome of this matter.
Other Retail Rate Matters
See Note 13B to the Progress Energy consolidated financial statements for
additional information on the Company's other retail rate matters.
Regional Transmission Organizations
In October 2000, Florida Power, along with Florida Power & Light Company
and Tampa Electric Company filed with FERC an application for approval of a
regional transmission organization, or RTO, for peninsular Florida,
currently named GridFlorida. On March 28, 2001, FERC issued an order
provisionally granting GridFlorida RTO status and directing the GridFlorida
applicants to make certain changes in the RTO documents and to file such
changes within 60 days. On May 29, 2001, the GridFlorida applicants made
the compliance filing as directed by FERC, but FERC has not yet issued an
order on that compliance filing.
On May 16, 2001, the FPSC initiated dockets to review the prudence of the
GridFlorida applicants' decision to form and participate in the GridFlorida
RTO. The GridFlorida applicants have announced that they will hold
GridFlorida development activities in abeyance. On June 27, 2001, the FPSC
issued an order establishing a two-phase process for addressing these
GridFlorida RTO issues in the context of Florida Power's pending rate case.
In the first phase, the FPSC will address the general issues associated
with the prudence of the GridFlorida RTO on an expedited basis. FPSC
hearings were held in October 2001 on the phase one issues, and the FPSC
issued an order in December 2001. The order states, among other things,
that the GridFlorida applicants acted prudently in moving to establish an
RTO for Florida. However, the order also directs the GridFlorida applicants
to make certain changes to the proposed GridFlorida structure and refile
with the FPSC within 90 days of the order. The GridFlorida applicants made
the required changes to GridFlorida and refiled the application with the
FPSC on March 20, 2002. The second phase will address ratemaking issues and
will be decided as part of the general rate proceeding. Progress Energy
cannot predict the outcome or impact of these matters.
In October 2000, CP&L, along with Duke Energy Corporation and South
Carolina Electric & Gas Company filed with FERC an application for approval
of a for-profit transmission company, currently named GridSouth. On July
12, 2001, FERC issued an order granting GridSouth RTO status and directing
that certain modifications to the RTO documents be made and filed within 90
days.
CP&L has applied to the NCUC and the SCPSC for permission to transfer
operational control of its transmission assets to GridSouth. On June 21,
2001, the Public Staff of the NCUC filed a motion asking the NCUC to hold
the GridSouth docket in abeyance until the U.S. Supreme Court had ruled on
the appeal of FERC's Order No. 888. That appeal addresses the scope of
FERC's jurisdiction over transmission service used to serve retail
customers. The appeal of Order No. 888 was heard by the Court on October 3,
2001, with a decision anticipated in the summer of 2002. The NCUC issued an
order holding that CP&L's and Duke Energy Corporation's petition to
transfer operational control of their transmission assets to GridSouth
shall be held in abeyance pending further order. In February 2002, CP&L and
the other GridSouth applicants withdrew the GridSouth application from the
NCUC and
55
<PAGE>
SCPSC for purposes of making certain revisions to the GridSouth proposal.
The GridSouth applicants plan to refile their application once those
changes have been made. Progress Energy cannot predict the outcome of this
matter.
On July 12, 2001, FERC issued an order requiring certain parties, including
CP&L, Duke Energy Corporation, South Carolina Electric & Gas Company,
Southern Company and Entergy to engage in a mediation to develop a plan for
a single RTO for the Southeast. The GridFlorida applicants and the parties
to the GridFlorida docket before FERC were encouraged to participate, but
were not required to do so. Florida Power and CP&L participated in the
mediation. On September 10, 2001, the presiding administrative law judge of
the mediation submitted a mediation report to FERC. The report, which has
not yet been acted on by FERC, recommended adoption of a for-profit
transmission company RTO model. FERC held a discussion on the mediation
report on November 24, 2001. In January 2002, FERC stated that it would
issue orders on the RTO formations for the Southeast during the first half
of 2002 after the development of a standardized market design for the
wholesale electricity market. Progress Energy cannot predict the outcome of
these matters or the effect that it may have on the GridFlorida proceedings
currently ongoing before the FERC and the FPSC or the GridSouth proceedings
currently ongoing before FERC, the SCPSC or the NCUC.
Franchise Litigation
Five cities, with a total of approximately 36,000 customers, have sued
Florida Power in various circuit courts in Florida. The lawsuits
principally seek 1) a declaratory judgment that the cities have the right
to purchase Florida Power's electric distribution system located within the
municipal boundaries of the cities, 2) a declaratory judgment that the
value of the distribution system must be determined through arbitration,
and 3) injunctive relief requiring Florida Power to continue to collect
from Florida Power's customers and remit to the cities, franchise fees
during the pending litigation, and as long as Florida Power continues to
occupy the cities' rights-of-way to provide electric service,
notwithstanding the expiration of the franchise ordinances under which
Florida Power had agreed to collect such fees. Three circuit courts have
entered orders requiring arbitration to establish the purchase price of
Florida Power's electric distribution facilities within three cities. One
appellate court has held that one city has the right to determine the value
of Florida Power's facilities within the city through arbitration. To date,
no city has attempted to actually exercise the right to purchase any
portion of Florida Power's electric distribution system, nor has there been
any proceeding to determine the value at which such a purchase could be
made. Arbitration has been scheduled for two of the cases in the third
quarter of 2002. Progress Energy cannot predict the outcome of these
matters.
Nuclear
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and
are based on site-specific estimates that include the costs for removal of
all radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by FERC. See Note 1I to the Progress Energy consolidated financial
statements for a discussion of the Company's nuclear decommissioning costs.
On December 21, 2000, CP&L received permission from the NRC to increase its
storage capacity for spent fuel rods in Wake County, North Carolina. The
NRC's decision came two years after CP&L asked for permission to open two
unused storage pools at the Shearon Harris Nuclear Plant (Harris Plant).
The approval means CP&L can complete cooling systems and install storage
racks in its third and fourth storage pools at the Harris Plant.
Orange County, North Carolina appealed the NRC license amendment to expand
spent fuel storage capacity at the Harris Plant. On May 31, 2001, Orange
County filed a petition for review in the U.S. Court of Appeals for the
District of Columbia, and on June 1, 2001, filed a request for stay and
expedition of the case with the court.
On June 29, 2001, U.S. Court of Appeals denied Orange County's motion for a
stay and rejected the request for an expedited schedule for the appeal. The
court is expected to issue a briefing schedule for the case sometime in
early 2002. Progress Energy cannot predict the outcome of this matter.
As required under the Nuclear Waste Policy Act of 1982, CP&L and Florida
Power each entered into a contract with the U.S. Department of Energy (DOE)
under which the DOE agreed to begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required to
sign the same standard contract. See Note 20D2 to the Progress Energy
consolidated financial statements for a discussion of recent spent nuclear
fuel and DOE developments.
Several projects, commonly referred to as power uprate projects, are
currently being evaluated and implemented at CP&L's nuclear facilities to
increase electrical generation output. A power uprate was completed at the
Harris Plant during 2001 and power uprates are in progress at the Brunswick
and Robinson Nuclear Plants, which will be
56
<PAGE>
implemented in phases over the next several years following regulatory
approval. The total increased generation from these projects is estimated
to be approximately 250 megawatts.
In August 2001, the NRC issued Bulletin 2001-01, "Circumferential Cracking
of Reactor Vessel Head Penetration Nozzles," requesting that all
pressurized water reactors (PWR) provide their plans for inspecting the
reactor vessel head for the conditions described in the bulletin. While
performing this inspection, FirstEnergy Corp.'s Davis Besse plant in Ohio
found three penetrations with evidence of leakage and further evidence of
some wastage of the reactor vessel head around two of these penetrations.
As a result of finding the wastage of the vessel head, the NRC issued
Bulletin 2002-01, requesting licensees to assess previous inspections of
the reactor head and determine the potential for the existence of
conditions similar to that found at the Davis Besse plant.
The Progress Energy PWRs have completed the inspections requested by
Bulletin 2001-01. Any indications of leakage have been inspected and
repaired, and no wastage of the reactor vessel head has been observed at
any of the plants. Based on these inspections, responses to Bulletin
2002-01 are being prepared. The Company does not anticipate any adverse
impact from this regulatory action.
Synthetic Fuels
Progress Energy, through its subsidiaries, is a majority owner in five
entities and a minority owner in one entity that own facilities that
produce synthetic fuel, as defined under the Internal Revenue Service Code
(Code). The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 of the Code (Section 29) if
certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. All entities have received private
letter rulings (PLR's) from the Internal Revenue Service (IRS) with respect
to their synthetic fuel operations. The PLR's do not limit the production
on which synthetic fuel tax credits may be claimed.
Should the tax credits be denied on future audits, and Progress Energy
fails to prevail through the IRS or legal process, there could be a
significant tax liability owed for previously taken Section 29 credits,
with a significant impact on earnings and cash flows. In management's
opinion, Progress Energy is complying with all the necessary requirements
to be allowed such credits under Section 29 and believes it is probable,
although it cannot provide certainty, that it will prevail if challenged by
the IRS on any credits taken.
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.
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The lead or sole regulatory agency that is responsible for a
particular former coal tar site depends largely upon the state in which the
site is located. There are several manufactured gas plant (MGP) sites to
which both electric utilities and the gas utility have some connection. In
this regard, both electric utilities and the gas utility, with other
potentially responsible parties, are participating in investigating and, if
necessary, remediating former coal tar sites with several regulatory
agencies, including, but not limited to, the U.S. Environmental Protection
Agency (EPA), the Florida Department of Environmental Protection (FDEP) and
the North Carolina Department of Environment and Natural Resources,
Division of Waste Management (DWM). Although the electric utilities and gas
utility may incur costs at these sites about which it has been notified,
based upon current status of these sites, the Company does not expect those
costs to be material to its consolidated financial position or results of
operations. The Company has accrued amounts to address known costs at
certain of these sites.
Both electric utilities, the gas utility and Progress Ventures are
periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. Although
Progress Energy's subsidiaries may incur costs at the sites about which
they have been notified, based upon the current status of these sites,
Progress Energy does not expect those costs to be material to the
consolidated financial position or results of operations of the Company.
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury
setting forth national caps and emission levels over an extended period of
time. This national multi-pollutant approach would have significant costs
which could be material to the Company's consolidated financial position or
results of operations. Some companies may seek recovery of the related cost
through rate adjustments or similar mechanisms. Progress Energy cannot
predict the outcome of this matter.
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<PAGE>
The EPA has been conducting an enforcement initiative related to a number
of coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both CP&L and Florida Power were asked to provide information to the EPA as
part of this initiative and cooperated in providing the requested
information. The EPA has initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative, some of which have
resulted in settlement agreements calling for expenditures ranging from
$1.0 billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. Progress Energy cannot predict the outcome of this
matter.
In 1998, the EPA published a final rule addressing the issue of regional
transport of ozone. This rule is commonly known as the NOx SIP Call. The
EPA's rule requires 23 jurisdictions, including North Carolina, South
Carolina and Georgia, but not Florida, to further reduce nitrogen oxide
emissions in order to attain a pre-set state NOx emission level by May 31,
2004. CP&L is evaluating necessary measures to comply with the rule and
estimates its related capital expenditures to meet these measures in North
and South Carolina could be approximately $370 million, which has not been
adjusted for inflation. A portion of this amount that is committed to be
spent from 2002 to 2004 is discussed in the "Investing Activities" section
under LIQUIDITY AND CAPITAL RESOURCES above. Increased operation and
maintenance costs relating to the NOx SIP Call are not expected to be
material to Progress Energy's results of operations. Further controls are
anticipated as electricity demand increases. Progress Energy cannot predict
the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals decision. Further litigation
and rulemaking are anticipated. North Carolina adopted the federal
eight-hour ozone standard and is proceeding with the implementation
process. North Carolina has promulgated final regulations, which will
require CP&L to install nitrogen oxide controls under the State's
eight-hour standard. The cost of those controls are included in the cost
estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act, which requires certain sources to make reductions in
nitrogen oxide emissions by May 1, 2003. The final rule also includes a set
of regulations that affect nitrogen oxide emissions from sources included
in the petitions. The North Carolina fossil-fueled electric generating
plants are included in these petitions. Acceptable state plans under the
NOx SIP Call can be approved in lieu of the final rules the EPA approved as
part of the 126 petitions. CP&L, other utilities, trade organizations and
other states participated in litigation challenging the EPA's action. On
May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in
favor of the EPA, which will require North Carolina to make reductions in
nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th
decision rejected the EPA's methodology for estimating the future growth
factors the EPA used in calculating the emissions limits for utilities. In
August 2001, the Court granted a request by CP&L and other utilities to
delay the implementation of the 126 Rule for electric generating units
pending resolution by the EPA of the growth factor issue. The Court's order
tolls the three-year compliance period (originally set to end on May 1,
2003) for electric generating units as of May 15, 2001. On January 16,
2002, the EPA issued a memo to harmonize the compliance dates for the
Section 126 Rule and the NOx SIP Call. The new compliance date for all
affected sources is now May 31, 2004, rather than May 1, 2003, subject to
the completion of the EPA's response to the related court decision on the
growth factor issue. Progress Energy cannot predict the outcome of this
matter.
On November 1, 2001, Progress Energy completed the sale of the Inland
Marine Transportation segment to AEP Resources, Inc. In connection with the
sale, Progress Energy entered into environmental indemnification provisions
covering both unknown and known sites. Progress Energy has recorded an
accrual to cover estimated probable future environmental expenditures.
Progress Energy believes that it is reasonably possible that additional
costs, which cannot be currently estimated, may be incurred related to the
environmental indemnification provision beyond the amounts accrued.
Progress Energy cannot predict the outcome of this matter.
Both electric utilities, the gas utility and Progress Ventures have filed
claims with the Company's general liability insurance carriers to recover
costs arising out of actual or potential environmental liabilities. Some
claims have been settled and others are still pending. While management
cannot predict the outcome of these matters, the outcome is not expected to
have a material effect on the consolidated financial position or results of
operations.
New Accounting Standards
See Note 1L to the Progress Energy consolidated financial statements for a
discussion of the impact of new accounting standards.
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CAROLINA POWER & LIGHT COMPANY
- ------------------------------
The information required by this item is incorporated herein by reference
to the following portions of Progress Energy's Management's Discussion and
Analysis of Financial Condition and Results of Operations, insofar as they
relate to CP&L: RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES;
FUTURE OUTLOOK and OTHER MATTERS.
RESULTS OF OPERATIONS
- ---------------------
Note 1 to the CP&L consolidated financial statements discusses its
significant accounting policies. The most critical accounting policies and
estimates that impact CP&L's financial statements are the economic impacts
of utility regulation, which are described in more detail in Note 8 to the
CP&L consolidated financial statements.
On July 1, 2000, CP&L distributed its ownership interest in the stock of
NCNG, SRS, Monroe Power and Progress Ventures, Inc. to Progress Energy.
Prior to that date, the consolidated operations of CP&L and Progress Energy
were substantially the same. Subsequent to that date, the operations of
these subsidiaries are no longer included in CP&L's results of operations
and financial position.
The results of operations for CP&L and Progress Energy are substantially
the same for 1999. Additionally, the results of operations for the CP&L
Electric segment are identical between CP&L and Progress Energy for all
periods presented. The primary difference between the results of operations
of the CP&L Electric segment and the consolidated CP&L results of
operations for the 1999, 2000 and 2001 comparison period relate to the
non-electric operations.
CP&L's non-electric operations for 2000 include a full year of operations
for Caronet. Therefore, the $121.1 million after-tax gain from the sale of
the BellSouth PCS assets in September 2000 (see Note 2B to the CP&L
consolidated financial statements) is included in CP&L's results of
operations. However, CP&L's other segment only includes six months of
operations for NCNG, SRS, Monroe Power and Progress Ventures, Inc. and
therefore a comparison to the prior period is not meaningful.
CP&L's non-electric operations for 2001 include an after-tax impairment of
$102.4 million for other than temporary declines in CP&L's investment in
Interpath.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
The statement of cash flows for CP&L does not include amounts related to
NCNG, SRS, Monroe Power and Progress Ventures, Inc. after July 1, 2000.
Additionally, the CP&L statement of cash flows does not include any amounts
related to the acquisition of FPC and the issuance of debt to consummate
the transaction.
CP&L's estimated capital requirements for 2002, 2003 and 2004 are $688
million, $676 million and $745 million, respectively, and primarily reflect
construction expenditures to add regulated generation and upgrade existing
facilities.
See Note 5 to the CP&L consolidated financial statements for information on
CP&L's available credit facilities at December 31, 2001, and the discussion
above for Progress Energy under "Financing Activities" for information
regarding CP&L's financing activities.
The following tables reflect CP&L's contractual cash obligations and other
commercial commitments in the respective periods in which they are due.
<TABLE>
<CAPTION>
Contractual Cash Total Amounts
Obligations Committed 2002 2003 2004 2005 2006 Thereafter
- ----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term debt $3,576 $ 600 $268 $300 $300 $ -- $2,108
Capital Lease 33 2 2 2 2 2 23
Obligations
Operating Leases 86 19 14 10 8 6 29
Fuel 1,854 538 403 345 270 286 12
Purchased Power 1,167 95 96 96 96 96 688
- ----------------------------------------------------------------------------------
Total $6,716 $1,254 $783 $753 $676 $390 $2,860
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
Other Commercial Total Amounts
Commitments Committed 2002 2003 2004 2005 2006 Thereafter
- ------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Standby Letters of $5 $ 5 $-- $-- $-- $-- $--
Credit
Guarantees and Other 2 -- -- -- -- -- 2
Commitments
- ------------------------------------------------------------------------------------
Total $7 $ 5 $-- $-- $-- $-- $ 2
</TABLE>
Information on the CP&L's contractual obligations at December 31, 2001, is
included in the notes to the CP&L consolidated financial statements. Future
debt maturities and lease obligations are included in Note 5 and Note 6,
respectively. The Company's fuel and purchased power obligations are
included in Note 15A to the CP&L consolidated financial statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- -------------------------------------------------------------------
PROGRESS ENERGY, INC.
- ---------------------
Market risk represents the potential loss arising from adverse changes in
market rates and prices. Certain market risks are inherent in the Company's
financial instruments, which arise from transactions entered into in the
normal course of business. The Company's primary exposures are changes in
interest rates with respect to its long-term debt and commercial paper, and
fluctuations in the return on marketable securities with respect to its
nuclear decommissioning trust funds. The Company manages its market risk in
accordance with its established risk management policies, which may include
entering into various derivative transactions.
These financial instruments are held for purposes other than trading. The
fair value of the Company's open trading positions was less than $0.2
million at December 31, 2001. The risks discussed below do not include the
price risks associated with non-financial 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 as of December 31, 2001 and 2000,
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,
commercial paper, FPC obligated mandatorily redeemable securities of trust,
and other short-term indebtedness. The tables also include estimates of the
fair value of the Company's interest rate risk sensitive instruments based
on quoted market prices for these or similar issues. For interest-rate
swaps and interest-rate forward contracts, the tables present notional
amounts and weighted-average interest rates by contractual maturity dates.
Notional amounts are used to calculate the contractual cash flows to be
exchanged under the interest-rate swaps and the settlement amounts under
the interest-rate forward contracts.
