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<SEC-DOCUMENT>0000950168-01-000603.txt : 20010410
<SEC-HEADER>0000950168-01-000603.hdr.sgml : 20010410
ACCESSION NUMBER: 0000950168-01-000603
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 10
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010328
DATE AS OF CHANGE: 20010402
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: PROGRESS ENERGY INC
CENTRAL INDEX KEY: 0001094093
STANDARD INDUSTRIAL CLASSIFICATION: 4911
IRS NUMBER: 562155481
STATE OF INCORPORATION: NC
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-15929
FILM NUMBER: 1582977
BUSINESS ADDRESS:
STREET 1: 411 FAYETTEVILLE STREET
CITY: RALEIGH
STATE: NC
ZIP: 27601
BUSINESS PHONE: 9195466463
MAIL ADDRESS:
STREET 1: 411 FAYETTEVILLE STREET
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
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: CAROLINA POWER & LIGHT CO
CENTRAL INDEX KEY: 0000017797
STANDARD INDUSTRIAL CLASSIFICATION: 4911
IRS NUMBER: 560165465
STATE OF INCORPORATION: NC
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-03382
FILM NUMBER: 1582978
BUSINESS ADDRESS:
STREET 1: 411 FAYETTEVILLE ST
CITY: RALEIGH
STATE: NC
ZIP: 27601
BUSINESS PHONE: 9195466111
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>FORM 10-K
<TEXT>
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, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
<TABLE>
<CAPTION>
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
<S> <C> <C>
Progress Energy, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
1-15929 State of Incorporation: North Carolina 56-2155481
Carolina Power & Light Company
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
1-3382 State of Incorporation: North Carolina 56-0165465
</TABLE>
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
-----------------------------------------------------------
Title of each class Name of each exchange on which registered
- - - - - - ------------------- -----------------------------------------
Progress Energy, Inc.:
Common Stock (Without Par Value) New York Stock Exchange
Pacific Stock Exchange
Carolina Power & Light Company:
Quarterly Income Capital Securities New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
-----------------------------------------------------------
Progress Energy, Inc.: None
Carolina Power & Light Company: $100 par value Preferred Stock, Cumulative
$100 par value Serial Preferred Stock,
Cumulative
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. Each registrant makes no representation as
to information relating exclusively to the other registrant.
As of February 28, 2001, the aggregate market value of the voting and non-voting
common equity of Progress Energy, Inc. held by non-affiliates was
$8,888,502,892. All of the common stock of Carolina Power & Light
<PAGE>
Company is owned by Progress Energy, Inc. As of February 28, 2001, each
registrant had the following shares of common stock outstanding:
<TABLE>
<CAPTION>
Registrant Description Shares
---------- ----------- ------
<S> <C> <C>
Progress Energy, Inc. Common Stock (Without Par Value) 206,082,949
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055
</TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
-----------------------------------
Portions of the Progress Energy and CP&L definitive proxy statements dated April
2, 2001 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 REGISTRANT
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 QUALATIVE 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 BellSouth Corporation
BellSouth Carolinas PCS BellSouth Carolinas, PCS L.P.
BellSouth PCI BellSouth Personal Communications, Inc.
Btu British thermal units
Caronet Caronet, Inc.
Comprehensive Environmental Response, Compensation and Liability Act of
CERCLA 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
North Carolina Department of Environment and Natural Resources, Division of
DWM Waste Management
Eastern Eastern North Carolina Natural Gas Company
ENCNG Eastern North Carolina Natural Gas Company, LLC
EPS Earnings per share
Energy Ventures Progress Energy Ventures, Inc. (formerly known as CPL Energy Ventures, Inc.)
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
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
<S> <C>
Pine Needle Pine Needle LNG Company, LLC
PLRs 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.
Progress Energy Progress Energy, Inc.
Progress Rail Progress Rail Services Corporation
Progress Telecom Progress Telecommunications Corporation
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
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
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
Yankee Atomic Yankee Atomic Electric Company
</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 estimated capital
requirements through the year 2003 and future financing plans, 2) "Future
Outlook" about the Company'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 the Company undertakes no 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 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; the outcome of legal and administrative proceedings before
our principal regulators; risks associated with operating nuclear power
facilities, availability of nuclear waste storage facilities, and nuclear
decommissioning costs; 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 recent 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 the Company.