<TABLE>
<CAPTION>
December 31, 2001
- ----------------- Fair Value
December 31,
2002 2003 2004 2005 2006 Thereafter Total 2001/(a)/
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(Dollars in millions)
Fixed rate long-term debt/(d)/ $ 188 $ 283 $ 869 $ 348 $ 909 $5,379 $7,976 $8,322
Average interest rate 6.38% 6.42% 6.67% 7.39% 6.78% 6.97% 6.90% --
Variable rate long-term debt -- -- -- -- -- $ 620 $ 620 $ 621
Average interest rate -- -- -- -- -- 1.58% 1.58% --
Commercial paper/(b)/ -- $ 415 $ 450 -- -- -- $ 865 $ 865
Average interest rate -- 2.89% 3.02% -- -- -- 2.96% --
Extendible notes $ 500 -- -- -- -- -- $ 500 $ 500
Average interest rate -
variable rate 2.83% -- -- -- -- -- 2.83% --
FPC mandatorily redeemable
securities of trust -- -- -- -- -- $ 300 $ 300 $ 291
Fixed rate -- 7.10% 7.10% --
Interest-rate swaps:
Pay fixed/receive variable/(c)/ $ 500 -- -- -- -- -- $ 500 $(18.5)
</TABLE>
/(a)/ Fair value includes accrued interest
/(b)/ Excludes short-term commercial paper
/(c)/ Receives floating rate based on three-month LIBOR and pays fixed rate
of 7.17%. Designated as a hedge of interest payments on $500 million
of Extendible notes.
/(d)/ In March 2002, $800 million of fixed rate debt was converted into
variable rate debt through interest rate derivative agreements that
receives fixed rate of 4.87% and pays floating rate based on
three-month LIBOR.
61
<PAGE>
<TABLE>
<CAPTION>
December 31, 2001
- ----------------- Fair Value
December 31,
2002 2003 2004 2005 2006 Thereafter Total 2001/(a)/
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(Dollars in millions)
Fixed rate long-term debt $ 184 $ 182 $ 282 $ 368 $ 348 $2,319 $3,683 $3,636
Average interest rate 6.84% 6.45% 6.42% 6.83% 7.40% 7.03% 6.96% --
Variable rate long-term debt -- -- -- -- -- $ 620 $ 620 $ 621
Average interest rate -- -- -- -- -- 4.72% 4.72% --
Commercial paper/(b)/ -- -- $ 986 -- -- -- $ 986 $ 986
Average interest rate -- -- 7.25% -- -- -- 7.25% --
Extendible notes -- $ 500 -- -- -- -- $ 500 $ 500
Average interest rate -
variable rate -- 6.76% -- -- -- -- 6.76% --
FPC mandatorily redeemable
securities of trust -- -- -- -- -- $ 300 $ 300 $ 272
Fixed rate 7.10% 7.10% --
Interest-rate swaps:
Pay fixed/receive variable/(c)/ -- $ 500 -- -- -- -- $ 500 $ (9.1)
Interest rate forward
contracts related to
anticipated long-term debt
issuances/(d)/ $1,125 -- -- -- -- -- $1,125 $(37.5)
</TABLE>
/(a)/ Fair value includes accrued interest
/(b)/ Excludes short-term commercial paper
/(c)/ Receives floating rate based on three-month LIBOR and pays fixed rate
of 7.17%. Designated as a hedge of interest payments on $500 million
of Extendible notes.
/(d)/ Receives floating rate based on three-month LIBOR and pays
weighted-average fixed rates of approximately 6.77%
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 $822.8
million and $812.0 million at December 31, 2001 and 2000, respectively. Of
these amounts, $416.7 million and $411.3 million, respectively, relate to
CP&L. 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.
CVO 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, 2001, the fair value of these CVOs
was $41.9 million. A hypothetical 10% decrease in market price would result
in a $4.2 million decrease in the fair value of the CVOs.
62
<PAGE>
CAROLINA POWER & LIGHT COMPANY
- ------------------------------
The information required by this item is incorporated herein by reference
to the Progress Energy Quantitative and Qualitative Disclosures About
Market Risk insofar as it relates to CP&L.
The following tables provide information as of December 31, 2001 and 2000,
about CP&L's interest rate risk sensitive instruments.
<TABLE>
<CAPTION>
December 31, 2001
- ----------------- Fair Value
December 31,
2002 2003 2004 2005 2006 Thereafter Total 2001/(a)/
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(Dollars in millions)
Fixed rate long-term debt $ 100 $ 7 $ 300 $ 300 -- $1,488 $2,195 $2,274
Average interest rate 6.75% 6.43% 6.87% 7.50% -- 6.88% 6.96% --
Variable rate long-term debt -- -- -- -- -- $ 620 $ 620 $ 621
Average interest rate -- -- -- -- -- 1.58% 1.58% --
Commercial paper -- $ 261 -- -- -- -- $ 261 $ 261
Average interest rate -- 3.10% -- -- -- -- 3.10% --
Extendible notes $ 500 -- -- -- -- -- $ 500 $ 500
Average interest rate -
variable rate 2.83% -- -- -- -- -- 2.83% --
Interest-rate swaps:
Pay fixed/receive variable/(b)/ $ 500 -- -- -- -- -- $ 500 $(18.5)
</TABLE>
/(a)/ Fair value includes accrued interest
/(b)/Receives floating rate based on three-month LIBOR and pays fixed rate
of 7.17%. Designated as a hedge on $500 million of Extendible notes.
<TABLE>
<CAPTION>
December 31, 2001
- ----------------- Fair Value
December 31,
2001 2002 2003 2004 2005 Thereafter Total 2001/(a)/
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(Dollars in millions)
Fixed rate long-term debt -- $ 100 $ 7 $ 300 $ 300 $1,319 $2,026 $1,996
Average interest rate -- 7.17% 6.34% 6.88% 7.50% 7.08% 7.14% --
Variable rate long-term debt -- -- -- -- -- $ 620 $ 620 $ 621
Average interest rate -- -- -- -- -- 4.72% 4.72% --
Commercial paper -- -- $ 486 -- -- -- $ 486 $ 486
Average interest rate -- -- 7.40% -- -- -- 7.40% --
Extendible notes -- $ 500 -- -- -- -- $ 500 $ 500
Average interest rate -
variable rate -- 6.76% -- -- -- -- 6.76% --
Interest-rate swaps:
Pay fixed/receive variable/(b)/ -- $ 500 -- -- -- -- $ 500 $ (9.1)
</TABLE>
/(a)/ Fair value includes accrued interest
/(b)/ Receives floating rate based on three-month LIBOR and pays fixed rate
of 7.17%. Designated as a hedge on $500 million of Extendible notes.
63
<PAGE>
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- ------ --------------------------------------------------------
The following consolidated financial statements, supplementary data and
consolidated financial statement schedules are included herein:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Progress Energy, Inc.
- ---------------------
Independent Auditors' Report - Deloitte & Touche LLP 65
Independent Auditors' Report - KPMG LLP 66
Consolidated Financial Statements - Progress Energy:
Consolidated Statements of Income for the Years Ended December 31, 2001, 2000, and 1999 67
Consolidated Balance Sheets as of December 31, 2001 and 2000 68
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000, and 1999 69
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2001,
2000 and 1999 70
Consolidated Quarterly Financial Data (Unaudited) 70
Notes to Consolidated Financial Statements 71
Carolina Power & Light Company
- ------------------------------
Independent Auditors' Report - Deloitte & Touche LLP 99
Consolidated Financial Statements - CP&L:
Consolidated Statements of Income and Comprehensive Income for the Years Ended
December 31, 2001, 2000, and 1999 100
Consolidated Balance Sheets as of December 31, 2001 and 2000 101
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000
and 1999 102
Consolidated Schedules of Capitalization as of December 31, 2001 and 2000 103
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2001, 2000
and 1999 103
Consolidated Quarterly Financial Data (Unaudited) 103
Notes to Consolidated Financial Statements 104
Consolidated Financial Statement Schedules for the Years Ended December 31,
2001, 2000, and 1999:
II-Valuation and Qualifying Accounts - Progress Energy, Inc. 122
II-Valuation and Qualifying Account - Carolina Power & Light Company 123
</TABLE>
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the
Consolidated Financial Statements or the accompanying Notes to the
Consolidated Financial Statements.
64
<PAGE>
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress
Energy, Inc. and its subsidiaries (the Company) as of December 31, 2001 and
2000, and the related consolidated statements of income, changes in common
stock equity and cash flows for each of the three years in the period ended
December 31, 2001. Our audits also included the financial statement
schedule listed in the Index at Item 8. These financial statements and the
financial statement schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits. We did not
audit the financial statements of Florida Progress Corporation (a
consolidated subsidiary since November 30, 2000) for the year ended
December 31, 2000, which statements reflect total assets constituting 31%
of the related consolidated total assets at December 31, 2000. Those
financial statements were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as it relates to the amounts
included for Florida Progress Corporation as of December 31, 2000, is based
solely on the report of such other auditors.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits and the report of the other auditors provide a reasonable
basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
such financial statements present fairly, in all material respects, the
financial position of the Company at December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion, such 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
February 15, 2002
65
<PAGE>
Independent Auditors' Report
To the Board of Directors of Florida Progress Corporation:
We have audited the consolidated balance sheet and schedule of
capitalization of Florida Progress Corporation and subsidiaries as of
December 31, 2000 (not separately presented herein). These consolidated
financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these consolidated financial
statements based on our audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audit provides a reasonable basis for our opinion.
The consolidated financial statements referred to in the introductory
paragraph have been prepared based on the Company's historical cost basis
and do not include any "push down" of Progress Energy, Inc.'s acquisition
cost basis as a result of Progress Energy, Inc.'s acquisition of the
Company on November 30, 2000.
In our opinion, the consolidated balance sheet and schedule of
capitalization present fairly, in all material respects, the financial
position of Florida Progress Corporation and subsidiaries as of December
31, 2000, in conformity with accounting principles generally accepted in
the United States of America.
/s/KPMG LLP
St. Petersburg, Florida
February 15, 2001
66
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
- ---------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands except per share data) 2001 2000 1999
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $6,556,561 $3,549,821 $3,146,158
Natural gas 321,385 324,499 98,903
Diversified businesses 1,583,513 229,093 119,866
- -------------------------------------------------------------------------------------------------
Total Operating Revenues 8,461,459 4,103,413 3,364,927
- -------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 1,559,998 686,754 581,340
Purchased power 868,078 364,977 365,425
Gas purchased for resale 243,451 250,902 67,465
Other operation and maintenance 1,246,835 823,549 682,407
Depreciation and amortization 1,090,178 754,748 503,105
Taxes other than on income 383,824 165,393 142,741
Diversified businesses 1,825,320 352,992 174,589
- -------------------------------------------------------------------------------------------------
Total Operating Expenses 7,217,684 3,399,315 2,517,072
- -------------------------------------------------------------------------------------------------
Operating Income 1,243,775 704,098 847,855
- -------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 22,206 26,984 10,336
Impairment of investments (164,183) -- --
Gain on sale of assets -- 200,000 --
Other, net (27,018) 12,338 (41,018)
- -------------------------------------------------------------------------------------------------
Total Other Income (Expense) (168,995) 239,322 (30,682)
- -------------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 592,477 237,494 180,676
Other interest charges 110,355 45,459 10,298
Allowance for borrowed funds used during construction (18,019) (20,668) (11,510)
- -------------------------------------------------------------------------------------------------
Total Interest Charges, Net 684,813 262,285 179,464
- -------------------------------------------------------------------------------------------------
Income before Income Taxes 389,967 681,135 637,709
Income Tax Expense (Benefit) (151,643) 202,774 258,421
- -------------------------------------------------------------------------------------------------
Net Income $ 541,610 $ 478,361 $ 379,288
- -------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 204,683 157,169 148,344
- -------------------------------------------------------------------------------------------------
Basic Earnings per Common Share $ 2.65 $ 3.04 $ 2.56
- -------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share $ 2.64 $ 3.03 $ 2.55
- -------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.135 $ 2.075 $ 2.015
- -------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Progress Energy, Inc. consolidated financial statements.
67
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
- ---------------------------
<TABLE>
<CAPTION>
(In thousands, except share amounts) December 31
Assets 2001 2000
- --------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric utility plant in service $ 19,176,021 $ 18,124,036
Gas utility plant in service 491,903 378,464
Accumulated depreciation (10,096,412) (9,350,235)
- --------------------------------------------------------------------------------------------------------
Utility plant in service, net 9,571,512 9,152,265
Held for future use 15,380 16,302
Construction work in progress 1,065,154 1,043,439
Nuclear fuel, net of amortization 262,869 224,692
- --------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 10,914,915 10,436,698
- --------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 54,419 101,296
Accounts receivable 944,753 925,911
Taxes receivable 32,325 --
Inventory 886,747 420,985
Deferred fuel cost 146,652 217,806
Prepayments 36,150 50,040
Assets held for sale, net -- 747,745
Other current assets 226,947 192,347
- --------------------------------------------------------------------------------------------------------
Total Current Assets 2,327,993 2,656,130
- --------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 455,325 613,200
Nuclear decommissioning trust funds 822,821 811,998
Diversified business property, net 1,073,046 729,662
Miscellaneous other property and investments 456,880 598,235
Goodwill, net 3,690,210 3,652,429
Prepaid pension costs 489,600 373,151
Other assets and deferred debits 509,001 239,198
- --------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,496,883 7,017,873
- --------------------------------------------------------------------------------------------------------
Total Assets $ 20,739,791 $ 20,110,701
- --------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- --------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares authorized,
218,725,352 and 206,089,047 shares issued and outstanding, respectively $ 4,121,194 $ 3,621,610
Unearned restricted shares (674,511 and 653,344 shares, respectively) (13,701) (12,708)
Unearned ESOP shares (5,199,388 and 5,782,376 shares, respectively) (114,385) (127,211)
Accumulated other comprehensive loss (32,180) --
Retained earnings 2,042,605 1,942,510
- --------------------------------------------------------------------------------------------------------
Total common stock equity 6,003,533 5,424,201
- --------------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-not subject to mandatory redemption 92,831 92,831
Long-term debt 9,483,745 5,890,099
- --------------------------------------------------------------------------------------------------------
Total capitalization 15,580,109 11,407,131
- --------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 688,052 184,037
Accounts payable 709,906 828,568
Interest accrued 212,387 121,433
Dividends declared 117,857 107,645
Short-term obligations 77,529 3,972,674
Customer deposits 154,343 141,744
Other current liabilities 431,522 306,558
- --------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,391,596 5,662,659
- --------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,434,506 1,807,192
Accumulated deferred investment tax credits 226,382 261,255
Regulatory liabilities 287,138 316,576
Other liabilities and deferred credits 820,060 655,888
- --------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,768,086 3,040,911
- --------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 20)
- --------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 20,739,791 $ 20,110,701
- --------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Progress energy, Inc. consolidated financial statements.
68
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
- -------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2001 2000 1999
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities
Net income $ 541,610 $ 478,361 $ 379,288
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of assets and investments (Note 1J) 208,983 -- --
Depreciation and amortization 1,189,171 846,279 592,001
Deferred income taxes (366,490) (95,366) (32,495)
Investment tax credit (22,895) (18,136) (10,299)
Gain on sale of assets -- (200,000) --
Change in deferred fuel 72,529 (76,704) (39,052)
Net (increase) decrease in accounts receivable 210,871 (122,640) (33,322)
Net (increase) decrease in inventories (295,874) 13,726 (17,576)
Net (increase) decrease in prepaids and other current assets (2,876) 60,727 (117,250)
Net increase (decrease) in accounts payable (273,768) 242,902 24,555
Net increase (decrease) in other current liabilities 129,124 (142,551) 7,436
Other 54,614 (48,920) 75,867
- -------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,444,999 937,678 829,153
- -------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (1,216,481) (950,198) (689,054)
Nuclear fuel additions (115,663) (59,752) (75,641)
Acquisition of Florida Progress Corporation -- (3,461,917) --
Net proceeds from sale of assets 53,010 212,825 --
Contributions to nuclear decommissioning trust (50,649) (32,391) (30,825)
Diversified business property additions (349,670) (157,628) (157,802)
Investments in non-utility activities (110) (89,351) (48,265)
- -------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,679,563) (4,538,412) (1,001,587)
- -------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 488,290 -- --
Issuance of long-term debt 4,564,243 783,052 400,970
Net increase (decrease) in commercial paper reclassified to long-tem debt (121,880) 123,697 268,500
Net increase (decrease) in short-term indebtedness (3,896,182) 3,658,374 70,600
Net increase (decrease) in cash provided by checks drawn in excess of bank balances (45,372) 115,337 (117,643)
Retirement of long-term debt (322,207) (710,373) (113,335)
Dividends paid on common stock (432,078) (368,004) (293,704)
Other (47,127) (66) 6,169
- -------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Financing Activities 187,687 3,602,017 221,557
- -------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (46,877) 1,283 49,123
- -------------------------------------------------------------------------------------------------------------------------------
Increase in Cash from Acquisition (See Noncash Activities) -- 20,142 1,876
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 101,296 79,871 28,872
- -------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 54,419 $ 101,296 $ 79,871
- -------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 588,127 $ 244,224 $ 174,101
income taxes $ 127,427 $ 367,665 $ 284,535
</TABLE>
Noncash Activities
. On July 15, 1999, the Company purchased all outstanding shares of
North Carolina Natural Gas Corporation (NCNG) through the issuance of
approximately $360 million in common stock.
. On June 28, 2000, Caronet, a wholly owned subsidiary of the Company,
contributed net assets in the amount of $93.0 million in exchange for
a 35% ownership interest (15% voting interest) in a newly formed
company.
. On November 30, 2000, the Company purchased all outstanding shares of
Florida Progress Corporation (FPC). In conjunction with the purchase
of FPC, the Company issued approximately $1.9 billion in common stock
and approximately $49.3 million in contingent value obligations.
See Notes to Progress Energy, Inc. consolidated financial statements.