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
the Company.
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 CPL Energy Ventures, Inc. (Energy
Ventures) 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 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.
The Company also engages in non-regulated business areas such as
telecommunications, coal and synthetic fuel operations, energy management and
related services, and merchant energy generation through other wholly-owned
subsidiaries.
Progress Energy revenues for the year ended December 31, 2000, were $4.1
billion, and assets at year-end were $20.1 billion. Its principal executive
offices are located at 411 Fayetteville Street, Raleigh, North Carolina 27601,
telephone number (919) 546-6111. The Progress Energy home page on the Internet's
World Wide Web 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.
Progress Energy defines its principal business segments in four major
categories: two electric utilities (CP&L and Florida Power), a natural gas
utility and other. The electric utility segments encompass all regulated utility
operations of CP&L and Florida Power. The natural gas utility segment includes
NCNG's regulated natural gas operations. The other segment includes
non-regulated energy businesses including merchant energy generation and coal
and synthetic fuel operations. The other category also provides various products
and services for energy and facility management and telecommunications and
includes certain holding company results. 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 contingent value obligations (CVO) valued at approximately $49.3
million. See Note 2A to the Progress Energy consolidated financial statements
for additional discussion of the FPC acquisition.
The acquisition has been 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.
Preliminary goodwill of approximately $3.4 billion has been recorded and is
being amortized on a straight-line basis over a period of primarily 40 years.
7
<PAGE>
FPC is a diversified 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. (Progress
Capital) which includes Electric Fuels Corporation (EFC), an energy and
transportation company. The primary segments of EFC are Energy and Related
Services, Rail Services, and Inland Marine Transportation.
Progress Energy has announced its intention to sell two of the non-utility
business segments acquired in the transaction, Rail Services and Inland Marine
Transportation. Therefore, the results of operations of these segments are not
included in the Company's consolidated earnings and the related assets and
liabilities are presented as net assets held for sale on the Company's
consolidated balance sheets.
As a result of the acquisition, Progress Energy is now a registered holding
company subject to regulation by the Securities and Exchange Commission (SEC)
under PUHCA. Pursuant to the SEC's order dated November 27, 2000, the Company
has committed to divest of certain immaterial non-utility businesses. The
Company has also agreed to file a response or responses with the SEC by November
30, 2001 that will either provide a legal basis for retaining certain other
non-utility businesses or a commitment to divest of those businesses. On March
22, 2001, the Company filed a post effective amendment requesting an SEC order
to divest of certain holdings of EFC.
The acquisition of FPC positions Progress Energy as a regional energy company
focusing on the high-growth Southeast region of the United States. Progress
Energy currently serves approximately 2.8 million customers in portions of North
Carolina, South Carolina and Florida. The darkly shaded area of the following
map shows Progress Energy's utility service territory at December 31, 2000.
[GRAPHIC OMITTED]
Progress Energy currently has more than 19,000 megawatts of generation capacity
with a competitively balanced generation fuel mix. Additionally, 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
mix. The following charts show Progress Energy's generation portfolio and
revenue mix at December 31, 2000:
Generation Portfolio Revenue Mix
[GRAPHIC OMITTED] [GRAPHIC OMITTED]
Coal 40% Residential 42%
Gas/Oil 38% Commercial 23%
Nuclear 21% Industrial 14%
Hydro 1% Other 21%
8
<PAGE>
BellSouth Carolinas PCS Partnership Interest Sale
On September 11, 2000, Caronet, Inc., a wholly-owned subsidiary of CP&L, entered
into an Agreement to Settle and Merger Plan (the Agreement) by and among DukeNet
Communications, Inc.; BellSouth Personal Communications, Inc., (BellSouth PCI);
BellSouth Corporation, (BellSouth), and BellSouth Carolinas PCS, L.P.,
(BellSouth Carolinas PCS) and CP&L. The transaction closed on September 28,
2000. Pursuant to the terms of the Agreement, BellSouth PCI acquired the
interests of the limited partners in BellSouth Carolinas PCS in conjunction with
a merger of BellSouth Carolinas PCS into BellSouth PCI (the Merger). As
consideration for the Merger, BellSouth PCI paid the limited partners $20
million for each one percent interest in BellSouth Carolinas PCS. Upon
consummation of the Merger, CP&L received $200 million for Caronet, Inc.'s 10%
limited partnership interest in BellSouth Carolinas PCS. This sale resulted in
an after-tax gain of $121.1 million.