69
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUITY
---------------------------------------------------------
<TABLE>
<CAPTION>
Common Stock Outstanding
Unearned
Unearned ESOP
(In thousands except share data) Restricted Common
Shares Amount Stock Stock
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance, January 1, 1999 151,337,503 $1,382,524 ($8,541) ($152,979)
Net income
Issuance of shares 8,262,147 360,509
Purchase of restricted stock (2,507)
Restricted stock expense recognition 3,110
Allocation of ESOP shares 10,360 12,826
Dividends ($2.015 per share)
- ---------------------------------------------------------------------------------------------
Balance, December 31, 1999 159,599,650 1,753,393 (7,938) (140,153)
Net income
Issuance of shares 46,527,797 1,863,886
Purchase of restricted stock (10,067)
Restricted stock expense recognition 3,671
Cancellation of restricted shares (38,400) (1,626) 1,626
Allocation of ESOP shares 5,957 12,942
Dividends ($2.075 per share)
- ---------------------------------------------------------------------------------------------
Balance, December 31, 2000 206,089,047 3,621,610 (12,708) (127,211)
Net income
FAS 133 transition adjustment (net of
tax of $15,130)
Change in net unrealized losses on cash
flow hedges (net of tax of $13,268)
Foreign currency translation
Reclassification adjustment for amounts
included in net income (net of tax of
$8,739)
Comprehensive income
Issuance of shares 12,658,027 488,592
Purchase of restricted stock (7,992)
Restricted stock expense recognition 6,084
Cancellation of restricted shares (21,722) (915) 915
Allocation of ESOP shares 11,907 12,826
Dividends ($2.135 per share)
- ---------------------------------------------------------------------------------------------
Balance, December 31, 2001 218,725,352 $4,121,194 ($13,701) ($114,385)
=============================================================================================
<CAPTION>
Accumulated Total
Other Common
(In thousands except share data) Comprehensive Retained Stock
Income (Loss) Earnings Equity
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance, January 1, 1999 $ -- $1,728,301 $2,949,305
Net income 379,288 379,288
Issuance of shares 360,509
Purchase of restricted stock (2,507)
Restricted stock expense recognition 3,110
Allocation of ESOP shares 23,186
Dividends ($2.015 per share) (300,244) (300,244)
- -----------------------------------------------------------------------------------
Balance, December 31, 1999 -- 1,807,345 3,412,647
Net income 478,361 478,361
Issuance of shares 1,863,886
Purchase of restricted stock (10,067)
Restricted stock expense recognition 3,671
Cancellation of restricted shares --
Allocation of ESOP shares 18,899
Dividends ($2.075 per share) (343,196) (343,196)
- -----------------------------------------------------------------------------------
Balance, December 31, 2000 -- 1,942,510 5,424,201
Net income 541,610 541,610
FAS 133 transition adjustment (net of
tax of $15,130) (23,567) (23,567)
Change in net unrealized losses on cash
flow hedges (net of tax of $13,268) (20,703) (20,703)
Foreign currency translation
(1,557) (1,557)
Reclassification adjustment for amounts
included in net income (net of tax of
$8,739) 13,647 13,647
-----------
Comprehensive income 509,430
-----------
Issuance of shares 488,592
Purchase of restricted stock (7,992)
Restricted stock expense recognition 6,084
Cancellation of restricted shares --
Allocation of ESOP shares 24,733
Dividends ($2.135 per share) (441,515) (441,515)
- -----------------------------------------------------------------------------------
Balance, December 31, 2001 ($32,180) $2,042,605 $6,003,533
===================================================================================
</TABLE>
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
-------------------------------------------------
<TABLE>
<CAPTION>
(In thousands except per share data) First Quarter Second Quarter Third Quarter (a) Fourth Quarter (a)
(a) (a)
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Year ended December 31, 2001
Operating revenues $1,908,090 $2,315,643 (e) $2,330,547 $1,907,179
Operating income 309,855 284,075 453,518 196,327
Net income 154,003 111,702 366,443 (90,538)(d)
Common stock data:
Basic earnings per common share 0.77 0.56 1.78 (0.43)(d)
Diluted earnings per common share 0.77 0.56 1.77 (0.42)(d)
Dividends paid per common share 0.530 0.530 0.530 0.530
Price per share - high 49.25 45.00 45.79 45.60
Low 38.78 40.36 39.25 40.50
- -------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Operating revenues $ 878,618 $ 887,748 $ 1,064,908 $1,272,139
Operating income 186,588 209,628 277,300 30,582 (c)
Net income 85,261 107,460 297,083 (b) (11,443)(c)
Common stock data:
Basic earnings per common share 0.56 0.70 1.94 (b) (0.07)(c)
Diluted earnings per common share 0.56 0.70 1.93 (b) (0.07)(c)
Dividends paid per common share 0.515 0.515 0.515 0.515
Price per share - high 37.00 38.00 41.94 49.38
Low 28.25 31.00 31.50 38.00
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
(a) 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.
(b) Includes gain on sale of BellSouth Carolinas PCS Partnership interest.
(c) Includes approved further accelerated depreciation of $125 million on
nuclear generating assets.
(d) Includes impairment and other one-time charges relating to SRS and
Interpath of $152.8 million, after tax.
(e) Includes seven months of revenue related to Progress Rail Services due
to reversal of Net Assets Held for Sale accounting treatment.
See Notes to Progress Energy, Inc. consolidated financial statements.
70
<PAGE>
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (the Company) is a registered holding company under
the Public Utility Holding Company Act (PUHCA) of 1935, as amended. Both
the Company and its subsidiaries are subject to the regulatory provisions
of the PUHCA. The Company was formed as a result of the reorganization of
Carolina Power & Light Company (CP&L) into a holding company structure on
June 19, 2000. All shares of common stock of CP&L were exchanged for an
equal number of shares of the Company. On December 4, 2000, the Company
changed its name from CP&L Energy, Inc. to Progress Energy, Inc. Through
its wholly owned subsidiaries, CP&L, Florida Power Corporation (Florida
Power) and North Carolina Natural Gas Corporation (NCNG), the Company is
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina, South Carolina and Florida and
the transport, distribution and sale of natural gas in portions of North
Carolina. Through the Progress Ventures business unit, the Company is
involved in merchant energy generation, coal and synthetic fuel operations
and energy marketing and trading. Through other business units, the Company
engages in other non-regulated business areas, including energy management
and related services, rail services and telecommunications.
The Company's results of operations include the results of Florida Progress
Corporation for the periods subsequent to November 30, 2000, and of North
Carolina Natural Gas Corporation for the periods subsequent to July 15,
1999 (See Note 2).
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
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 rate making process
is probable. The accounting records of CP&L, Florida Power and NCNG
(collectively, "the utilities") are maintained in accordance with uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC), the North Carolina Utilities Commission (NCUC), the Public Service
Commission of South Carolina (SCPSC) and the Florida Public Service
Commission (FPSC). Certain amounts for 2000 and 1999 have been reclassified
to conform to the 2001 presentation.
Unconsolidated investments in companies over which the Company does not
have control, but have the ability to exercise influence over operating and
financial policies (generally, 20% - 50% ownership) are accounted for under
the equity method of accounting. Other investments are stated principally
at cost. These investments, which total approximately $160 million at
December 31, 2001, are included as miscellaneous other property and
investments in the Consolidated Balance Sheets.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with accounting
principles generally accepted in the United States of America, management
must make estimates and assumptions that affect the reported amounts of
assets and liabilities, disclosure of contingent assets and liabilities at
the date of the consolidated financial statements and amounts of revenues
and expenses reflected during the reporting period. Actual results could
differ from those estimates.
D. Inventory
Inventory is carried at average cost. As of December 31, 2001 and 2000,
inventory was comprised of (in thousands):
2001 2000
-------- --------
Fuel $305,858 $150,786
Rail equipment and parts 200,697 --
Materials and supplies 354,587 269,546
Other 25,605 653
-------- --------
Inventory $886,747 $420,985
======== ========
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<PAGE>
E. Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to utility plant. Maintenance and repairs of property,
and replacements and renewals of items determined to be less than units of
property, are charged to maintenance expense. The cost of units of property
replaced, renewed or retired, plus removal or disposal costs, less salvage,
is charged to accumulated depreciation. Subsequent to the acquisitions of
Florida Progress Corporation and NCNG, the utility plants of these entities
continue to be presented on a gross basis to reflect the treatment of such
plant in cost-based regulation. Generally, electric utility plant other
than nuclear fuel is pledged as collateral for the first mortgage bonds of
CP&L and Florida Power. Gas utility plant is not currently pledged as
collateral for such bonds.
The balances of utility plant in service at December 31 are listed below
(in thousands), with a range of depreciable lives for each:
2001 2000
----------- -----------
Electric
Production plant (7-33 years) $10,670,717 $10,014,635
Transmission plant (30-75 years) 2,013,243 1,964,652
Distribution plant (12-50 years) 5,767,788 5,292,134
General plant and other (8-75 years) 724,273 852,615
----------- -----------
Total electric utility plant 19,176,021 18,124,036
Gas plant (10-40 years) 491,903 378,464
----------- -----------
Utility plant in service $19,667,924 $18,502,500
=========== ===========
As prescribed in the regulatory uniform systems of accounts, an allowance
for the cost of borrowed and equity funds used to finance utility plant
construction (AFUDC) is charged to the cost of the plant. 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 equity funds portion of AFUDC is credited to other income and
the borrowed funds portion is credited to interest charges. The total
equity funds portion of AFUDC was $10.9 million, $15.5 million and $3.9
million in 2001, 2000 and 1999, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2%, 8.2% and 6.4% in 2001, 2000 and
1999, respectively. The composite AFUDC rate for Florida Power's electric
utility plant was 7.8% in both 2001 and 2000. The composite AFUDC rate for
NCNG's gas utility plant was 10.09% in 2001, 2000 and 1999.
F. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2001 2000
---------- ---------
Equipment $ 184,353 $ 109,080
Land and mineral rights 154,728 96,803
Buildings and plants 291,550 231,219
Telecommunications equipment 266,603 192,727
Railcars 56,044 --
Marine equipment 78,868 73,289
Computers, office equipment and software 14,150 23,065
Construction work in progress 342,830 234,689
Accumulated depreciation (316,080) (231,210)
---------- ---------
Diversified business property, net $1,073,046 $ 729,662
========== =========
Diversified business property is stated at cost. Depreciation is computed
on a straight-line basis using the following estimated useful lives:
equipment, buildings and plants - 3 to 40 years; telecommunications
equipment - 5 to 20 years; computers, office equipment and software - 3 to
10 years; railcars - 3 to 20 years; and marine equipment - 3 to 35 years.
Depletion of mineral rights is provided on the units-of-production method
based upon the estimates of recoverable amounts of clean mineral.
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G. Depreciation and Amortization
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated net salvage. Depreciation provisions, including decommissioning
costs (See Note 1I) and excluding accelerated cost recovery of nuclear
generating assets, as a percent of average depreciable property other than
nuclear fuel, were approximately 4.0%, 4.1% and 3.9% in 2001, 2000 and
1999, respectively. Total depreciation provisions were $821.2 million,
$721.0 million and $409.6 million in 2001, 2000 and 1999, respectively.
Depreciation and amortization expense also includes amortization of
deferred operation and maintenance expenses associated with Hurricane Fran,
which struck significant portions of CP&L's service territory in September
1996. In 1996, the NCUC authorized CP&L to defer these expenses
(approximately $40 million) with amortization over a 40-month period, which
expired in December 1999.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000 and
continuing through 2004. Also in 2000, CP&L received approval from the
commissions to further accelerate the cost recovery of its nuclear
generation facilities in 2000. The accelerated cost recovery of these
assets resulted in additional depreciation expense of approximately $75
million and $275 million in 2001 and 2000, respectively (See Note 13B).
Pursuant to authorizations from the NCUC and the SCPSC, CP&L accelerated
the amortization of certain regulatory assets over a three-year period
beginning January 1997 and expiring December 1999. The accelerated
amortization of these regulatory assets resulted in additional depreciation
and amortization expenses of approximately $68 million in 1999.
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE) and costs
associated with obligations to the DOE for the decommissioning and
decontamination of enrichment facilities, is computed primarily on the
unit-of-production method and charged to fuel expense. The total of these
costs for the years ended December 31, 2001, 2000 and 1999 were $130.1
million, $114.6 million and $110.8 million, respectively.
Goodwill, the excess of purchase price over fair value of net assets of
businesses acquired, is being amortized on a straight-line basis over
primarily 40 years. Goodwill amortization expense was $96.8 million, $16.7
million, and $4.0 million in 2001, 2000 and 1999, respectively. Accumulated
amortization was $119.0 million and $24.2 million at December 31, 2001 and
2000, respectively. Effective January 1, 2002, goodwill will no longer be
subject to amortization over its estimated useful life, but instead, will
be subject to an annual test for impairment (See Note 1L).
H. Diversified Business Expenses
The major components of diversified business expenses for the years ended
December 31, 2001, 2000 and 1999 are as follows (in thousands):
2001 2000 1999
---------- -------- --------
Cost of sales $1,403,434 $ 80,744 $100,776
Depreciation and amortization 86,741 33,139 17,051
General and administrative expenses 279,115 234,132 56,692
Impairment of assets (Note 1J) 44,800 -- --
Other 11,230 4,977 70
---------- -------- --------
Diversified Business Expenses $1,825,320 $352,992 $174,589
========== ======== ========
I. Decommissioning and Dismantlement Provisions
In the Company's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC, the SCPSC and the FPSC and
are based on site-specific estimates that include the costs for removal of
all radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by FERC. Decommissioning cost provisions, which are included in
depreciation and amortization expense, were $38.5 million, $32.5 million
and $33.3 million in 2001, 2000 and 1999, respectively. In January 2002,
Florida Power received regulatory approval from the FPSC to decrease its
retail provision for nuclear decommissioning from approximately $20.5
million annually to approximately $7.7 million annually, effective January
1, 2001.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were approximately $1.0 billion at both December 31, 2001 and
2000. These costs include amounts retained internally and amounts funded
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<PAGE>
in externally managed decommissioning trusts. Trust earnings increase the
trust balance with a corresponding increase in the accumulated
decommissioning balance. These balances are adjusted for net unrealized
gains and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were
developed in 1998, using 1998 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring shortly after operating license expiration. These estimates, in
1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million
for Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and
$328.1 million for the Harris Plant. The estimates are subject to change
based on a variety of factors including, but not limited to, cost
escalation, changes in technology applicable to nuclear decommissioning and
changes in federal, state or local regulations. The cost estimates exclude
the portion attributable to North Carolina Eastern Municipal Power Agency
(Power Agency), which holds an undivided ownership interest in the
Brunswick and Harris nuclear generating facilities. Operating licenses for
CP&L's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016
for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the
Harris Plant.
Florida Power's most recent site-specific estimate of decommissioning costs
for the Crystal River Nuclear Plant (CR3) was developed in 2000 based on
prompt dismantlement decommissioning. The estimate, in 2000 dollars, is
$490.9 million and is subject to change based on the same factors as
discussed above for CP&L's estimates. The cost estimate excludes the
portion attributable to other co-owners of CR3. CR3's operating license
expires in 2016.
Management believes that the decommissioning costs being recovered through
rates by CP&L and Florida Power, when coupled with reasonable assumed
after-tax fund earnings rates, are currently sufficient to provide for the
costs of decommissioning.
Florida Power maintains a reserve for fossil plant dismantlement. At
December 31, 2001 and 2000, this reserve was approximately $140.5 million
and $134.6 million, respectively, and was included in accumulated
depreciation. The provision for fossil plant dismantlement was previously
suspended per a 1997 FPSC settlement agreement, but resumed mid-2001. The
current annual provision, approved by the FPSC, is $8.8 million.
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" that will impact the
accounting for decommissioning and dismantlement provisions (See Note 1L).
J. Impairment of Long-lived Assets and Investments
SFAS No. 121 " Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to Be Disposed Of" requires review of long-lived assets
and certain intangibles for impairment when events or circumstances
indicate that the carrying value of an asset may not be recoverable. Any
impairment losses are reported in the period in which the recognition
criteria are first applied based on the fair value of the asset. Due to
historical and current year losses at Strategic Resource Solutions, Inc.
(SRS) and the decline in the market value for technology companies, the
Company has evaluated the long-lived assets of SRS. Fair value was
generally determined based on discounted cash flows. As a result of this
review, the Company recorded asset impairments, primarily goodwill, and
other one-time charges totaling $44.8 million on a pre-tax basis during the
fourth quarter of 2001 related to SRS. Asset write-downs resulting from
this review were charged to diversified business expenses on the
Consolidated Statements of Income.
The Company continually reviews its investments to determine whether a
decline in fair value below the cost basis is other-than-temporary.
Effective June 28, 2000, a subsidiary of the Company contributed the net
assets used in its application service provider business to a newly formed
company (Interpath) for a 35% ownership interest (15% voting interest). The
Company obtained a valuation study to assess its investment in Interpath
based on current valuations in the technology sector. As a result, the
Company has recorded investment impairments for other-than-temporary
declines in the fair value of its investment in Interpath. Investment
impairments were also recorded related to certain investments of SRS.
Investment write-downs totaled $164.2 million on a pre-tax basis for the
year ended December 31, 2001.
K. Other Policies
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."
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
74
<PAGE>
through surcharges on customer rates. NCNG is also allowed to recover the
costs of gas purchased for resale through customer rates.
Operations of Progress Rail Services Corporation and certain other
diversified operations are recognized one-month in arrears.
The Company maintains an allowance for doubtful accounts receivable, which
totaled approximately $40.7 million and $28.1 million at December 31, 2001
and 2000, respectively. Long-term debt premiums, discounts and issuance
expenses for the utilities are amortized over the life of the related debt
using the straight-line method. Any expenses or call premiums associated
with the reacquisition of debt obligations by the utilities are amortized
over the remaining life of the original debt using the straight-line
method. The Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents.
L. Impact of New Accounting Standards
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended by SFAS No.
138. SFAS No. 133, as amended, establishes accounting and reporting
standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. SFAS
No. 133 requires that an entity recognize all derivatives as assets or
liabilities in the balance sheet and measure those instruments at fair
value.
As a result of the adoption of SFAS No. 133, the Company recorded a
transition adjustment as a cumulative effect of a change in accounting
principle of $23.6 million, net of tax, which increased accumulated other
comprehensive loss as of January 1, 2001. This amount relates to several
derivatives used to hedge cash flows related to interest on long-term debt
(See Note 14). The net derivative losses will be reclassified into earnings
consistent with hedge designations, primarily over the life of the related
debt instruments, which principally range from three to ten years. The
Company estimates that approximately $15.5 million of the net losses at
December 31, 2001 will be reclassified into earnings during 2002. There was
no transition adjustment affecting the Consolidated Statements of Income as
a result of the adoption of SFAS No. 133.
During the second quarter of 2001, the FASB issued interpretations of SFAS
No. 133 indicating that options in general cannot qualify for the normal
purchases and sales exception, but provided an exception that allows
certain electricity contracts, including certain capacity-energy contracts,
to be excluded from the mark-to-market requirements of SFAS No. 133. The
interpretations were effective July 1, 2001. Those interpretations did not
require the Company to mark-to-market any of its electricity
capacity-energy contracts currently outstanding. In December 2001, the FASB
revised the criteria related to the exception for certain electricity
contracts, with the revision to be effective April 1, 2002. The Company
does not expect the revised interpretation to change its assessment of
mark-to-market requirements for its current contracts. If an electricity or
fuel supply contract in its regulated businesses is subject to
mark-to-market accounting, there would be no income statement effect of the
mark-to-market because the contract's mark-to-market gain or loss will be
recorded as a regulatory asset or liability. Any mark-to-market gains or
losses in its non-regulated businesses will affect income unless those
contracts qualify for hedge accounting treatment.
The application of the new rules is still evolving, and further guidance
from the FASB is expected, which could additionally impact the Company's
financial statements.
Effective January 1, 2002, the Company adopted SFAS No. 141, "Business
Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets."
These statements require that all business combinations initiated after
June 30, 2001 be accounted for using the purchase method of accounting and
clarifies the criteria for recording of other intangible assets separately
from goodwill. Effective January 1, 2002, goodwill is no longer subject to
amortization over its estimated useful life. Instead, goodwill is subject
to at least an annual assessment for impairment by applying a fair-value
based test. This assessment could result in periodic impairment charges.
The Company has not yet determined whether its goodwill is impaired under
the initial impairment test required.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations"
in July 2001. This statement provides accounting requirements for
retirement obligations associated with tangible long-lived assets and is
effective January 1, 2003. This statement requires that the present value
of retirement costs for which the Company has a legal obligation be
recorded as liabilities with an equivalent amount added to the asset cost
and depreciated over an appropriate period. The Company is currently
assessing the effects this statement may ultimately have on the Company's
accounting for decommissioning, dismantlement and other retirement costs.
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<PAGE>
Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." It also supersedes the accounting and reporting provisions of
APB Opinion No. 30, "Reporting the Results of Operations - Reporting the
Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions" related to the disposal
of a segment of a business. Adoption of this statement did not have a
material effect on the Company's financial statements.
2. Acquisitions and Dispositions
A. Florida Progress Corporation
On November 30, 2000, the Company completed its acquisition of Florida
Progress Corporation (FPC) for an aggregate purchase price of approximately
$5.4 billion. The Company paid cash consideration of approximately $3.5
billion and issued 46.5 million common shares valued at approximately $1.9
billion. In addition, the Company issued 98.6 million contingent value
obligations (CVO) valued at approximately $49.3 million (See Note 8). The
purchase price includes $20.1 million in direct transaction costs.
FPC is a diversified, exempt electric utility holding company. Florida
Power, FPC's largest subsidiary is a regulated public utility engaged in
the generation, transmission, distribution and sale of electricity. FPC
also has diversified non-utility operations owned through Progress Capital
Holdings, Inc. Included in diversified operations are Progress Fuels
Corporation, an energy and transportation company, and Progress
Telecommunications Corporation, a wholesale telecommunications service
provider. As of the acquisition date, the primary segments of Progress
Fuels Corporation were energy and related services, rail services and
inland marine transportation.
The acquisition was accounted for using the purchase method of accounting
and, accordingly, the results of operations for FPC have been included in
the Company's consolidated financial statements since the date of
acquisition. Identifiable assets acquired and liabilities assumed have been
recorded at their fair values of $6.7 billion and $4.9 billion,
respectively. The excess of the purchase price over the fair value of the
net identifiable assets and liabilities acquired has been recorded as
goodwill. The goodwill, of approximately $3.6 billion, was being amortized
on a straight-line basis over a period of 40 years. Effective January 1,
2002, goodwill is no longer subject to amortization (See Note 1L).
The fair values of FPC's rate-regulated net assets acquired were considered
to be equivalent to book value since book value represents the amount that
will be recoverable through regulated rates. Initially, the allocation of
the purchase price included estimated amounts expected to be realized from
the sale of FPC's Rail Services ("Rail Services") and Inland Marine
Transportation business segments which were classified as net assets held
for sale. During 2001, the Company announced its intention to retain the
Rail Services segment within the allocation period and, therefore, these
assets were reclassified to operating assets. Accordingly, the Company has
made adjustments to the purchase price allocation to remove Rail Services
from net assets held for sale and reflect the net realizable value from the
disposition of FPC's Inland Marine Transportation business segment (See
Note 4). An SEC order approving the merger requires the Company to divest
of Rail Services and certain immaterial, non-regulated investments of FPC
by November 30, 2003.
The company made adjustments during 2001 to the purchase price allocation
for changes in preliminary assumptions and analyses, based on receipt of
the following additional information:
. final actuarial valuations of pension plan obligations
. proceeds realized from the disposition of assets held for sale
. valuations of non-regulated businesses and individual assets and
liabilities
The original allocation of purchase price included the assumption of
liabilities associated with change in control payments triggered by the
acquisition and executive termination benefits, totaling approximately
$50.8 million. Substantially all change in control and executive
termination payments were paid as of December 31, 2000. During 2000, the
Company began the implementation of a plan to combine operations of the
companies resulting in an original non-executive involuntary termination
cost accrual of approximately $52.2 million. Approximately $41.8 million
was attributable to Florida Power employees and was reflected as part of
the purchase price allocation, while approximately $10.4 million
attributable to the acquiring company's employees was charged to operating
results in 2000. During 2001, the Company finalized the plan to combine
operations of the companies with final termination payments occurring in
2002.
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<PAGE>
The activity for the non-executive involuntary termination costs is
detailed in the table below:
(in millions) 2001
------
Balance at January 1 $ 52.2
Payments (33.1)
Adjustments credited to operating results (4.8)
Adjustments credited to purchase price allocation (6.1)
------
Balance at December 31 $ 8.2
======
Actuarial valuations resulted in adjustments to increase the other
postretirement benefits liability by $16.8 million and the prepaid pension
asset by $283.4 million. These adjustments were substantially offset by the
establishment of a regulatory asset for other postretirement benefits of
approximately $15.9 million and a pension regulatory liability of $258.4
million. In addition, an adjustment increased the supplementary defined
benefit retirement plan liability by $24.4 million.
The following unaudited pro forma combined results of operations have been
prepared assuming the acquisition of FPC had occurred at the beginning of
each period. The pro forma results are provided for information only. The
pro forma results include the effect of 2001 purchase price allocation
adjustments and, therefore, differ from previously reported pro forma
results for the same periods. The results are not necessarily indicative of
the actual results that would have been realized had the acquisition
occurred on the indicated date, nor are they necessarily indicative of
future results of operations of the combined companies.
(in thousands, except per share data) 2000 1999
---------- ----------
Revenues $8,098,356 $7,083,641
Net income 575,112 451,455
Basic earnings per share 2.88 2.32
Diluted earnings per share 2.87 2.32
Average shares - Basic 199,722 194,591
Average shares - Diluted 200,177 194,966
B. North Carolina Natural Gas Corporation
On July 15, 1999, the Company completed the acquisition of NCNG for an
aggregate purchase price of approximately $364 million, resulting in the
issuance of approximately 8.3 million shares. The acquisition was accounted
for as a purchase and, accordingly, the operating results of NCNG were
included in the Company's consolidated financial statements beginning with
the date of acquisition. The excess of the aggregate purchase price over
the fair value of net assets acquired, approximately $240 million, was
recorded as goodwill of the acquired business and is being amortized
primarily over a period of 40 years. Effective January 1, 2002, goodwill
will no longer be subject to amortization (See Note 1L).
C. BellSouth Carolinas PCS Partnership Interest
In September 2000, Caronet, Inc., a wholly owned subsidiary of CP&L, sold
its 10% limited partnership interest in BellSouth Carolinas PCS for $200
million. The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
The Company currently provides services through the following business
segments: CP&L Electric, Florida Power Electric, Progress Ventures, Rail
Services and Other. Prior periods have been restated to reflect the current
operating segments.
FPC's operations are not included in the Company's results of operations
prior to the acquisition date of November 30, 2000.
The CP&L Electric and Florida Power Electric segments are engaged in the
generation, transmission, distribution, and sale of electric energy in
portions of North Carolina, South Carolina and Florida. Electric operations
are subject to the rules and regulations of FERC, the NCUC, the SCPSC and
the FPSC.
The Progress Ventures segment is primarily engaged in merchant energy
generation and coal and synthetic fuel operations. Management reviews the
operations of this segment after allocating energy marketing and trading
activity to Progress Ventures. The energy marketing and trading activity is
currently performed by Progress Ventures on behalf of the regulated
utilities, CP&L and Florida Power, and includes wholesale sales on behalf
of
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<PAGE>
these utilities. Electric wholesale operations are subject to the rules and
regulations of FERC, the NCUC, the SCPSC and the FPSC.
The Rail Services segment operations include railcar repair, rail parts
reconditioning and sales, railcar leasing and sales, providing rail and
track material, and scrap metal recycling.
The Other segment is primarily made up of natural gas, other diversified
businesses and holding company operations, which includes the
transportation, distribution and sale of natural gas in portions of North
Carolina, telecommunication services, energy management services,
miscellaneous non-regulated activities and elimination entries.
For reportable segments presented in the accompanying table, segment income
includes intersegment revenues accounted for at prices representative of
unaffiliated party transactions. Intersegment revenues that are not
eliminated represent natural gas sales to the CP&L Electric and the Florida
Power Electric segments.
<TABLE>
<CAPTION>
Florida
CP&L Power Progress Rail Consolidated
(In thousands) Electric Electric Ventures Services(b) Other Totals
-------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED 12/31/01
Revenues
Unaffiliated $3,343,720 $3,212,841 $ 526,200 $944,985 $ 415,063 $ 8,442,809
Intersegment -- -- 398,228 1,174 (380,752) 18,650
-----------------------------------------------------------------------------
Total Revenues 3,343,720 3,212,841 924,428 946,159 34,311 8,461,459
Depreciation and Amortization 521,910 452,971 40,695 36,053 125,290 1,176,919
Net Interest Charges 241,427 113,707 24,085 40,589 265,005 684,813
Income Taxes 264,078 182,590 (421,559) (6,416) (170,336) (151,643)
Net Income (Loss) 468,328 309,577 201,989 (12,108) (426,176) 541,610
Segment Income (Loss) After Allocation 405,661 285,566 288,667 (12,108) (426,176) 541,610
(a)
Total Segment Assets 8,918,691 4,998,162 1,018,875 602,597 5,201,466 20,739,791
Capital and Investment Expenditures 823,952 323,170 265,183 12,886 141,070 1,566,261
========================================================================================================================
FOR THE YEAR ENDED 12/31/00
Revenues
Unaffiliated $3,308,215 $ 241,606 $ 108,739 $ -- $ 438,956 $ 4,097,516
Intersegment -- -- 15,717 -- (9,820) 5,897
-----------------------------------------------------------------------------
Total Revenues 3,308,215 241,606 124,456 -- 429,136 4,103,413
Depreciation and Amortization 698,633 28,872 17,020 -- 43,362 787,887
Net Interest Charges 221,856 9,777 5,714 -- 24,938 262,285
Income Taxes 227,705 13,580 (109,057) -- 70,546 202,774
Net Income (Loss) 373,764 21,764 39,816 -- 43,017 478,361
Segment Income (Loss) After Allocation 289,724 20,057 125,563 -- 43,017 478,361
(a)
Total Segment Assets 8,839,720 4,997,728 644,234 -- 5,629,019 20,110,701
Capital and Investment Expenditures 805,489 49,805 38,981 -- 302,902 1,197,177
========================================================================================================================
------------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED 12/31/99
Revenues
Unaffiliated $3,146,158 $ -- $ 225 $ -- $ 217,527 $ 3,363,910
Intersegment -- -- -- -- 1,017 1,017
-----------------------------------------------------------------------------
Total Revenues 3,146,158 -- 225 -- 218,544 3,364,927
Depreciation and Amortization 493,938 -- 93 -- 26,125 520,156
Net Interest Charges 183,099 -- -- -- (3,635) 179,464
Income Taxes 275,769 -- 38 -- (17,386) 258,421
Net Income (Loss) 430,295 -- 56 -- (51,063) 379,288
Segment Income (Loss) After 360,821 -- 69,530 -- (51,063) 379,288
Allocation (a)
Total Segment Assets 8,501,273 -- 98,429 -- 894,317 9,494,019
Capital and Investment Expenditures 671,401 -- 90,678 -- 133,042 895,121
========================================================================================================================
</TABLE>
(a) Includes allocation of energy trading and marketing net income managed
by Progress Ventures on behalf of the electric utilities.
(b) Amounts for the year ended December 31, 2001 reflect cumulative
operating results of Rail Services since the acquisition date of November
30, 2000. As of December 31, 2000, the Rail Services segment was included
as Net Assets Held for Sale and therefore no assets are reflected for this
segment as of that date.
Segment totals for depreciation and amortization expense include expenses
related to the Progress Ventures, Rail Services and the Other segment that
are included in diversified business expenses on the Consolidated
Statements of Income. Segment totals for interest expense exclude
immaterial expenses related to the Progress Ventures, Rail Services and the
Other segment that are included in other, net on the Consolidated
Statements of Income.
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<PAGE>
4. Net Assets Held for Sale
The estimated amounts reported for the expected sale of FPC's Rail Services
and Inland Marine Transportation business segments, $679.1 million and
$68.6 million, respectively, were classified as net assets held for sale as
of December 31, 2000. During 2001, the Company announced its intention to
retain the Rail Services segment within the allocation period and,
therefore, reclassified Rail Services' to operating assets. During 2001,
the Company recorded an after-tax charge of $3.2 million reflecting the
reversal of net assets held for sale accounting.
During 2001, the Company completed the sale of the Inland Marine
Transportation segment and related investments to AEP Resources, Inc., a
wholly owned subsidiary of American Electric Power, for a sales price of
$270 million. Of the $270 million purchase price, $230 million was used to
pay early termination of certain off-balance sheet arrangements for assets
leased by the business segment. In connection with the sale, the Company
entered into environmental indemnification provisions covering both known
and unknown sites (See Note 20D).
The Company adjusted the FPC purchase price allocation to reflect a $15.0
million negative net realizable value of the Inland Marine business segment
(See Note 2A). The Company's results of operations exclude Inland Marine
Transportation segment net income of $9.1 million for 2001 and $1.8 million
for the month of December 2000. These earnings were included in the
determination of net realizable value for purchase price allocation. As a
result of the change in net realizable value, the Company recorded interest
expense in 2001, net of tax, of $0.3 million to reverse the interest
allocated during 2000.
5. Related Party Transactions
Prior to the acquisition of FPC, the Company purchased a 90% membership
interest in two synthetic fuel related limited liability companies from a
wholly owned subsidiary of FPC. Interest expense incurred during the
pre-acquisition period was approximately $3.3 million. Subsequent to the
acquisition date, intercompany amounts have been eliminated in
consolidation.
NCNG sells natural gas to both CP&L and Florida Power. For the years ended
December 31, 2001, 2000 and 1999 sales of natural gas to CP&L and Florida
Power that were not eliminated in consolidation were $18.7 million, $5.9
million and $1.0 million, respectively.
The Company and its subsidiaries have guarantees, surety bonds and stand by
letters of credit of approximately $140.0 million at December 31, 2001
relating to prompt performance payments, lease obligations, self-insurance
and other payments subject to certain contingencies. As of December 31,
2001, management does not believe conditions are likely for performance
under these agreements.
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<PAGE>
6. Debt and Credit Facilities
At December 31, 2001 and 2000 the Company's long-term debt consisted of the
following (maturities and weighted-average interest rates as of December
31, 2001):
<TABLE>
<CAPTION>
(in thousands) 2001 2000
------------------------
<S> <C> <C> <C>
Progress Energy, Inc.:
Senior unsecured notes, maturing 2004-2031 6.93% $4,000,000 --
Commercial paper reclassified to long-term debt 3.02% 450,000 --
Unamortized premium and discount, net (29,708) --
------------------------
4,420,292 --
------------------------
Carolina Power & Light Company:
First mortgage bonds, maturing 2003-2023 7.02% 1,800,000 1,800,000
Pollution control obligations, maturing 2009-2024 2.22% 707,800 713,770
Unsecured subordinated debentures, maturing 2025 -- 125,000
Extendible notes, maturing 2002 2.83% 500,000 500,000
Medium-term notes, maturing 2008 6.65% 300,000 --
Commercial paper reclassified to long-term debt 3.10% 260,535 486,297
Miscellaneous notes 6.43% 7,234 8,360
Unamortized premium and discount, net (16,716) (12,407)
------------------------
3,558,853 3,621,020
------------------------
Florida Power Corporation:
First mortgage bonds, maturing 2003-2023 6.83% 810,000 510,000
Pollution control revenue bonds, maturing 2014-2027 6.59% 240,865 240,865
Medium-term notes, maturing 2002-2028 6.73% 449,100 531,100
Commercial paper reclassified to long-term debt 2.54% 154,250 200,000
Unamortized premium and discount, net (2,935) (2,849)
------------------------
1,651,280 1,479,116
------------------------
Florida Progress Funding Corporation (Note 7):
Mandatorily redeemable preferred securities, maturing 2039 7.10% 300,000 300,000
Purchase accounting fair value adjustment (30,413) --
Unamortized premium and discount, net (8,922) --
------------------------
260,665 300,000
------------------------
Progress Capital Holdings:
Medium-term notes, maturing 2002-2008 6.74% 273,000 374,000
Commercial paper reclassified to long-term debt -- 300,000
Miscellaneous notes 7,707 --
------------------------
280,707 674,000
------------------------
Current portion of long-term debt (688,052) (184,037)
------------------------
Total Long-Term Debt, Net $9,483,745 $5,890,099
========================
</TABLE>
At December 31, 2001, the Company had committed lines of credit totaling
$1.945 billion, all of which are used to support its commercial paper
borrowings. The Company is required to pay minimal annual commitment fees
to maintain its credit facilities. The following table summarizes the
Company's credit facilities:
<TABLE>
<CAPTION>
Subsidiary Description Short-term Long-term Total
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Progress Energy 364-Day $550 $ -- $ 550
Progress Energy 3-Year (3 years remaining) -- 450 450
CP&L 364-Day -- 200 200
CP&L 5-Year (2 years remaining) -- 375 375
Florida Power 364-Day 170 -- 170
Florida Power 5-Year (2 years remaining) -- 200 200
-------------------------------
$720 $1,225 $1,945
===============================
</TABLE>
As of December 31, 2001, there were no loans outstanding under these
facilities. CP&L's 364-day revolving credit agreement is considered a
long-term commitment due to an option to convert to a one-year term loan at
the expiration date.
Based on the available balances on the long-term facilities, commercial
paper of approximately $865 million has been reclassified to long-term debt
at December 31, 2001. Commercial paper of approximately $986 million was
reclassified to long-term debt at December 31, 2000. As of December 31,
2001 and 2000, the Company had an
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<PAGE>
additional $78 million and $4 billion, 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, 2001 and 2000 were 2.95% and 7.40%,
respectively.
Florida Power and Progress Capital Holdings, Inc. (Progress Capital),
subsidiaries of FPC, have two uncommitted bank bid facilities authorizing
them to borrow and re-borrow, and have loans outstanding at any time, up to
$100 million and $300 million, respectively. These bank bid facilities were
not drawn as of December 31, 2001.
The combined aggregate maturities of long-term debt for 2002 through 2006
are approximately $688 million, $698 million, $1.3 billion, $348 million,
and $909 million, respectively.
7. FPC-Obligated Mandatorily Redeemable Preferred Securities of a Subsidiary
Holding Solely FPC Guaranteed Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly owned
subsidiary of FPC, issued 12 million shares of $25 par cumulative
FPC-obligated mandatorily redeemable preferred securities (Preferred
Securities) due 2039, with an aggregate liquidation value of $300 million
and a quarterly distribution rate of 7.10%. Currently, all 12 million
shares of the Preferred Securities that were issued are outstanding.
Concurrent with the issuance of the Preferred Securities, the Trust issued
to Florida Progress Funding Corporation (Funding Corp.) all of the common
securities of the Trust (371,135 shares) for $9.3 million. Funding Corp. is
a direct wholly owned subsidiary of FPC.
The Preferred Securities are included in long-term debt on the Consolidated
Balance Sheets (See Note 6). During 2001, an adjustment was recorded to the
book value of the preferred securities resulting from fair value
adjustments recorded under the purchase method of accounting. The fair
value adjustment decreased the carrying value of these securities by $30.5
million.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable
Interest Notes (subordinated notes) due 2039, for a principal amount of
$309.3 million. The subordinated notes and the Notes Guarantee (as
discussed below) are the sole assets of the Trust. Funding Corp.'s proceeds
from the sale of the subordinated notes were advanced to Progress Capital
and used for general corporate purposes including the repayment of a
portion of certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding
Corp. under the subordinated notes (the Notes Guarantee). In addition, FPC
has guaranteed the payment of all distributions required to be made by the
Trust, but only to the extent that the Trust has funds available for such
distributions (Preferred Securities Guarantee). The Preferred Securities
Guarantee, considered together with the Notes Guarantee, constitutes a full
and unconditional guarantee by FPC of the Trust's obligations under the
Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp.
beginning in 2004 at par value plus accrued interest through the redemption
date. The proceeds of any redemption of the subordinated notes will be used
by the Trust to redeem proportional amounts of the Preferred Securities and
common securities in accordance with their terms. Upon liquidation or
dissolution of Funding Corp., holders of the Preferred Securities would be
entitled to the liquidation preference of $25 per share plus all accrued
and unpaid dividends thereon to the date of payment.
8. Contingent Value Obligations
In connection with the acquisition of FPC during 2000, the Company issued
98.6 million CVOs. Each CVO represents the right to receive contingent
payments based on the performance of four synthetic fuel facilities
purchased by subsidiaries of FPC in October 1999. The payments, if any,
would be based on the net after-tax cash flows the facilities generate. The
initial liability recorded at the acquisition date was approximately $49.3
million. The CVO liability is adjusted to reflect market price
fluctuations. The liability, included in other liabilities and deferred
credits, at December 31, 2001 and 2000, was $41.9 million and $40.4
million, respectively.
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<PAGE>
9. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock at December 31, 2001 and 2000 was
issued by its subsidiaries and was not subject to mandatory redemption.