NCNG Acquisition
On July 15, 1999, the Company completed the acquisition of NCNG, now operating
as a wholly-owned subsidiary. Each outstanding share of NCNG common stock was
converted into the right to receive 0.8054 shares of Company common stock,
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
have been included in the Company's consolidated financial statements since 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.
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 the year 2000. So far 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 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
states 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 provides guidance and specifies
minimum characteristics and functions required of an RTO and
9
<PAGE>
also states that all RTOs should be operational by December 15, 2001. See PART
I, ITEM 1, "Competition" of CP&L Electric and Florida Power Electric for a
discussion of 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 essentially
every other state has, 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 Natural Gas for further discussion of competitive
developments within these segments.
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 2001 through
2003 are included in the estimates under the "Investing Activities" discussion
under PART II, ITEM 7, "Liquidity and Capital Resources."
CLEAN AIR LEGISLATION
- - - - - - ---------------------
The 1990 amendments to the Clean Air Act require substantial reductions in
sulfur dioxide and nitrogen oxide emissions from fossil-fueled electric
generating plants. The Clean Air Act required the Company to meet more stringent
provisions effective January 1, 2000. The Company meets the sulfur dioxide
emissions requirements by maintaining sufficient sulfur dioxide emission
allowances. Installation of additional equipment was necessary to reduce
nitrogen oxide emissions. Increased operation and maintenance costs, including
emission allowance expense, installation of additional equipment and increased
fuel costs are not expected to be material to the consolidated financial
position or results of operations of the Company.
The U.S. Environmental Protection Agency (EPA) 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 have recently been asked to provide
information to the EPA as part of this initiative and have cooperated in
providing the requested information. The EPA has initiated enforcement actions
against other 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. 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 and South Carolina, 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. 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
10
<PAGE>
sources to make reductions in nitrogen oxide emissions by 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 are participating in litigation challenging the EPA's action. 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 Environment and 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
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 EFC 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
- - - - - - ---------------------------
Both electric utilities and the gas utility 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 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.
EMPLOYEES
- - - - - - ---------
As of February 28, 2001, Progress Energy and its subsidiaries employed
approximately 16,000 full-time employees. Of this total, approximately 2,100
employees 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, 2001, CP&L employed approximately 5,300 full-time employees.
11
<PAGE>
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. CP&L has a total
summer generating capacity (including jointly-owned capacity) of 10,961
megawatts (MW).
CP&L generates, transmits, 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 33,667 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 approximately 4.2 million. At December 31,
2000, CP&L was providing electric services, retail and wholesale, to
approximately 1.2 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).
BILLED ELECTRIC REVENUES
- - - - - - ------------------------
CP&L's electric revenues billed by customer class, for the last three years, is
shown as a percentage of total electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2000 1999 1998
------------- ---- ---- ----
Residential 33% 34% 33%
Commercial 22% 22% 22%
Industrial 23% 24% 26%
Wholesale 18% 18% 17%
Other retail 4% 2% 2%
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 Power Agency's share) by primary
energy source, along with purchased power, for the last three years is set forth
below:
ENERGY MIX PERCENTAGES
2000 1999 1998
---- ---- ----
Coal 49% 48% 47%
Nuclear 42% 42% 42%
Hydro 1% 1% 1%
Oil/Gas 1% 1% 1%
Purchased Power 7% 8% 9%
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:
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AVERAGE FUEL COST
(per million Btu)
2000 1999 1998
---- ---- ----
Coal $ 1.70 $ 1.70 $ 1.67
Nuclear 0.45 0.46 0.46
Hydro - - -
Oil (a) 5.51 3.70 3.58
Gas (a) 5.41 3.37 3.02
Weighted Average 1.21 1.16 1.14
(a) The unit price for oil and gas increased significantly from 1999 to
2000 due to market conditions. Since these costs are recovered through
recovery clauses established by regulators, the increase does not
affect net income.