Preferred stock outstanding of subsidiaries consisted of the following (in
thousands, except share data):
<TABLE>
<CAPTION>
2001 2000
-----------------
<S> <C> <C>
Carolina Power & Light Company:
Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
20,000,000 shares, cumulative, $100 par value Serial Preferred Stock
$5.00 Preferred - 236,997 shares outstanding (redemption price $110.00) $24,349 $24,349
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000 10,000
$5.44 Serial Preferred - 249,850 shares outstanding (redemption price$101.00) 24,985 24,985
-----------------
59,334 59,334
-----------------
Florida Power Corporation:
Authorized - 4,000,000 shares, cumulative, $100 par value Preferred Stock;
5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000 shares,
$100 par value Preference Stock
$100 par value Preferred Stock:
4.00% - 39,980 shares outstanding (redemption price $104.25) 3,998 3,998
4.40% - 75,000 shares outstanding (redemption price $102.00) 7,500 7,500
4.58% - 99,990 shares outstanding (redemption price $101.00) 9,999 9,999
4.60% - 39,997 shares outstanding (redemption price $103.25) 4,000 4,000
4.75% - 80,000 shares outstanding (redemption price $102.00) 8,000 8,000
-----------------
$33,497 $33,497
-----------------
Total Preferred Stock of Subsidiaries $92,831 $92,831
=================
</TABLE>
10. 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. Contingent rentals are not
significant. Rent expense (under operating leases) totaled $62.6 million,
$26.8 million and $21.3 million for 2001, 2000 and 1999, respectively.
Assets recorded under capital leases at December 31 consist of (in
thousands):
2001 2000
------- -------
Buildings $27,626 $27,626
Equipment 12,170 9,366
Less: Accumulated amortization (8,975) (8,018)
------- -------
$30,821 $28,974
------- -------
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as
of December 31, 2001 are (in thousands):
<TABLE>
<CAPTION>
Capital Leases Operating Leases
-------------- ----------------
<S> <C> <C>
2002 $ 3,533 $ 52,339
2003 3,533 66,317
2004 3,533 50,245
2005 3,533 30,278
2006 3,459 22,132
Thereafter 35,675 86,265
-------- --------
$ 53,266 $307,576
========
Less amount representing imputed interest (22,445)
--------
Present value of net minimum lease payments
under capital leases $ 30,821
========
</TABLE>
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<PAGE>
The Company is also a lessor of land, buildings, railcars and other types
of properties it owns under operating leases with various terms and
expiration dates. The leased buildings and railcars are depreciated under
the same terms as other buildings and railcars included in diversified
business property. Minimum rentals receivable under noncancelable leases as
of December 31, 2001, are (in thousands):
Amounts
-------
2001 $12,190
2002 7,904
2003 5,591
2004 4,741
2005 3,766
Thereafter 9,222
-------
$43,414
11. 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, 2001 and 2000, there were miscellaneous
investments, consisting primarily of investments in company-owned life
insurance, with carrying amounts of approximately $124.3 million and $187.8
million, respectively, included in miscellaneous other property and
investments. The carrying amount of these investments approximates fair
value due to the short maturity of certain instruments and certain
instruments are presented at fair value. The carrying amount of the
Company's long-term debt, including current maturities, was $10.2 billion
and $6.1 billion at December 31, 2001 and 2000, respectively. The estimated
fair value of this debt, as obtained from quoted market prices for the same
or similar issues, was $10.6 billion and $6.0 billion at December 31, 2001
and 2000, respectively.
External funds have been established as a mechanism to fund certain costs
of nuclear decommissioning (See Note 1I). 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.
12. Common Stock
In August 2001, the Company issued 12.65 million shares of common stock at
$40 per share for net cash proceeds of $488 million. Proceeds from the
issuance were primarily used to retire commercial paper. During 2000 and
1999, the Company issued common stock in conjunction with the FPC and NCNG
acquisitions, respectively (See Note 2).
As of December 31, 2001, the Company had 38,549,922 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. The
Company intends, however, to meet the requirements of these stock plans
with issued and outstanding shares presently held by the Trustee of the
Progress Energy 401(k) Savings and Stock Ownership Plan (previously known
as the Stock Purchase-Savings Plan) or with open market purchases of common
stock shares, as appropriate.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2001,
there were no significant restrictions on the use of retained earnings.
13. Regulatory Matters
A. Regulatory Assets and Liabilities
As regulated entities, the utilities are subject to the provisions of SFAS
No. 71, "Accounting for the Effects of Certain Types of Regulation."
Accordingly, the utilities record certain assets and liabilities resulting
from the effects of the ratemaking process, which would not be recorded
under generally accepted accounting principles for non-regulated 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 is provided. Additionally, these
factors could result in an impairment of utility plant assets as determined
pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (See Note 1L).
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<PAGE>
At December 31, 2001 and 2000, the balances of the utilities' regulatory
assets (liabilities) were as follows (in thousands):
<TABLE>
<CAPTION>
2001 2000
--------- ---------
<S> <C> <C>
Deferred fuel (included in current assets) $ 146,652 $ 217,806
----------------------
Income taxes recoverable through future rates 234,180 228,686
Deferred purchased power contract termination costs 95,326 226,656
Harris Plant deferred costs 32,476 44,813
Loss on reacquired debt 28,931 28,121
Deferred DOE enrichment facilities-related costs (Note 1G) 39,102 46,006
Other postretirement benefits (Note 2A) 12,207 15,670
Other 13,103 23,248
----------------------
Total long-term regulatory assets 455,325 613,200
----------------------
Nuclear maintenance and refueling (346) (10,835)
Defined benefit retirement plan (Note 2A) (234,102) (203,137)
Deferred revenues -- (63,000)
Emission allowance gains (7,494) --
Storm reserve (Note 20C) (35,527) (29,527)
Other (9,669) (10,077)
----------------------
Total long-term regulatory liabilities (287,138) (316,576)
----------------------
Net regulatory assets $ 314,839 $ 514,430
======================
</TABLE>
Except for portions of deferred fuel, all regulatory assets earn a return
or the cash has not yet been expended, in which case, the assets are offset
by liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of CP&L's
nuclear generating assets beginning January 1, 2000, and continuing through
2004. The accelerated cost recovery began immediately after the 1999
expiration of the accelerated amortization of certain regulatory assets
(See Note 1G). Pursuant to the orders, the accelerated depreciation expense
for nuclear generating assets was set at a minimum of $106 million with a
maximum of $150 million per year. In late 2000, CP&L received approval from
the NCUC and the SCPSC to further accelerate the cost recovery of its
nuclear generation facilities by $125 million in 2000. This additional
depreciation allowed CP&L to reduce the minimum accelerated annual
depreciation in 2001 through 2004 to $75 million. The resulting total
accelerated depreciation was $75 million in 2001 and $275 million in 2000.
Recovering the costs of its nuclear generating assets on an accelerated
basis will better position CP&L for the uncertainties associated with
potential restructuring of the electric utility industry.
In compliance with a regulatory order, Florida Power accrues a reserve for
maintenance and refueling expenses anticipated to be incurred during
scheduled nuclear plant outages.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion
of its annual accelerated cost recovery of nuclear generating assets by the
amount of sulfur dioxide (SO2) emission allowance expense. CP&L did not
offset accelerated depreciation expense in 2001 against emission allowance
expense. CP&L is allowed to recover emission allowance expense through the
fuel clause adjustment in its South Carolina retail jurisdiction. Florida
Power is also allowed to recover its emission allowance expenses through
the fuel adjustment clause in its retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. NCNG also agreed to cap its North Carolina margin rates for gas
sales and transportation services, with limited exceptions, through
November 1, 2003. In February 2002, NCNG filed a general rate case with the
NCUC requesting an annual rate increase of $47.6 million, based upon its
completion of major expansion projects. The Company cannot predict the
final outcome of this matter.
In conjunction with the FPC merger, CP&L reached a settlement with the
Public Staff of the NCUC in which it agreed to reduce rates to all of its
non-real time pricing customers by $3 million in 2002, $4.5 million in
2003, $6
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<PAGE>
million in 2004 and $6 million in 2005. CP&L also agreed to write off and
forego recovery of $10 million of unrecovered fuel costs in each of its
2000 NCUC and SCPSC fuel cost recovery proceedings.
At December 31, 2000, Florida Power, with the approval of the FPSC, had
established a regulatory liability to defer $63 million of revenues. In
2001, Florida Power applied the deferred revenues, plus accrued interest,
to offset its regulatory asset related to deferred purchased power
termination costs. In addition, Florida Power recorded accelerated
amortization of $34.0 million to further offset this regulatory asset
during 2001.
Florida Power previously operated under an agreement committing several
parties not to seek any reduction in its base rates or authorized return on
equity. During 2001, the FPSC required Florida Power to submit minimum
filing requirements, based on a 2002 projected test year, to initiate a
rate proceeding regarding its future base rates. The FPSC required that
annual revenues of $98 million be held subject to refund to its customers.
The FPSC may allow Florida Power to reduce the amount subject to refund if
it is successful in recovering certain expenses incurred during 2001.
On September 14, 2001, Florida Power submitted its required rate filing,
including its revenue requirements and supporting testimony. Under the
filing, Florida Power customers would receive a $5 million annual credit
rate for 15 years, or $75 million in total, from net synergies of its
merger with the Company. Additionally, the filing provides that the
regulatory asset (approximately $95 million at December 31, 2001) related
to the purchase of Tiger Bay cogeneration facility in 1997 would be fully
amortized by the end of 2003, which would provide customers with a further
rate reduction of $37 million annually beginning in 2004. Also included in
the filing is an incentive regulatory plan, which would provide for
additional rate reductions through efficiencies derived as a result of
Florida Power's ability to lower the future costs of its utility
operations. Florida Power filed supplemental minimum filing requirements
and testimony on November 15, 2001. Hearings are scheduled to begin March
20, 2002, with a final decision expected in July 2002. The FPSC has
encouraged its staff, Florida Power and other parties to negotiate a
settlement, if possible. The Company cannot predict the outcome or impact
of these matters.
C. Plant-Related Deferred Costs
In 1988 rate orders, CP&L was ordered to remove from rate base and treat as
abandoned plant certain costs related to the Harris Plant. Abandoned plant
amortization related to the 1988 rate orders was completed in 1998 for the
wholesale and North Carolina retail jurisdictions and in 1999 for the South
Carolina retail jurisdiction. Amortization of plant abandonment costs is
included in depreciation and amortization expense and totaled $15.0 million
in 1999.
14. Risk Management Activities and Derivatives Transactions
The Company uses a variety of instruments, including swaps, options and
forward contracts, to manage exposure to fluctuations in commodity prices
and interest rates. Such instruments contain credit risk if the
counterparty fails to perform under the contract. The Company minimizes
such risk by performing credit reviews using, among other things, publicly
available credit ratings of such counterparties. Potential non-performance
by counterparties is not expected to have a material effect on the
consolidated financial position or consolidated results of operations of
the Company.
The Company engages in limited energy trading activities to optimize the
value of electricity and fuel contracts, as well as generating facilities.
These activities are accounted for at fair value.
A. Commodity Derivatives - Non-Trading
The Company enters into certain forward contracts involving cash
settlements or physical delivery that reduce the exposure to market
fluctuations relative to the price and delivery of electric products.
During 2001, 2000 and 1999, the Company principally sold electricity
forward contracts, which can reduce price risk on the Company's available
but unsold generation. While such contracts are deemed to be economic
hedges, the Company no longer designates such contracts as hedges for
accounting purposes; therefore, these contracts are carried on the balance
sheet at fair value, with changes in fair value recognized in earnings.
Gains and losses from such contracts were not material during 2001, 2000
and 1999. Also, the Company did not have material outstanding positions in
such contracts at December 31, 2001 or 2000. Most of the Company's
commodity contracts either are not derivatives pursuant to SFAS No. 133 or
qualify as normal purchases or sales pursuant to SFAS No. 133. Therefore,
such contracts are not recorded at fair value.
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<PAGE>
B. Commodity Derivatives - Trading
The Company from time to time engages in the trading of electricity
commodity derivatives and, therefore, experiences net open positions. The
Company manages open positions with strict policies which limit its
exposure to market risk and require daily reporting to management of
potential financial exposures. When such instruments are entered into for
trading purposes, the instruments are carried on the balance sheet at fair
value, with changes in fair value recognized in earnings. The net results
of such contracts have not been material in any year and the Company did
not have material outstanding positions in such contracts at December 31,
2001 or 2000.
C. Other Derivative Instruments
The Company may from time to time enter into derivative instruments to
hedge interest rate risk or equity securities risk.
The Company has interest rate swap agreements to hedge its exposure on
variable rate debt positions. The agreements, with a total notional amount
of $500 million, were effective in July 2000 and mature in July 2002. Under
these agreements, the Company receives a floating rate based on the
three-month London Interbank Offered Rate (LIBOR) and pays a
weighted-average fixed rate of approximately 7.17%. The fair value of the
swaps was a $18.5 million liability position at December 31, 2001. Interest
rate swaps are carried on the balance sheet at fair value with the
unrealized gains or losses adjusted through other comprehensive income. As
such, payments or receipts on interest rate swap agreements are recognized
as adjustments to interest expense.
During 2000, the Company entered into forward starting swap agreements to
hedge its exposure to interest rates with regard to future issuances of
fixed-rate debt. The fair value of the swaps was a $37.5 million liability
position at December 31, 2000. During February 2001, as part of the
issuance of $3.2 billion of senior unsecured notes, the Company terminated
the forward starting swaps. The Company realized a $45.3 million loss on
these contracts, designated as cash flow hedges, that is deferred through
accumulated other comprehensive loss and amortized over the life of the
associated debt instruments.
The notional amounts of the interest rate swaps 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.
15. Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the
provisions of Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees," and related interpretations as permitted under
SFAS No. 123, "Accounting for Stock-Based Compensation.
A. Employee Stock Ownership Plan
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
Plan (401(k)) for which substantially all full-time non-bargaining unit
employees and certain part-time non-bargaining unit employees within
participating subsidiaries are eligible. Participating subsidiaries within
the Company as of January 1, 2002 were CP&L, NCNG, Florida Power, Progress
Telecom, Progress Fuels (Corporate) and Progress Energy Service Company.
The 401(k), which has Company matching and incentive goal features,
encourages systematic savings by employees and provides a method of
acquiring Company common stock and other diverse investments. The 401(k),
as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that can
enter into acquisition loans to acquire Company common stock to satisfy
401(k) common share needs. Qualification as an ESOP did not change the
level of benefits received by employees under the 401(k). Common stock
acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in
a suspense account. The common 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.
There were 5,199,388 and 5,782,376 ESOP suspense shares at December 31,
2001 and 2000, respectively, with a fair value of $234.1 million and $284.4
million, respectively. ESOP shares allocated to plan participants totaled
14,088,173 and 13,732,670 at December 31, 2001 and 2000, 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
86
<PAGE>
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
and with shares released from the ESOP suspense account. Matching and
incentive cost met with shares released from the suspense account totaled
approximately $18.2 million, $15.6 million and $16.3 million for the years
ended December 31, 2001, 2000 and 1999, respectively. The Company has a
long-term note receivable from the 401(k) Trustee related to the purchase
of common stock from the Company in 1989. The balance of the note
receivable from the 401(k) Trustee is included in the determination of
unearned ESOP common stock, which reduces common stock equity. ESOP shares
that have not been committed to be released to participants' accounts are
not considered outstanding for the determination of earnings per common
share. Interest income on the note receivable and dividends on unallocated
ESOP shares are not recognized for financial statement purposes.
B. Stock Option Agreements
Pursuant to the Company's 1997 Equity Incentive Plan, Amended and Restated
as of September 26, 2001, the Company may grant options to purchase shares
of common stock to officers and eligible employees. Generally, options
granted vest one-third per year with 100 percent vesting at the end of year
three. 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. In October 2001, a grant of
approximately 2.4 million options was made at an exercise price of $43.49.
There has been no other significant stock option activity.
Compensation cost is measured for stock options as the difference between
the market price of the Company's common stock and the exercise price of
the option at the grant date. Accordingly, no compensation expense has been
recognized for the stock option granted.
Pro forma information regarding net income and earnings per share is
required by SFAS No. 123. Under this statement, compensation cost is
measured at the grant date based on the fair value of the award and is
recognized over the vesting period. The pro forma amounts 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:
2001
-----
Risk-free interest rate (%) 4.83%
Dividend yield (%) 5.21%
Volatility factor (%) 26.47%
Weighted-average expected life of the options (in years) 10
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 weighted-average fair value
of stock options granted during 2001 was approximately $8.00.
For purposes of the pro forma disclosures required by SFAS No. 123, the
estimated fair value of the options is amortized to expense over the
options vesting period. Compensation expense would have been $2.9 million
in 2001 under SFAS No. 123. The Company's pro forma information is as
follows (in thousands, except per share data):
2001
--------
Net income:
As reported $541,610
Pro forma $539,845
Basic earnings per common share:
As reported $ 2.65
Pro forma $ 2.64
Diluted earnings per common share:
As reported $ 2.64
Pro forma $ 2.63
The effects of applying SFAS No. 123 in this pro forma disclosure are not
likely to be representative of effects on reported net income for future
years.
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<PAGE>
The number of options outstanding as of December 31, 2001, was 2.3 million
with a weighted-average remaining contractual life of 9.75 years and a
weighted-average exercise price of $43.49. No options were exercisable as
of December 31, 2001.
C. Other Stock-Based Compensation Plans
The Company has additional compensation plans for officers and key
employees of the Company that are stock-based in whole or in part. The two
primary programs are the Performance Share Sub-Plan (PSSP) and the
Restricted Stock Awards program (RSA), both of which were established
pursuant to the Company's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares that vest over a three-year consecutive period.
Each performance share has a value that is equal to, and changes with, the
value of a share of the Company's common stock, and dividend equivalents
are accrued on, and reinvested in, the performance shares. The PSSP has two
equally weighted performance measures, both of which are based on the
Company's results as compared to a peer group of utilities. Compensation
expense is recognized over the vesting period based on the expected
ultimate cash payout. Compensation expense is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to
officers and key employees of the Company. The restricted shares 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 $41.86, $36.97 and $37.63 in 2001, 2000 and
1999, 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:
2001 2000 1999
------- ------- -------
Beginning balance 653,344 331,900 265,300
Granted 113,651 359,844 66,600
Vested (21,722) -- --
Forfeited (70,762) (38,400) --
----------------------------------------
Ending balance 674,511 653,344 331,900
========================================
The total amount expensed for other stock-based compensation plans was
$14.3 million, $15.6 million and $2.2 million in 2001, 2000 and 1999,
respectively.
16. Postretirement Benefit Plans
The Company and some of its subsidiaries have a non-contributory defined
benefit retirement (pension) plan for substantially all full-time
employees. The Company also has supplementary defined benefit pension plans
that provide benefits to higher-level employees.
The components of net periodic pension benefit for the years ended December
31 are (in thousands):
2001 2000 1999
--------- -------- --------
Expected return on plan assets $(169,329) $(87,628) $(75,124)
Service cost 31,863 22,123 20,467
Interest cost 96,200 56,924 46,846
Amortization of transition obligation 125 125 106
Amortization of prior service benefit (1,325) (1,314) (1,314)
Amortization of actuarial gain (4,989) (5,721) (3,932)
--------- -------- --------
Net periodic pension benefit $ (47,455) $(15,491) $(12,951)
========= ======== ========
In addition to the net periodic benefit reflected above, in 2000 the
Company recorded a charge of approximately $21.5 million to adjust one of
its supplementary defined benefit pension plans. The effect of the
adjustment for this plan is reflected in the actuarial loss (gain) line in
the pension obligation reconciliation below.
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<PAGE>
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the pension obligation
or the market-related value of assets are amortized over the average
remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
<TABLE>
<CAPTION>
2001 2000
---------- ----------
<S> <C> <C>
Pension obligation at January 1 $1,376,859 $ 688,124
Interest cost 96,200 56,924
Service cost 31,863 22,123
Benefit payments (86,010) (55,291)
Actuarial loss (gain) 13,164 39,798
Plan amendments 20,882 --
Acquisitions (acquisition adjustment) (62,221) 625,181
---------- ----------
Pension obligation at December 31 $1,390,737 $1,376,859
Fair value of plan assets at December 31 1,677,630 1,843,410
---------- ----------
Funded status $ 286,893 $ 466,551
Unrecognized transition obligation 370 495
Unrecognized prior service cost (benefit) 5,346 (16,861)
Unrecognized actuarial loss (gain) 111,600 (158,541)
---------- ----------
Prepaid (accrued) pension cost at December 31, net $ 404,209 $ 291,644
========== ==========
</TABLE>
The net prepaid pension cost of $404.2 million at December 31, 2001 is
recognized in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $489.6 million and accrued benefit cost of $85.4 million,
which is included in other liabilities and deferred credits. The net
prepaid pension cost of $291.6 million at December 31, 2000 is recognized
in the accompanying Consolidated Balance Sheets as prepaid pension cost of
$373.2 million and accrued benefit cost of $81.6 million, which is included
in other liabilities and deferred credits. The aggregate benefit obligation
for those plans where the accumulated benefit obligation exceeded the fair
value of plan assets was $85.4 million and $83.6 million at December 31,
2001 and 2000, respectively, and those plans have no plan assets.
Reconciliations of the fair value of pension plan assets are (in
thousands):
<TABLE>
<CAPTION>
2001 2000
---------- ----------
<S> <C> <C>
Fair value of plan assets at January 1 $1,843,410 $ 947,143
Actual return on plan assets (84,254) 24,840
Benefit payments (86,010) (55,291)
Employer contributions 4,484 1,329
Acquisitions -- 925,389
---------- ----------
Fair value of plan assets at December 31 $1,677,630 $1,843,410
========== ==========
</TABLE>
The weighted-average discount rate used to measure the pension obligation
was 7.5% in 2001 and 2000. The weighted-average rate of increase in future
compensation for non-bargaining unit employees used to measure the pension
obligation was 4.0% in 2001 and 2000 and 4.2% in 1999. The corresponding
rate of increase in future compensation for bargaining unit employees was
3.5% in 2001 and 2000. The expected long-term rate of return on pension
plan assets used in determining the net periodic pension cost was 9.25% in
2001, 2000 and 1999.
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.
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<PAGE>
The components of net periodic OPEB cost for the years ended December 31 are (in
thousands):
2001 2000 1999
------- ------- -------
Expected return on plan assets $(4,651) $(4,045) $(3,378)
Service cost 13,231 10,067 7,936
Interest cost 28,414 15,446 13,914
Amortization of prior service cost 319 107 --
Amortization of transition obligation 4,701 5,878 5,760
Amortization of actuarial gain (592) (819) (1)
------- ------- -------
Net periodic OPEB cost $41,422 $26,634 $24,231
======= ======= =======
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the OPEB obligation or
the market-related value of assets are amortized over the average remaining
service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2001 2000
--------- ---------
OPEB obligation at January 1 $ 374,923 $ 213,488
Interest cost 28,414 15,446
Service cost 13,231 10,067
Benefit payments (17,207) (7,258)
Actuarial gain 27,428 (12,590)
Plan amendment (25,845) --
Acquisitions -- 155,770
--------- ---------
OPEB obligation at December 31 $ 400,944 $ 374,923
Fair value of plan assets at December 31 55,529 54,642
--------- ---------
Funded status $(345,415) $(320,281)
Unrecognized transition obligation 33,129 70,715
Unrecognized prior service cost 7,675 955
Unrecognized actuarial loss (gain) 6,429 (25,060)
--------- ---------
Accrued OPEB cost at December 31 $(298,182) $(273,671)
========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2001 2000
-------- --------
Fair value of plan assets at January 1 $ 54,642 $ 43,235
Actual return on plan assets (444) 124
Acquisition -- 11,283
Employer contribution 18,538 7,258
Benefits paid (17,207) (7,258)
-------- --------
Fair value of plan assets at December 31 $ 55,529 $ 54,642
======== ========
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<PAGE>
The assumptions used to measure the OPEB obligation and determine the net
periodic OPEB cost are:
<TABLE>
<CAPTION>
2001 2000 1999
---- ---------- ----
<S> <C> <C> <C>
Weighted-average long-term rate of return on plan assets 8.70% 9.20% 9.25%
Weighted-average discount rate 7.50% 7.50% 7.50%
Initial medical cost trend rate for pre-Medicare benefits 7.50% 7.2% - 7.5% 7.50%
Initial medical cost trend rate for post-Medicare benefits 7.50% 6.2% - 7.5% 7.25%
Ultimate medical cost trend rate 5.0% 5.0% - 5.3% 5.0%
Year ultimate medical cost trend rate is achieved 2008 2005-2009 2006
</TABLE>
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 2001 would increase by $5.6 million, and
the OPEB obligation at December 31, 2001, would increase by $35.3 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
2001 would decrease by $4.8 million and the OPEB obligation at December 31,
2001, would decrease by $32.3 million.
During 1999, the Company completed the acquisition of NCNG (See Note 2B).
During 2000, the Company completed the acquisition of FPC (See Note 2A).
NCNG's and FPC's pension and OPEB liabilities, assets and net periodic
costs are reflected in the above information as appropriate. Effective
January 1, 2000, NCNG's benefit plans were merged with those of the
Company. Certain of FPC's non-bargaining unit benefit plans were merged
with those of the Company effective January 1, 2002.
Florida Power continues to recover qualified plan pension costs and OPEB
costs in rates as if the acquisition had not occurred. Accordingly, a
portion of the prepaid pension cost and a portion of the accrued OPEB cost
reflected in the tables above have a corresponding regulatory liability and
regulatory asset, respectively (See Note 2A). In addition, pursuant to its
rate treatment, for 2001 Florida Power recognized additional periodic
pension credit of $16.5 million and additional periodic OPEB cost of $3.5
million, as compared to the amounts included in the net periodic
information above.
17. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average of common
shares outstanding. Diluted earnings per share includes the effect of the
non-vested portion of restricted stock awards. The stock options
outstanding as of December 31, 2001 were anti-dilutive and therefore are
not included in diluted earnings per share. Restricted stock awards and
contingently issuable shares had a dilutive effect on earnings per share
for all three years and increased the weighted-average number of common
shares outstanding for dilutive purposes by 664,403 in 2001, 454,924 in
2000 and 290,474 in 1999. The weighted-average number of common shares
outstanding for dilutive purposes was 205.3 million, 157.6 million and
148.6 million for 2001, 2000 and 1999, respectively.
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 5.4 million,
5.7 million and 6.5 million for the years ended December 31, 2001, 2000 and
1999, respectively.
18. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. A regulatory asset or liability has been recognized for the
impact of tax expenses or benefits that are recovered or refunded in
different periods by the utilities pursuant to rate orders.
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<PAGE>
Accumulated deferred income tax (assets) liabilities at December 31 are (in
thousands):
2001 2000
---------- ----------
Accelerated depreciation and property
cost differences $1,812,743 $2,054,509
Deferred costs, net 82,566 63,085
Income tax credit carry forward (306,497) (103,754)
Miscellaneous other temporary differences, net (157,343) (150,969)
Valuation allowance 31,492 10,868
---------- ----------
Net accumulated deferred income
tax liability $1,462,961 $1,873,739
========== ==========
Total deferred income tax liabilities were $2.68 billion and $2.79 billion
at December 31, 2001 and 2000, respectively. Total deferred income tax
assets were $1.22 billion and $919 million at December 31, 2001 and 2000,
respectively. The net of deferred income tax liabilities and deferred
income tax assets is included on the Consolidated Balance Sheets under the
captions other current liabilities and accumulated deferred income taxes.
The Company established a valuation allowance of $10.9 million in 2000 and
established additional valuation allowances of $20.5 million during 2001
due to the uncertainty of realizing future tax benefits from certain state
net operating loss carryforwards.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
<TABLE>
<CAPTION>
2001 2000 1999
----- ---- ----
<S> <C> <C> <C>
Effective income tax rate (38.9)% 29.7% 40.3%
State income taxes, net of federal benefit (7.7) (4.8) (4.6)
AFUDC amortization (4.9) (5.1) (1.7)
Federal tax credits 93.5 12.2 1.4
Goodwill amortization and write-offs (11.3) (0.7) (0.3)
Investment tax credit amortization 5.9 4.2 1.6
ESOP dividend deduction 1.9 1.0 1.1
Interpath investment impairment (2.1) -- --
Other differences, net (1.4) (1.5) (2.8)
----- ---- ----
Statutory federal income tax rate 35.0% 35.0% 35.0%
===== ==== ====
</TABLE>
Income tax expense (benefit) is comprised of (in thousands):
<TABLE>
<CAPTION>
2001 2000 1999
--------- -------- --------
<S> <C> <C> <C>
Current - federal $ 185,309 $254,967 $253,140
state 52,433 61,309 48,075
Deferred - federal (356,160) (84,605) (30,011)
state (10,330) (10,761) (2,484)
Investment tax credit (22,895) (18,136) (10,299)
--------- -------- --------
Total income tax expense (benefi) $(151,643) $202,774 $258,421
========= ======== ========
</TABLE>
The Company, through its subsidiaries, is a majority owner in five entities
and a minority owner in one entity that own facilities that produce
synthetic fuel as defined under the Internal Revenue Service Code (Code).
The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 of the Code (Section 29) if
certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. All entities have received private
letter rulings (PLR's) from the Internal Revenue Service (IRS) with respect
to their synthetic fuel operations. The PLR's do not limit the production
on which synthetic fuel credits may be claimed. Should the tax credits be
denied on future audits, and the Company fails to prevail through the IRS
or legal process, there could be a significant tax liability owed for
previously taken Section 29 credits, with a significant impact on earnings
and cash flows. In
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<PAGE>
management's opinion, the Company is complying with all the necessary
requirements to be allowed such credits under Section 29 and believes it is
probable, although it cannot provide certainty, that it will prevail on any
credits taken.
19. Joint Ownership of Generating Facilities
CP&L and Florida Power hold undivided ownership interests in certain
jointly owned generating facilities, excluding related nuclear fuel and
inventories. Each is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. Each
also pays its ownership share of additional construction costs, fuel
inventory purchases and operating expenses. CP&L's and Florida Power's
share of expenses for the jointly owned facilities is included in the
appropriate expense category.
CP&L's and Florida Power's ownership interests in the jointly owned
generating facilities are listed below with related information as of
December 31, 2001 (dollars in thousands):
<TABLE>
<CAPTION>
Company
Megawatt Ownership Plant Accumulated Accumulated Under
Subsidiary Facility Capability Interest Investment Depreciation Decommissioning Construction
- ---------- ------------------- ---------- --------- ---------- ------------ --------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
CP&L Mayo Plant 745 83.83% $ 460,026 $ 230,630 $ -- $ 7,116
CP&L Harris Plant 860 83.83% 3,154,183 1,321,694 93,637 14,416
CP&L Brunswick Plant 1,631 81.67% 1,427,842 828,480 339,945 41,455
CP&L Roxboro Unit 4 700 87.06% 309,032 126,007 - 7,881
Florida Crystal River Plant 834 91.78% 773,835 469,840 333,939 25,723
Power
</TABLE>
In the table above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
20. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between CP&L and Power Agency, CP&L is obligated to purchase a percentage
of Power Agency's ownership capacity of, and energy from, the Harris Plant.
In 1993, CP&L and Power Agency entered into an agreement to restructure
portions of their contracts covering power supplies and interests in
jointly owned units. Under the terms of the 1993 agreement, CP&L increased
the amount of capacity and energy purchased from Power Agency's ownership
interest in the Harris Plant, and the buyback period was extended six years
through 2007. The estimated minimum annual payments for these purchases,
which reflect capacity costs, total approximately $32 million. These
contractual purchases totaled $33.3 million, $33.9 million and $36.5
million for 2001, 2000 and 1999, respectively. In 1987, the NCUC ordered
CP&L to reflect the recovery of the capacity portion of these costs on a
levelized basis over the original 15-year buyback period, thereby deferring
for future recovery the difference between such costs and amounts collected
through rates. At December 31, 2001 and 2000, CP&L had deferred purchased
capacity costs, including carrying costs accrued on the deferred balances,
of $32.5 million and $44.8 million, respectively. Increased purchases
(which are not being deferred for future recovery) resulting from the 1993
agreement with Power Agency were approximately $29 million, $26 million and
$23 million for 2001, 2000 and 1999, respectively.
CP&L has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts
of capacity through 2009 with minimum annual payments of approximately $31
million, representing capital-related capacity costs. Total purchases
(including transmission use charges) under the Rockport agreement amounted
to $62.8 million, $61.0 million and $59.2 million for 2001, 2000 and 1999,
respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the
purchase of power from Skygen Energy LLC's Broad River facility (Broad
River). The agreement provides for the purchase of approximately 500
megawatts of capacity through 2021 with an original minimum annual payment
of approximately $16 million, primarily representing capital-related
capacity costs. The minimum annual payments will be indexed for inflation.
Total purchases under the Broad River agreement amounted to $35.9 million
in 2001. A separate long-term agreement for additional power from Broad
River will commence June 1, 2002. This agreement will provide for the
purchase of approximately 300 megawatts of capacity through 2022 with an
original minimum annual payment of
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<PAGE>
approximately $16 million representing capital-related capacity costs. The
minimum annual payments will be indexed for inflation.
Florida Power has long-term contracts for approximately 460 megawatts of
purchased power with other utilities, including a contract with The
Southern Company for approximately 400 megawatts of purchased power
annually through 2010. Florida Power can lower these purchases to
approximately 200 megawatts annually with a three-year notice. Total
purchases under these agreements amounted to $111.7 million and $104.5
million for 2001 and 2000, respectively. Minimum purchases under these
contracts, representing capital-related capacity costs, are approximately
$50 million annually through 2003 and $30 million annually through 2006.
Both CP&L and Florida Power have ongoing purchased power contracts with
certain cogenerators (qualifying facilities) with expiration dates ranging
from 2002 to 2025. These purchased power contracts generally provide for
capacity and energy payments. Energy payments for the Florida Power
contracts are based on actual power taken under these contracts. Minimum
expected future capacity payments under these contracts as of December 31,
2001 are $235.7 million, $244.3 million, $255.4 million, $267.9 million and
$279.1 million for 2002-2006, respectively. CP&L has various
pay-for-performance contracts with qualifying facilities for approximately
300 megawatts of capacity expiring at various times through 2009. Payments
for both capacity and energy are contingent upon the qualifying facilities'
ability to generate. Payments made under these contracts were $145.1
million in 2001, $168.4 million in 2000 and $178.7 million in 1999.
Florida Power and CP&L have entered into various long-term contracts for
coal, gas and oil requirements of its generating plants. Estimated annual
payments for firm commitments of fuel purchases and transportation costs
under these contracts are approximately $1.5 billion, $1.2 billion, $992.8
million, $942.4 million and $944.4 million for 2002 through 2006,
respectively.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties) of up
to $11.4 million on sales from each plant annually through 2007. The
related agreements were amended in December 2001 to require the payment of
minimum annual royalties of approximately $6.6 million for each plant
through 2007. As a result of the amendment, the Company recorded a
liability (included in other liabilities and deferred credits on the
Consolidated Balance Sheets) and a deferred cost asset (included in other
assets and deferred debits in the Consolidated Balance Sheets) of
approximately $134.0 million at December 31, 2001, representing the minimum
amounts due through 2007, discounted at 6.05%. As of December 31, 2001, the
portion of the asset and liability recorded that was classified as current
was $25.8 million. The deferred cost asset will be amortized to expense
each year as synthetic fuel sales are made. The maximum amounts payable
under these agreements remain unchanged. Actual amounts accrued under these
agreements were approximately $45.8 million in 2001 and $43.1 million in
2000.
The Company has entered into a joint venture to build an 850-mile natural
gas pipeline system to serve 14 eastern North Carolina counties. The
Company has agreed to fund approximately $22.0 million of the project. The
entire project is expected to be completed by the end of 2004.
During February 2002, Progress Ventures completed the acquisition of two
electric generating projects totaling approximately 1,100 megawatts for
total cash consideration of $345 million. The transaction included a power
purchase agreement with the seller through December 31, 2004. In addition,
there is a project management completion agreement whereby the Company
assumed certain liabilities to facilitate buildout of one of the projects.
In January 2002, Progress Ventures entered into a letter of intent to
acquire approximately 215 natural gas wells, 52 miles of intrastate gas
pipeline and 170 miles of gas-gathering systems. Total consideration of
$153 million is expected to include $135 million in Company common stock
and $18 million in cash. This transaction is expected to be completed
during the first quarter of 2002.
C. Insurance
CP&L and Florida Power are members of Nuclear Electric Insurance Limited
(NEIL), which provides primary and excess insurance coverage against
property damage to members' nuclear generating facilities. Under the
primary program, each company is insured for $500 million at each of its
respective nuclear plants. In addition to primary coverage, NEIL also
provides decontamination, premature decommissioning and excess property
insurance with limits of $2.0 billion on the Brunswick and Harris Plants,
and $1.1 billion on the Robinson and CR3 Plants.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. Both CP&L and Florida Power are
insured
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<PAGE>
thereunder, following a twelve-week deductible period, for 52 weeks in the
amount of $3.5 million per week at each of the nuclear units. An additional
110 weeks of coverage is provided at 80% of the above weekly amount. For
the current policy period, the companies are subject to retrospective
premium assessments of up to approximately $31.4 million with respect to
the primary coverage, $32.4 million with respect to the decontamination,
decommissioning and excess property coverage, and $22.1 million for the
incremental replacement power costs coverage, in the event covered losses
at insured facilities exceed premiums, reserves, reinsurance and other NEIL
resources. Pursuant to regulations, each company's property damage
insurance policies provide that all proceeds from such insurance be
applied, first, to place the plant in a safe and stable condition after an
accident and, second, to decontamination costs, before any proceeds can be
used for decommissioning, plant repair or restoration. Each company is
responsible to the extent losses may exceed limits of the coverage
described above.
Both CP&L and Florida Power are insured against public liability for a
nuclear incident up to $9.54 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
$200 million (currently available through commercial insurers), each
company would be subject to pro rata assessments of up to $88.1 million for
each reactor owned per occurrence. Payment of such assessments would be
made over time as necessary to limit the payment in any one year to no more
than $10 million per reactor owned. The Price Anderson Act expires August
1, 2002. There are several renewal proposals before Congress which include
possible increased limits and retroactive premiums. The final outcome of
this matter cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were
multiple terrorism losses occurring within one year after the first loss
from terrorism, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant.
If terrorism losses occurred beyond the one-year period, a new set of
limits and resources would apply. For nuclear liability claims arising out
of terrorist acts, the primary level available through commercial insurers
is now subject to an industry aggregate limit of $200.0 million. The second
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $200.0 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts aggregate.
CP&L and Florida Power self-insure their transmission and distribution
lines against loss due to storm damage and other natural disasters. Florida
Power accrues $6 million annually to a storm damage reserve pursuant to a
regulatory order and may defer losses in excess of the reserve (Note 13B).
D. Claims and uncertainties
1. The Company is subject to federal, state and local regulations
addressing air and water quality, hazardous and solid waste management and
other environmental matters.