Coal
CP&L has intermediate and long-term agreements from which it expects to receive
approximately 80% of its coal burn requirements in 2001. These agreements have
expiration dates ranging from 2001 to 2006. All of the coal that CP&L is
currently purchasing under intermediate and long-term agreements is considered
to be low sulfur coal by industry standards. Recent amendments to the Clean Air
Act may result in increases in the price of low sulfur 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 the 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
CP&L uses No. 2 oil primarily for its combustion turbine units, which are used
for emergency backup and peaking purposes, and for boiler start-up and flame
stabilization. CP&L has a No. 2 oil supply contract for its normal requirements.
In the event base-load capacity is unavailable during periods of high demand,
CP&L may increase the use of its combustion turbine units, thereby increasing
No. 2 oil consumption. CP&L intends to meet any additional requirements for No.
2 oil through additional contract purchases or purchases in the spot market. To
reduce CP&L's vulnerability to the lack of No. 2 oil availability, ten dual fuel
combustion turbine units with a total generating capacity of 982 MW can also
burn natural gas. Gas is the primary fuel used at the dual fuel units during the
summer peak season. There can be no assurance that adequate supplies of No. 2
oil will be available to meet CP&L's requirements. The availability and cost of
fuel oil could be affected by energy legislation enacted by Congress and
disruption of oil or gas supplies.
Purchased Power
CP&L purchased 4,467,802 MWh in 2000, 4,730,657 MWh in 1999 and 5,336,867 MWh in
1998 or approximately
13
<PAGE>
7%, 8% and 9%, respectively, of its system energy requirements (including Power
Agency) and had available 1,306 MW in 2000, 1,489 MW in 1999 and 1,438 MW in
1998 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 related to deregulation of the electric industry in
California and other states.
o 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. In its January 23,
2001 meeting, the commission requested that the NCUC review the
requirements for certification of new generating capacity in North
Carolina and consider changes to streamline the process. Subsequently,
the NCUC initiated action requesting comments from interested parties.
The Company cannot predict the outcome of this matter.
o 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. The three companies
are continuing to make progress in developing GridSouth and are planning to make
a supplemental filing to the original GridSouth RTO application in mid 2001 that
will include generator interconnection procedures and more detail on congestion
management. On March 14, 2001, FERC conditionally approved GridSouth, provided
it make certain modifications to the board selection process, passive owners'
veto powers and take steps to expand its geographic area. FERC directed
GridSouth to file a status report by May 13, 2001 on efforts to expand the scope
of the proposed RTO. FERC also directed GridSouth to file its rates sixty days
prior to operation, and submit a plan that sets forth specific milestones for
transmission planning and expansion.
Franchises
CP&L holds franchises to the extent necessary to operate its regulated electric
operations in the municipalities and other areas it serves.
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
14
<PAGE>
FERC in mid-1996. Shortly thereafter, Power Agency and other entities filed
protests challenging numerous aspects of CP&L's tariff and requesting that an
evidentiary proceeding be held. FERC set the matter for hearing and set a
discovery and procedural schedule. In July 1997, CP&L filed an offer of
settlement in this matter. The administrative law judge certified the offer to
the full FERC 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. CP&L
made additional compliance filings on June 8, 2000 and July 12, 2000 to report
the status of negotiations with the remaining intervenors. On August 25, 2000,
CP&L filed modifications to its open access transmission tariff as a result of
settlement negotiations with the remaining intervenors. 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 Progress Energy's PART II, ITEM 7, "Retail Rate Matters" for additional
discussion of CP&L's retail rate developments during 2000.
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
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. Pursuant to the
orders, CP&L's 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 in 2000 by
$125 million. This additional depreciation will allow CP&L to reduce the minimum
annual accelerated depreciation in 2001 through 2004 to $75 million. The
resulting total accelerated depreciation in 2000 was $275 million. 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
15
<PAGE>
See Progress Energy's PART II, ITEM 7, "Current Regulatory Environment - Energy
Costs Provisions" for information on energy costs that CP&L is able to recover
in North Carolina and South Carolina.