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The lead or sole regulatory agency that is responsible for a
particular former coal tar site depends largely upon the state in which the
site is located. There are several manufactured gas plant (MGP) sites to
which both electric utilities and the gas utility have some connection. In
this regard, both electric utilities and the gas utility, with other
potentially responsible parties, are participating in investigating and, if
necessary, remediating former coal tar sites with several regulatory
agencies, including, but not limited to, the U.S. Environmental Protection
Agency (EPA), the Florida Department of Environmental Protection (FDEP) and
the North Carolina Department of Environment and Natural Resources,
Division of Waste Management (DWM). Although the electric utilities and gas
utility may incur costs at these sites about which it has been notified,
based upon current status of these sites, the Company does not expect those
costs to be material to its consolidated financial position or results of
operations. The Company has accrued probable costs at certain of these
sites.
Both electric utilities, the gas utility and Progress Ventures are
periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. Although The
Company's subsidiaries may incur costs at the sites about which they have
been notified, based upon the current status of these sites, the Company
does not expect those costs to be material to the consolidated financial
position or results of operations of the Company.
95
<PAGE>
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide and mercury
setting forth national caps and emission levels over an extended period of
time. This national multi-pollutant approach would have significant costs
which could be material to CP&L's consolidated financial position or
results of operations. Some companies may seek recovery of the related cost
through rate adjustments or similar mechanisms. The Company cannot predict
the outcome of this matter.
The EPA has been conducting an enforcement initiative related to a number
of coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both CP&L and Florida Power were asked to provide information to the EPA as
part of this initiative and cooperated in providing the requested
information. The EPA has initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative, some of which have
resulted in settlement agreements calling for expenditures, ranging from
$1.0 billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the issue of regional
transport of ozone. This rule is commonly known as the NOx SIP Call. The
EPA's rule requires 23 jurisdictions, including North Carolina, South
Carolina and Georgia, but not Florida, to further reduce nitrogen oxide
emissions in order to attain a pre-set state NOx emission level by May 31,
2004. CP&L is evaluating necessary measures to comply with the rule and
estimates its related capital expenditures to meet these measures in North
and South Carolina could be approximately $370 million, which has not been
adjusted for inflation. Increased operation and maintenance costs relating
to the NOx SIP Call are not expected to be material to the Company's
results of operations. Further controls are anticipated as electricity
demand increases. The Company cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals decision. Further litigation
and rulemaking are anticipated. North Carolina adopted the federal
eight-hour ozone standard and is proceeding with the implementation
process. North Carolina has promulgated final regulations, which will
require CP&L to install nitrogen oxide controls under the State's
eight-hour standard. The cost of those controls are included in the cost
estimate of $370 million set forth above.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act, which requires certain sources to make reductions in
nitrogen oxide emissions by May 1, 2003. The final rule also includes a set
of regulations that affect nitrogen oxide emissions from sources included
in the petitions. The North Carolina fossil-fueled electric generating
plants are included in these petitions. Acceptable state plans under the
NOx SIP Call can be approved in lieu of the final rules the EPA approved as
part of the 126 petitions. CP&L, other utilities, trade organizations and
other states participated in litigation challenging the EPA's action. On
May 15, 2001, the District of Columbia Circuit Court of Appeals ruled in
favor of the EPA which will require North Carolina to make reductions in
nitrogen oxide emissions by May 1, 2003. However, the Court in its May 15th
decision rejected the EPA's methodology for estimating the future growth
factors the EPA used in calculating the emissions limits for utilities. In
August 2001, the Court granted a request by CP&L and other utilities to
delay the implementation of the 126 Rule for electric generating units
pending resolution by the EPA of the growth factor issue. The Court's order
tolls the three-year compliance period (originally set to end on May 1,
2003) for electric generating units as of May 15, 2001. On January 16,
2002, the EPA issued a memo to harmonize the compliance dates for the
Section 126 Rule and the NOx SIP Call. The new compliance date for all
affected sources is now May 31, 2004, rather than May 1, 2003, subject to
the completion of the EPA's response to the related court decision on the
growth factor issue. The Company cannot predict the outcome of this matter.
On November 1, 2001, the Company completed the sale of the Inland Marine
Transportation segment to AEP Resources, Inc. In connection with the sale,
the Company entered into environmental indemnification provisions covering
both unknown and known sites. The Company has recorded an accrual to cover
estimated probable future environmental expenditures. The Company believes
that it is reasonably possible that additional costs, which cannot be
currently estimated, may be incurred related to the environmental
indemnification provision beyond the amounts accrued. The Company cannot
predict the outcome of this matter.
CP&L, Florida Power, Progress Ventures and NCNG have filed claims with the
Company's general liability insurance carriers to recover costs arising out
of actual or potential environmental liabilities. Some claims have
96
<PAGE>
been settled and others are still pending. While management cannot predict
the outcome of these matters, the outcome is not expected to have a
material effect on the consolidated financial position or results of
operations.
2. As required under the Nuclear Waste Policy Act of 1982, CP&L and Florida
Power each entered into a contract with the Department of Energy (DOE)
under which the DOE agreed to begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required to
sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
-------------------------------
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan
------------------
Power v. DOE, a group of utilities petitioned the Court of Appeals in
------------
Northern States Power (NSP) v. DOE, seeking an order requiring the DOE to
----------------------------------
begin taking spent nuclear fuel by January 31, 1998. The DOE took the
position that their delay was unavoidable, and the DOE was excused from
performance under the terms and conditions of the contract. The Court of
Appeals found that the delay was not unavoidable, but did not order the DOE
to begin taking spent nuclear fuel, stating that the utilities had a
potentially adequate remedy by filing a claim for damages under the
contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
----------
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
----------
Subsequently, a number of utilities each filed an action for damages in the
Court of Claims. In a recent decision, the U.S. Circuit Court of Appeals
(Federal Circuit) ruled that utilities may sue the DOE for damages in the
Federal Court of Claims instead of having to file an administrative claim
with DOE. CP&L and Florida Power are in the process of evaluating whether
they should each file a similar action for damages.
CP&L and Florida Power also continue to monitor legislation that has been
introduced in Congress which might provide some limited relief. CP&L and
Florida Power cannot predict the outcome of this matter.
With certain modifications, CP&L's spent nuclear fuel storage facilities
will be sufficient to provide storage space for spent fuel generated on
CP&L's system through the expiration of the current operating licenses for
all of CP&L's nuclear generating units. Subsequent to the expiration of
these licenses, dry storage may be necessary. CP&L obtained NRC approval to
use additional storage space at the Harris Plant in December 2000. Florida
Power currently is storing spent nuclear fuel onsite in spent fuel pools.
If Florida Power does not seek renewal of the CR3 operating license, CR3
will have sufficient storage capacity in place for fuel consumed through
the end of the expiration of the license in 2016. If Florida Power extends
the CR3 operating license, dry storage may be necessary.
3. The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve
substantial amounts. Where appropriate, accruals have been made in
accordance with SFAS No. 5, "Accounting for Contingencies," to provide for
such matters. In the opinion of management, the final disposition of
pending litigation would not have a material adverse effect on the
Company's consolidated results of operations or financial position.
21. Subsequent Event (Unaudited)
On March 27, 2002, the parties in Florida Power's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement is to be effective from May 1, 2002 through 2005;
provided, however, that if Florida Power's base rate earnings fall below a
10% return on equity, Florida Power may petition the FPSC to amend its base
rates.
The Agreement provides that Florida Power will reduce its retail revenues
from the sale of electricity by $125 million annually through 2005. The
Agreement also provides that Florida Power will operate under a Revenue
Sharing Incentive Plan (the Plan) that establishes revenue caps and sharing
thresholds for the years 2002 through 2005. The Plan provides that retail
base rate revenues between the sharing thresholds and the retail base rate
revenue caps will be divided into two shares - a 1/3 share to be received
by Florida Power's shareholders, and a 2/3 share to be refunded to Florida
Power's retail customers; provided, however, that for the year 2002 only,
the refund to
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<PAGE>
customers will be limited to 67.1% of the 2/3 customer share. The retail
base rate revenue sharing threshold amounts for 2002, 2003, 2004 and 2005
will be $1,296 million, $1,333 million, $1,370 million and $1,407 million,
respectively. The Plan also provides that all retail base rate revenues
above the retail base rate revenue caps established for the years 2003,
2004 and 2005 will be refunded to retail customers on an annual basis. For
2002, the refund to customers will be limited to 67.1% of the retail base
rate revenues that exceed the 2002 cap. The retail base revenue caps for
2002, 2003, 2004 and 2005 will be $1,356 million, $1,393 million, $1,430
million and $1,467 million, respectively.
The Agreement also provides that beginning with the in-service date of
Florida Power's Hines Unit 2 and continuing through December 31, 2005,
Florida Power will be allowed to recover through the fuel cost recovery
clause a return on average investment and depreciation expense for Hines
Unit 2, to the extent such costs do not exceed the Unit's cumulative fuel
savings over the recovery period.
Additionally, the Agreement provides that Florida Power will effect a
mid-course correction of its fuel cost recovery clause to reduce the fuel
factor by $50 million for the remainder of 2002. The fuel cost recovery
clause will operate as it normally does, including, but not limited to any
additional mid-course adjustments that may become necessary, and the
calculation of true-ups to actual fuel clause expenses.
During the term of the Agreement, Florida Power will suspend accruals on
its reserves for nuclear decommissioning and fossil dismantlement.
Additionally, for each calendar year during the term of the Agreement,
Florida Power will record a $62.5 million depreciation expense reduction,
and may, at its option, record up to an equal annual amount as an
offsetting accelerated depreciation expense. In addition, Florida Power 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, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan
and expects to achieve a 20% improvement in its annual System Average
Interruption Duration Index by no later than 2004. If this improvement
level is not achieved for calendar years 2004 or 2005, Florida Power will
provide a refund of $3 million for each year the level is not achieved to
10% of its total retail customers served by its worst performing
distribution feeder lines.
The Agreement also provides that Florida Power will refund to customers $35
million of the $98 million in interim revenues Florida Power has collected
subject to refund since March 13, 2001. No other interim revenues that were
collected during that period will continue to be held subject to refund.
The Agreement was filed with the FPSC for approval on March 27, 2002. If
the FPSC approves the Agreement, the new rates will take effect May 1,
2002. Progress Energy cannot predict the outcome of this matter.
98
<PAGE>
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT
COMPANY:
We have audited the accompanying consolidated balance sheets and schedules
of capitalization of Carolina Power & Light Company and its subsidiaries
(CP&L) as of December 31, 2001 and 2000, and the related consolidated
statements of income and comprehensive income, retained earnings, and cash
flows for each of the three years in the period ended December 31, 2001.
Our audits also included the financial statement schedule listed in the
Index at Item 8. These financial statements and the financial statement
schedule are the responsibility of CP&L's management. Our responsibility is
to express an opinion on these financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, based on our audits, such consolidated financial statements
present fairly, in all material respects, the financial position of CP&L at
December 31, 2001 and 2000, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such 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
February 15, 2002
99
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of INCOME and COMPRHENSIVE INCOME
- ---------------------------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2001 2000 1999
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $3,343,720 $3,323,676 $3,138,846
Natural gas -- 147,448 98,903
Diversified businesses 16,441 72,783 119,866
- ----------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,360,161 3,543,907 3,357,615
- ----------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 647,263 627,463 581,340
Purchased power 353,551 325,366 365,425
Gas purchased for resale -- 103,734 67,465
Other operation and maintenance 701,703 741,466 682,407
Depreciation and amortization 521,910 708,249 503,105
Taxes other than on income 149,719 148,037 142,741
Diversified businesses 9,985 135,258 174,589
- ----------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,384,131 2,789,573 2,517,072
- ----------------------------------------------------------------------------------------------------------
Operating Income 976,030 754,334 840,543
- ----------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 13,728 26,226 10,336
Gain on sale of assets -- 200,000 --
Impairment of investment (156,712) -- --
Other, net (4,155) (7,795) (30,739)
- ----------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (147,139) 218,431 (20,403)
- ----------------------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 245,808 223,562 180,676
Other interest charges 11,333 16,441 10,298
Allowance for borrowed funds used during construction (15,714) (18,537) (11,510)
- ----------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 241,427 221,466 179,464
- ----------------------------------------------------------------------------------------------------------
Income before Income Taxes 587,464 751,299 640,676
Income Taxes 223,233 290,271 258,421
- ----------------------------------------------------------------------------------------------------------
Net Income 364,231 461,028 382,255
Preferred Stock Dividend Requirement 2,964 2,966 2,967
- ----------------------------------------------------------------------------------------------------------
Earnings for Common Stock 361,267 458,062 379,288
- ----------------------------------------------------------------------------------------------------------
Other Comprehensive Income (Loss), Net of Tax:
SFAS No. 133 transition adjustment (net of tax of $474) (738) -- --
Unrealized loss on cash flow hedges (net of tax of $7,565) (11,784) -- --
Reclassification adjustment for amounts included in net
income (net of tax of $3,515) 5,476 -- --
- ----------------------------------------------------------------------------------------------------------
Total Other Comprehensive Loss, Net of Tax (7,046) -- --
- ----------------------------------------------------------------------------------------------------------
Comprehensive Income for Common Stock $ 354,221 $ 458,062 $ 379,288
- ----------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Carolina Power & Light Company consolidated financial statements.
100
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
- ---------------------------
<TABLE>
<CAPTION>
(In thousands) December 31
Assets 2001 2000
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric utility plant in service $12,024,291 $11,125,901
Accumulated depreciation (5,952,206) (5,505,731)
- ------------------------------------------------------------------------------------------
Utility plant in service, net 6,072,085 5,620,170
Held for future use 7,105 7,105
Construction work in progress 711,129 815,246
Nuclear fuel, net of amortization 200,332 184,813
- ------------------------------------------------------------------------------------------
Total Utility Plant, Net 6,990,651 6,627,334
- ------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 21,250 30,070
Accounts receivable 454,228 466,774
Receivables from affiliated companies 31,707 341,932
Taxes receivable 17,543 15,412
Inventory 365,501 233,369
Deferred fuel cost 131,505 119,853
Prepayments 11,863 24,284
Other current assets 66,193 75,451
- ------------------------------------------------------------------------------------------
Total Current Assets 1,099,790 1,307,145
- ------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 277,550 291,411
Nuclear decommissioning trust funds 416,721 411,279
Diversified business property, net 111,802 102,294
Miscellaneous other property and investments 231,325 395,995
Other assets and deferred debits 135,373 104,028
- ------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,172,771 1,305,007
- ------------------------------------------------------------------------------------------
Total Assets 9,263,212 $ 9,239,486
- ------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of capitalization)
- ------------------------------------------------------------------------------------------
Common stock equity $ 3,095,456 $ 2,852,038
Preferred stock - not subject to mandatory redemption 59,334 59,334
Long-term debt, net 2,958,853 3,619,984
- ------------------------------------------------------------------------------------------
Total Capitalization 6,113,643 6,531,356
- ------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 600,000 --
Accounts payable 300,829 281,026
Payables to affiliated companies 157,423 255,074
Interest accrued 61,124 56,259
Other current liabilities 209,776 147,673
- ------------------------------------------------------------------------------------------
Total Current Liabilities 1,329,152 740,032
- ------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,316,823 1,491,660
Accumulated deferred investment tax credits 170,302 197,207
Regulatory liabilities 7,494 --
Other liabilities and deferred credits 325,798 279,231
- ------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,820,417 1,968,098
- ------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 15)
- ------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,263,212 $ 9,239,486
- ------------------------------------------------------------------------------------------
</TABLE>
See Notes to Carolina Power & Light Company consolidated financial statements.
101
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of CASH FLOWS
- -------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2001 2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities
Net income $ 364,231 $ 461,028 $ 382,255
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of investment 156,712 -- --
Depreciation and amortization 609,718 800,056 592,001
Deferred income taxes (149,895) (83,554) (32,495)
Investment tax credit (14,928) (4,511) (10,299)
Gain on sale of assets -- (200,000) --
Deferred fuel credit (11,652) (40,763) (39,052)
Net (increase) decrease in accounts receivable 397,727 (299,717) (33,322)
Net increase in inventories (132,630) (3,699) (17,576)
Net (increase) decrease in prepaid and other current assets 21,679 87,575 (117,250)
Net increase (decrease) in accounts payable (183,739) 287,858 24,555
Net increase in other current liabilities 53,845 11,654 7,436
Other 46,402 29,180 75,867
- -----------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,157,470 1,045,107 832,120
- -----------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (823,952) (821,991) (689,054)
Nuclear fuel additions (72,576) (59,752) (75,641)
Proceeds from sale of assets -- 200,000 --
Contributions to nuclear decommissioning trust (30,678) (30,727) (30,825)
Net cash flow of company-owned life insurance program (5,066) (4,291) (6,542)
Diversified business property additions (13,500) (56,489) (157,802)
Investments in non-utility activities (12,675) (107,225) (41,723)
- -----------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (958,447) (880,475) (1,001,587)
- -----------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 296,124 783,052 400,970
Net increase (decrease) in commercial paper reclassified to long-term debt (225,762) 123,697 268,500
Net increase in short-term indebtedness -- -- 70,600
Net increase (decrease) in cash provided by checks drawn in excess of bank balances -- 21,069 (117,643)
Retirement of long-term debt (134,611) (695,163) (113,335)
Equity contribution from parent 115,000 -- --
Dividends paid to parent (255,630) -- --
Dividends paid on preferred stock (2,964) (2,966) (2,967)
Dividends paid on common stock -- (432,325) (293,704)
Other -- (42) 6,169
- -----------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (207,843) (202,678) 218,590
- -----------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents (8,820) (38,046) 49,123
- -----------------------------------------------------------------------------------------------------------------------------
Increase in Cash from Acquisition (See Noncash Activities) -- -- 1,876
Decrease in Cash from Stock Distribution (See Note 1A) -- (11,755) --
Cash and Cash Equivalents at Beginning of the Year 30,070 79,871 28,872
- -----------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 21,250 $ 30,070 $ 79,871
- -----------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 230,828 $ 205,250 $ 174,101
income taxes $ 395,433 $ 434,908 $ 284,535
</TABLE>
Noncash Activities
. On July 15, 1999, CP&L purchased all outstanding shares of North
Carolina Natural Gas Corporation (NCNG). In conjunction with the
purchase of NCNG, CP&L issued approximately $360 million in common
stock.
. On June 28, 2000, Caronet, a wholly owned subsidiary of CP&L,
contributed net assets in the amount of $93.0 million in exchange for
a 35% ownership interest (15% voting interest) in a newly formed
company.
. On July 1, 2000, CP&L distributed its ownership interest in the stock
of North Carolina Natural Gas Corporation, Strategic Resource
Solutions Corp., Monroe Power Company and Progress Ventures, Inc. to
Progress Energy, Inc. This resulted in a noncash dividend to its
parent of approximately $555.9 million.
. In January 2001, CP&L transferred certain assets, through a noncash
dividend to parent in the amount of $19.1 million, to Progress Energy
Service Company, LLC
See Notes to Carolina Power & Light Company consolidated financial statements.