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
Harris Plant. Plans are in place to request the extension of the Robinson and
Brunswick operating licenses in 2002 and 2004, respectively. 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.
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.
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 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. 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 will respond to
the petition and the request for stay. CP&L cannot predict the outcome of this
matter.
See PART II, ITEM 8, footnote 15.C.2 to the Carolina Power & Light Company
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 and South Carolina were participants
in the Southeast Regional Compact and disposed of waste at a disposal site in
South Carolina
16
<PAGE>
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 over the next 8 years.
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, which has been accepting
lower activity low-level waste, has requested a license amendment to receive and
dispose of low-level Class B and C 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 Carolina
Power & Light Company 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. Actions are
pending in the Court of Federal Claims and in the Federal District Court for the
Southern District of New York.
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. 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 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 $51 million in special assessments, 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 the District Court case (discussed below). 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. CP&L cannot predict the
17
<PAGE>
outcome of this matter.
In June 1998, a number of other utilities filed an action for declaratory
judgement against the United States government 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. The complaint was amended to add CP&L (among others) as a
party to this litigation by order of the Court dated November 29, 1999. A total
of 22 utilities are participating in this action.
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 affirmed the District Court ruling. The Government filed
for rehearing in January, 2001, and the utilities filed their response in
February, 2001. 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. Florida Power has a total summer generating capacity (including
jointly-owned capacity) of 8,012 MW. Florida Power has no other material
segments of business.
Florida Power provided electric service during 2000 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.
BILLED ELECTRIC REVENUES
- - - - - - ------------------------
Florida Power's electric revenues billed by customer class, for 2000 is shown as
a percentage of total electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2000 (a)
------------- --------
Residential 53%
Commercial 24%
Industrial 8%
Other retail 5%
Wholesale 10%
(a) These figures reflect Florida Power's billed electric for the year ended
December 31, 2000, which is representative of the period Progress Energy
owned Florida Power.
Important industries in the 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.
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 2000 is presented in the following table:
18
<PAGE>
ENERGY MIX PERCENTAGES
Fuel Type 2000 (a)
--------- --------
Coal (b) 34%
Oil 15%
Nuclear 15%
Gas 14%
Purchased Power 22%
(a) These figures reflect Florida Power's energy mix percentages for the year
ended December 31, 2000, which is representative of the period Progress
Energy owned Florida Power.
(b) Includes synthetic fuel and pet 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 2000 were as follows:
AVERAGE FUEL COST
(per million Btu)
2000 (a)
--------
Coal (b) $1.89
Oil 4.15
Nuclear .47
Gas 4.32
Weighted Average 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 and pet coke.
Coal
Florida Power anticipates a combined requirement of approximately 5.5 million to
6.0 million tons of coal and synthetic fuel in 2001. 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 EFC pursuant to contracts between
Florida Power and EFC, which expire in 2002 and 2004.
For 2001, EFC has long-term contracts with various sources for approximately 38%
of the fuel requirements of Florida Power's coal units. These long-term
contracts have price adjustment provisions. EFC expects to acquire the remainder
in the spot market and under short-term contracts. EFC does not anticipate any
problems obtaining the remaining Florida Power requirements for 2001 through
short-term contracts and purchases in the spot market.
Oil and Gas
Oil is purchased under contracts and in the spot market from several suppliers.
The cost of Florida Power's oil is determined by world market conditions.
Management believes that Florida Power has access to an adequate supply 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 that is 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.
19
<PAGE>
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 1,300
MW of firm power under a variety of purchase power agreements. As of December
31, 2000, 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 legislative session began during the
first week of March and concludes during the first week of May. The wholesale
restructuring outline is intended to facilitate the evolution of a more robust
wholesale marketplace in Florida. See Progress Energy's PART II, ITEM 7, "Other
Matters" for a list of the key provisions proposed by the study commission.
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 an RTO
for peninsular Florida, currently named GridFlorida. On January 10, 2001, FERC
rendered a positive order on certain aspects of the GridFlorida RTO application,
specifically governance and certain financial obligations. The three companies
are continuing to make progress towards the development of GridFlorida.