102
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES of CAPITALIZATION
- ----------------------------------------
<TABLE>
<CAPTION>
December 31
(Dollars in thousands) 2001 2000
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Common Stock Equity
Common stock without par value, authorized 200,000,000
shares, 159,608,055 shares issued and
outstanding at December 31 $1,904,246 $1,765,813
Unearned restricted stock awards -- (12,708)
Unearned ESOP common stock (114,385) (127,211)
Accumulated other comprehensive loss (7,046) --
Retained earnings 1,312,641 1,226,144
- -------------------------------------------------------------------------------------------------------
Total Common Stock Equity $3,095,456 $2,852,038
- -------------------------------------------------------------------------------------------------------
Preferred Stock - not subject to mandatory redemption
- -------------------------------------------------------------------------------------------------------
Authorized - 300,000 shares, cumulative, $100 par value
Preferred Stock; 20,000,000 shares, cumulative, $100 par
value Serial Preferred Stock
$5.00 Preferred - 236,997 shares (redemption price $110.00) $ 24,349 $ 24,349
$4.20 Serial Preferred - 100,000 shares outstanding (redemption
price $102.00) 10,000 10,000
$5.44 Serial Preferred -249,850 shares (redemption price $101.00) 24,985 24,985
- -------------------------------------------------------------------------------------------------------
Total Preferred Stock $ 59,334 $ 59,334
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Long-Term Debt (maturities and weighted average interest rates as of
December 31, 2001)
First mortgage bonds, maturing 2003-2023 7.02% $1,800,000 $1,800,000
Pollution control obligations, maturing 2009-2024 2.22% 707,800 713,770
Unsecured subordinated debentures, maturing 2025 -- 125,000
Extendible notes, maturing 2002 2.83% 500,000 500,000
Medium-term notes, maturing 2008 6.65% 300,000 --
Commercial paper reclassified to long-term debt 3.10% 260,535 486,297
Miscellaneous notes 6.43% 7,234 7,324
Unamortized premium and discount, net (16,716) (12,407)
Current portion of long-term debt (600,000) --
- -------------------------------------------------------------------------------------------------------
Total Long-Term Debt 2,958,853 3,619,984
- -------------------------------------------------------------------------------------------------------
Total Capitalization $6,113,643 $6,531,356
- -------------------------------------------------------------------------------------------------------
</TABLE>
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
- --------------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2001 2000 1999
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $1,226,144 $ 1,807,345 $ 1,728,301
Net income 364,231 461,028 382,255
Preferred stock dividends at stated rates (2,964) (2,966) (2,967)
Common stock dividends (274,770) (1,039,263) (300,244)
- ------------------------------------------------------------------------------------
Retained Earnings at End of Year $1,312,641 $ 1,226,144 $ 1,807,345
- ------------------------------------------------------------------------------------
</TABLE>
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
- -------------------------------------------------
<TABLE>
<CAPTION>
(In thousands) First Quarter (a) Second Quarter (a) Third Quarter (a) Fourth Quarter (a)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Year ended December 31, 2001
Operating revenues $826,603 783,379 976,891 773,288
Operating income 231,641 184,390 322,477 237,522
Net income (loss) 120,845 84,879 167,874 (9,367) (d)
- --------------------------------------------------------------------------------------------------------------
Year ended December 31, 2000
Operating revenues $877,140 $892,304 $943,112 $831,351
Operating income 185,110 214,184 330,675 24,365 (c)
Net income (loss) 86,003 108,202 291,914 (b) (25,091) (c)
</TABLE>
(a) 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.
(b) Includes gain on sale of BellSouth Carolinas PCS Partnership interest.
(c) Includes approved further accelerated depreciation of $125 million on
nuclear generating assets.
(d) Includes impairment and other one-time charges relating to Interpath
of $107.2 million, after tax.
See Notes to Carolina Power & Light Company consolidated financial
statements.
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CAROLINA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina and South Carolina. CP&L is a
wholly owned subsidiary of Progress Energy, Inc. (the Company or Progress
Energy), which was formed as a result of the reorganization of CP&L into a
holding company structure on June 19, 2000. All shares of common stock of
CP&L were exchanged for an equal number of shares of the Company. On
December 4, 2000, the Company changed its name from CP&L Energy, Inc. to
Progress Energy, Inc. The Company is a registered holding company under the
Public Utility Holding Company Act (PUHCA) of 1935. Both the Company and
its subsidiaries are subject to the regulatory provisions of the PUHCA.
On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas (NCNG), Strategic Resource Solutions Corp.
(SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc. to
the Company. As a result, those companies are direct subsidiaries of
Progress Energy, Inc. and are not included in CP&L's results of operations
and financial position since that date.
CP&L's results of operations include the results of NCNG for the periods
subsequent to July 15, 1999 (See Note 2A) and prior to July 1, 2000.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
and include the activities of CP&L and its majority-owned subsidiaries.
Significant intercompany balances and transactions have been eliminated in
consolidation except as permitted by Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," which provides that profits on intercompany sales to regulated
affiliates are not eliminated if the sales price is reasonable and the
future recovery of the sales price through the rate making process is
probable. The accounting records are maintained in accordance with uniform
systems of accounts prescribed by the Federal Energy Regulatory Commission
(FERC), the North Carolina Utilities Commission (NCUC) and the Public
Service Commission of South Carolina (SCPSC). Certain amounts for 2000 and
1999 have been reclassified to conform to the 2001 presentation.
Unconsolidated investments in companies over which CP&L does not have
control, but has the ability to exercise influence over operating and
financial policies (generally, 20% - 50% ownership) are accounted for under
the equity method of accounting. Effective June 28, 2000, a subsidiary of
CP&L contributed the net assets used in its application service provider
business to a newly formed company (Interpath) for a 35% ownership interest
(15% voting interest) which is accounted for on a cost basis because CP&L
does not exercise significant influence over those operations. Other
investments are stated principally at cost. These investments, which total
approximately $121 million at December 31, 2001, are included as
miscellaneous other property and investments in the Consolidated Balance
Sheets.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with accounting
principles generally accepted in the United States of America, management
must make estimates and assumptions that affect the reported amounts of
assets and liabilities, disclosure of contingent assets and liabilities at
the date of the consolidated financial statements and amounts of revenues
and expenses reflected during the reporting period. Actual results could
differ from those estimates.
D. Utility Plant
The cost of additions, including betterments and replacements of units of
property, is charged to utility plant. Maintenance and repairs of property,
and replacements and renewals of items determined to be less than units of
property, are charged to maintenance expense. The cost of units of property
replaced, renewed or retired, plus removal or disposal costs, less salvage,
is charged to accumulated depreciation. Generally, electric utility plant,
other than nuclear fuel is pledged as collateral for the first mortgage
bonds of CP&L.
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The balances of utility plant in service at December 31 are listed below
(in thousands), with a range of depreciable lives for each:
2001 2000
----------- -----------
Electric
Production plant (7-33 years) $ 7,301,225 $ 6,659,111
Transmission plant (30-75 years) 1,092,024 1,060,080
Distribution plant (12-50 years) 3,063,753 2,869,104
General plant and other (8-75 years) 567,289 537,606
----------- -----------
Utility plant in service $12,024,291 $11,125,901
=========== ===========
As prescribed in the regulatory uniform systems of accounts, an allowance
for the cost of borrowed and equity funds used to finance utility plant
construction (AFUDC) is charged to the cost of the plant. 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 equity funds portion of AFUDC is credited to other income and
the borrowed funds portion is credited to interest charges. The total
equity funds portion of AFUDC was $8.8 million, $14.5 million and $3.9
million in 2001, 2000 and 1999, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2%, 8.2% and 6.4% in 2001, 2000 and
1999, respectively. The composite AFUDC rate for NCNG's gas utility plant
was 10.09% in 2000 and 1999, respectively.
E. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2001 2000
-------- --------
Telecommunications equipment $ 94,164 $ 76,694
Other equipment 11,657 8,368
Construction work in progress 21,622 25,603
Accumulated depreciation (15,641) (8,371)
-------- --------
Diversified business property, net $111,802 $102,294
======== ========
Diversified business property is stated at cost. Depreciation is computed
on a straight-line basis using the following estimated useful lives:
telecommunications equipment - 5 to 20 years and computers, office
equipment and software - 3 to 10 years.
F. Depreciation and Amortization
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated net salvage. Depreciation provisions, including decommissioning
costs (See Note 1G) and excluding accelerated cost recovery of nuclear
generating assets, as a percent of average depreciable property other than
nuclear fuel, were approximately 3.8% in 2001 and 2000 and 3.9% in 1999.
Depreciation provisions totaled $504.9 million, $688.8 million and $409.6
million in 2001, 2000 and 1999, respectively.
Depreciation and amortization expense also includes amortization of
deferred operation and maintenance expenses associated with Hurricane Fran,
which struck significant portions of CP&L's service territory in September
1996. In 1996, the NCUC authorized CP&L to defer these expenses
(approximately $40 million) with amortization over a 40-month period, which
expired in December 1999.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000 and
continuing through 2004. Also in 2000, CP&L received approval from the
commissions to further accelerate the cost recovery of its nuclear
generation facilities in 2000. The accelerated cost recovery of these
assets resulted in additional depreciation expense of approximately $75
million and $275 million in 2001 and 2000, respectively (See Note 8B).
Pursuant to authorizations from the NCUC and the SCPSC, CP&L accelerated
the amortization of certain regulatory assets over a three-year period
beginning January 1997 and expiring December 1999. The accelerated
amortization of these regulatory assets resulted in additional depreciation
and amortization expenses of approximately $68 million in 1999.
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE), is computed
primarily on the unit-of-production method and charged to fuel expense.
Costs related
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to obligations to the DOE for the decommissioning and decontamination of
enrichment facilities are also charged to fuel expense. The total of these
costs for the years ended December 31, 2001, 2000 and 1999 were $101.0
million, $112.1 million and $110.8 million, respectively.
G. Decommissioning Provisions
In CP&L's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC and the SCPSC, and are based on
site-specific estimates that include the costs for removal of all
radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by FERC. Decommissioning cost provisions, which are included in
depreciation and amortization expense, were $30.7 million in 2001 and 2000
and $33.3 million in 1999.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $604.8 million and $599.3 million at December 31, 2001
and 2000, respectively. These costs include amounts retained internally and
amounts funded in externally managed decommissioning trusts. Trust earnings
increase the trust balance with a corresponding increase in the accumulated
decommissioning balance. These balances are adjusted for net unrealized
gains and losses related to changes in the fair value of trust assets.
CP&L's most recent site-specific estimates of decommissioning costs were
developed in 1998, using 1998 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring shortly after operating license expiration. These estimates, in
1998 dollars, are $281.5 million for Robinson Unit No. 2, $299.6 million
for Brunswick Unit No. 1, $298.7 million for Brunswick Unit No. 2 and
$328.1 million for the Harris Plant. The estimates are subject to change
based on a variety of factors including, but not limited to, cost
escalation, changes in technology applicable to nuclear decommissioning and
changes in federal, state or local regulations. The cost estimates exclude
the portion attributable to North Carolina Eastern Municipal Power Agency
(Power Agency), which holds an undivided ownership interest in the
Brunswick and Harris nuclear generating facilities. Operating licenses for
CP&L's nuclear units expire in the year 2010 for Robinson Unit No. 2, 2016
for Brunswick Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the
Harris Plant.
Management believes that the decommissioning costs being recovered through
rates by CP&L, when coupled with reasonable assumed after-tax fund earnings
rates, are currently sufficient to provide for the costs of
decommissioning.
The Financial Accounting Standards Board has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations" that will impact the
accounting for decommissioning and dismantlement provisions (See Note 1J).
H. Other Policies
CP&L 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.
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by CP&L's regulators. These clauses allow CP&L to
recover fuel costs and portions of purchased power costs through surcharges
on customer rates.
CP&L maintains an allowance for doubtful accounts receivable, which totaled
approximately $12.2 million and $17.0 million at December 31, 2001 and
2000, respectively. Inventory, which includes fuel and materials and
supplies is carried at average cost. Long-term debt premiums, discounts and
issuance expenses for the utilities are amortized over the life of the
related debt using the straight-line method. Any expenses or call premiums
associated with the reacquisition of debt obligations by the utilities are
amortized over the remaining life of the original debt using the
straight-line method. CP&L considers all highly liquid investments with
original maturities of three months or less to be cash equivalents.
I. Impairment of Long-lived Assets and Investments
SFAS No. 121 " Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to Be Disposed Of" requires review of long-lived assets
and certain intangibles for impairment when events or circumstances
indicate that the carrying value of an asset may not be recoverable. Any
impairment losses are reported in the period in which the recognition
criteria are first applied based on the fair value of the asset.
Write-downs of investments are charged against earnings when a decline in
fair value is determined to be other-than-temporary. CP&L continually
reviews its investments to determine whether a decline in fair value below
the
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cost basis is other-than-temporary. During 2001, CP&L obtained a valuation
study to assess its investment in Interpath based on current valuations in
the technology sector. As a result, CP&L has recorded an investment
impairment of $156.7 million on a pre-tax basis for other-than-temporary
declines in the fair value of its investment in Interpath.
J. Impact of New Accounting Standards
Effective January 1, 2001, CP&L adopted Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS No. 138. SFAS No. 133, as amended,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and
for hedging activities. SFAS No. 133 requires that an entity recognize all
derivatives as assets or liabilities in the balance sheet and measure those
instruments at fair value.
As a result of the adoption of SFAS No. 133, CP&L recorded a transition
adjustment as a cumulative effect of a change in accounting principle of
$0.7 million, net of tax, which increased accumulated other comprehensive
loss as of January 1, 2001. This amount relates to several derivatives used
to hedge cash flows related to interest on long-term debt. The net
derivative losses will be reclassified into earnings consistent with hedge
designations, primarily over the life of the related debt instruments,
which principally range from three to ten years. CP&L estimates that
approximately $10.7 million of the net losses at December 31, 2001 will be
reclassified into earnings during 2002. There was no transition adjustment
affecting the Consolidated Statement of Income as a result of the adoption
of SFAS No. 133.
During the second quarter of 2001, the FASB issued interpretations of SFAS
No. 133 indicating that options in general cannot qualify for the normal
purchases and sales exception, but provided an exception that allows
certain electricity contracts, including certain capacity-energy contracts,
to be excluded from the mark-to-market requirements of SFAS No. 133. The
interpretations were effective July 1, 2001. Those interpretations did not
require CP&L to mark-to-market any of its electricity capacity-energy
contracts currently outstanding. In December 2001, the FASB revised the
criteria related to the exception for certain electricity contracts, with
the revision to be effective April 1, 2002. CP&L does not expect the
revised interpretation to change its assessment of mark-to-market
requirements for its current contracts. If an electricity or fuel supply
contract in its regulated businesses is subject to mark-to-market
accounting, there would be no income statement effect of the mark-to-market
because the contract's mark-to-market gain or loss will be recorded as a
regulatory asset or liability. Any mark-to-market gains or losses in its
non-regulated businesses will affect income unless those contracts qualify
for hedge accounting treatment.
The application of the new rules is still evolving, and further guidance
from the FASB is expected, which could additionally impact CP&L's financial
statements.
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations"
in July 2001. This statement provides accounting requirements for
retirement obligations associated with tangible long-lived assets and is
effective January 1, 2003. This statement requires that the present value
of retirement costs for which CP&L has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. CP&L is currently assessing the
effects this statement may ultimately have on accounting for
decommissioning, dismantlement and other retirement costs.
Effective January 1, 2002, CP&L adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." It also supersedes the accounting and reporting provisions of
APB Opinion No. 30, "Reporting the Results of Operations - Reporting the
Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual
and Infrequently Occurring Events and Transactions" related to the disposal
of a segment of a business. Adoption of this statement did not have a
material effect on CP&L's financial statements.
2. Acquisitions and Dispositions
A. North Carolina Natural Gas Corporation
On July 15, 1999, CP&L completed the acquisition of NCNG for an aggregate
purchase price of approximately $364 million, resulting in the issuance of
approximately 8.3 million shares. The acquisition was accounted for as a
purchase and, accordingly, the operating results of NCNG were included in
CP&L's consolidated financial statements beginning with the date of
acquisition. The excess of the aggregate purchase price over the fair value
of
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net assets acquired, approximately $240 million, was recorded as goodwill
of the acquired business and is amortized primarily over a period of 40
years. Effective July 1, 2000, CP&L distributed its ownership in NCNG stock
to its parent. As of that date, the results of NCNG are no longer included
in CP&L's Consolidated Statements of Income and NCNG's assets and
liabilities are no longer included in CP&L's Consolidated Balance Sheets.
B. BellSouth Carolinas PCS Partnership Interest
In September 2000, Caronet, Inc., a wholly owned subsidiary of CP&L, sold
its 10% limited partnership interest in BellSouth Carolinas PCS for $200
million. The sale resulted in an after-tax gain of $121.1 million.
3. Financial Information by Business Segment
As described in Note 1A, on July 1, 2000, CP&L distributed its ownership
interest in the stock of NCNG, SRS, Monroe Power and Progress Ventures,
Inc. to Progress Energy. As a result, those companies are direct
subsidiaries of Progress Energy and are not included in CP&L's results of
operations and financial position since that date.
Through June 30, 2000, the business segments, operations and assets of
Progress Energy and CP&L were substantially the same. Subsequent to July 1,
2000, CP&L's operations consist primarily of the CP&L Electric segment, the
investment impairment described in Note 1I and the gain on sale of assets
described in Note 2B. Subsequent to July 1, 2000, CP&L has no other
material segments.
The financial information for the CP&L Electric segment for the years ended
December 31, 2001, 2000 and 1999 is as follows:
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended
(In thousands) December 31, 2001 December 31, 2000 December 31, 1999
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues $3,343,720 $3,308,215 $3,146,158
Depreciation and Amortization 521,910 698,633 493,938
Net Interest Charges 241,427 221,856 183,099
Income Taxes 264,078 227,705 275,769
Net Income 468,328 373,764 430,295
Total Segment Assets 8,918,691 8,839,720 8,501,273
Capital and Investment Expenditures 823,952 805,489 671,401
=====================================================================================================
</TABLE>
The primary differences between the CP&L Electric segment and CP&L
consolidated financial information relate to other non-electric operations
and elimination entries.
4. Related Party Transactions
CP&L participates in an internal money pool, operated by the Company, to
more effectively utilize cash resources and to reduce outside short-term
borrowings. Short-term borrowing needs are met first by available funds of
the money pool participants. Borrowing companies pay interest at a rate
designed to approximate the cost of outside short-term borrowings.
Subsidiaries which invest in the money pool earn interest on a basis
proportionate to their average monthly investment. The interest rate used
to calculate earnings approximates external interest rates. Funds may be
withdrawn from or repaid to the pool at any time without prior notice. At
December 31, 2001, CP&L had $1.8 million of amounts receivable from the
money pool that are included in receivables from affiliated companies on
the Consolidated Balance Sheets and $49.7 million of amounts payable to the
money pool that are included in payables to affiliated companies on the
Consolidated Balance Sheets. At December 31, 2000, CP&L had $30.5 million
of amounts receivable from the money pool that are included in receivables
from affiliated companies on the Consolidated Balance Sheets. CP&L recorded
$1.6 million of interest income and $1.7 million of interest expense
related to the money pool for 2001. Amounts recorded for interest income
and interest expense related to the money pool for 2000 were not
significant.
During 2000, the Company formed Progress Energy Service Company, LLC (PESC)
to provide specialized services, at cost, to the Company and its
subsidiaries, as approved by the Securities and Exchange Commission. CP&L
has an agreement with PESC under which services, including purchasing,
accounting, treasury, tax, marketing, legal and human resources, are
rendered to CP&L at cost. Amounts billed to CP&L by PESC for these services
during 2001 and 2000 amounted to $173.9 million and $52.4 million,
respectively. At December 31, 2001 and 2000, CP&L had net payables of $46.0
million and $250.7 million, respectively, to PESC that are included in
payables to affiliated
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companies on the Consolidated Balance Sheets. Subsidiaries of CP&L had
amounts receivable from PESC of $13.7 million at December 31, 2001.
During the years ended December 31, 2001, 2000 and the period from July 15,
1999 to December 31, 1999, gas sales from NCNG to CP&L amounted to $14.7
million, $5.9 million and $1.0 million, respectively.
For the year ended December 31, 2001 and the period from July 1, 2000 to
December 31, 2000, the Consolidated Statements of Income contain interest
income received from NCNG in the amount of $4.8 million and $4.1 million,
respectively. Prior to July 1, 2000, the interest income received from NCNG
was eliminated in consolidation. At December 31, 2001 and 2000, CP&L h