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 state and 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. Approximately 37% of Florida Power's total utility revenues for 2000
were from the incorporated areas of the 109 municipalities that have enacted
franchise ordinances. The general effect of these franchises is to provide for
the manner in which Florida Power occupies rights-of-way in incorporated areas
of municipalities for the purpose of constructing, operating and maintaining an
energy transmission and distribution system. All but three of the existing
franchises cover a 30-year period from the date enacted. The exceptions are two
franchises each with a term of 10 years from the date enacted, which expire in
2001 and 2005, and a franchise with a term of 20 years expiring in 2020. Of the
109 franchises, 17 expire during 2001, 12 expire during 2002, 20 expire between
January 1, 2003 and December 31, 2012 and 60 expire between January 1, 2013 and
December 31, 2030. Ongoing negotiations are taking place with the municipalities
20
<PAGE>
to reach agreement on franchise terms and to enact new franchise ordinances. In
addition to the regulation of rights-of-way, quality of service and flexible
terms that anticipate retail competition are among the factors considered by
municipalities negotiating new franchise ordinances.
Stranded Costs
For Florida Power, the single largest stranded cost exposure is its commitments
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.
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%.
Fuel Cost Recovery
See Progress Energy's PART II, ITEM 7, "Energy Costs Provisions" for a
discussion of costs that Florida Power is allowed to recover in Florida.
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. Plans are in place to request the
extension of the CR3 operating license in 2005. 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
United States Department of Energy (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 plans to expand 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.
Enrichment Facilities Decontamination
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
21
<PAGE>
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 $13 million in special assessments,
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 of approximately $9.5
million, plus interest.
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 affirmed the District Court ruling. The Government filed for rehearing in
January 2001.
NATURAL GAS
- - - - - - -----------
GENERAL
- - - - - - -------
NCNG transports, distributes and sells natural gas to over 105,600 residential
customers, over 14,000 commercial and agricultural customers and 473 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 which serve over 53,300 end
users. NCNG serves principally the following cities and towns: Albermarle, Dunn,
Fayetteville, Goldsboro, Greenville, Jacksonville, Indian Trail, Kinston,
Lumberton, New Bern, Monroe, Roanoke Rapids, Rockingham, Rocky Mount,
Smithfield/Selma, Southern Pines, Wilmington and Wilson. Natural Gas operations
are subject to the rules and regulations of the NCUC.
SEASONALITY
- - - - - - -----------
The natural gas business is seasonal in nature. Cold weather affects customer
demand in high priority markets and generally results in greater earnings during
the winter months. In NCNG's October 1995 General Rate Order, residential and
commercial rates were increased while industrial rates were decreased. This
action further increased the seasonal variation in NCNG's revenues, margins and
earnings because residential and commercial consumption increases in the winter
months and industrial consumption increases in the summer months. However,
NCNG's weather normalization adjustment, deliveries to high load factor
industrial customers, together with summer season deliveries for agricultural
crop drying and electricity generation, help to minimize quarterly variations in
throughput volumes and earnings.
NCNG normally injects gas into storage during periods of warm weather and
withdraws it during periods of cold weather. NCNG also utilizes storage and
various other contracts to provide adequate daily supply to meet peak-day
requirements.
NATURAL GAS SUPPLY
- - - - - - ------------------
NCNG has long-term firm gas supply contracts with major producers and national
natural gas marketers. During 2000, NCNG purchased 13,659,726 dekatherms (dt) of
natural gas under our firm sales contracts with Transcontinental Gas Pipeline
Corporation (Transco). NCNG also purchased 28,018,176 dt in the spot market or
under long-term contracts with producers or natural gas marketers. Additionally,
NCNG transported 15,347,951 dt of customer-owned gas in 2000. The outlook for
natural gas supplies in our service area remains favorable, and many sources of
gas are available on a firm basis.
NCNG's firm transportation contracts enable NCNG to acquire gas directly from
producers or other natural gas marketers and have the gas transported on a firm
basis at delivered costs that reflect the market price of natural gas in any
month. NCNG's primary objectives are to secure adequate and reliable gas
supplies on reasonable terms and conditions consistent with NCNG's obligation to
provide service to NCNG's firm service customers at the lowest reasonable cost.
Spot market purchases will continue to be utilized primarily in the off-peak
months (generally
22
<PAGE>
March through November) to supplement purchases under firm supply agreements.
The Transco firm sales contract provides gas supplies of up to 55,935 dt/day,
which NCNG uses to accommodate our supply needs resulting from day-to-day
changes in the level of demand on NCNG's system.
NCNG obtains its winter supplies and some of the summer supplies on a firm basis
in order to provide reliable supplies to residential, commercial and small
industrial customers who have no alternative fuel sources readily available and
whose consumption is not impacted materially by price. Reservation fees, which
continued to decline in 2000, are paid to firm suppliers to insure the
availability of natural gas supply at all times, particularly during the coldest
days when gas is most needed by core market customers. NCNG augments its flowing
supply with various storage services, including NCNG's liquefied natural gas
(LNG) storage plant and additional capacity under its contract with Pine Needle
LNG Company, LLC (Pine Needle). The LNG storage plant provides 97,200 dt per day
to NCNG's peak-day delivery capability. Pine Needle owns and operates a
liquefied natural gas plant located in Guilford County, North Carolina near the
interconnection of Transco's pipeline with Cardinal Pipeline.
Pricing under these contracts fluctuate with market prices and, during 2000,
these prices have increased. See Progress Energy's PART II, ITEM 7, "Results of
Operations", for a discussion of NCNG's increases in the market price of gas
during 2000.
COMPETITION
- - - - - - -----------
General
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 our service territory, we are 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 NCNG 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 2000, approximately 49% 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.
The price sensitive volume adjustment (PSVA) requires that all margins earned
from the eight large, fuel-switchable customers subject to the adjustment be
passed through to all other customers. Although NCNG has historically benefited
from the favorable spread between the prices of both No. 2 fuel oil and propane,
as compared to natural gas, and have remained competitive in most instances with
No. 6 fuel oil, the market could be affected by volatility in the price of fuel
oil as well as increases in the price of natural gas. See Progress Energy's
PART II, ITEM 7, "Results of Operations," for a discussion of increases in the
market price of natural gas during 2000.
By purchasing from several reputable suppliers, NCNG obtains its gas supplies at
the lowest reasonable cost, consistent with NCNG's public utility obligation to
supply gas on demand to most of its high priority markets. NCNG also serves a
substantial interruptible industrial market that does not require firm gas
supplies. During the year, many of these interruptible customers purchase their
gas supplies from suppliers other than NCNG, and NCNG transports the gas for
them to their plants. In some instances NCNG sells available gas supply to such
customers. When necessary, NCNG is allowed to negotiate the sales rate to meet
alternative fuel prices and recovers the discount through a deferred gas
account. Because the NCUC establishes transportation rates on a full-margin
basis, NCNG earns approximately the same amount of margin on the transportation
of gas as the margin on the sale of gas.
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<PAGE>
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 67 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, 2001,
two franchise agreements have expired and are under negotiation. A new town,
Wilson Mills, is also under negotiation. NCNG expects all negotiations to result
in 10 or 20-year renewal agreements. In the event that these franchise
agreements cannot be renegotiated, 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 three 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.
On July 28, 1998, the NCUC initiated a review to determine whether NCNG was
providing adequate service to at least some portion of the 47 counties in the
franchise territory. Hearings were held December 7 and 8, 1998. On March 17,
1999, the NCUC issued an order requiring NCNG to forfeit its exclusive franchise
rights to 14 of 17 unserved counties in eastern North Carolina for failing to
adequately serve these counties. NCNG had not previously initiated service to
these counties due to the small population and resulting infeasibility.
Furthermore, the order required NCNG to complete the expansion project to
provide service in the remaining three counties (Bertie, Martin and Onslow) by
July 1, 2000. These projects were completed by the imposed deadline. NCNG does
not expect the loss of exclusive franchise rights to serve these 14 counties to
have a material adverse impact on NCNG's future prospects.
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. See Progress
Energy's PART II, ITEM 7, "Future Outlook" for a discussion of recent
developments with the Richmond County plant.
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 14 currently unserved counties in
eastern North Carolina, as discussed above. In furtherance of this project, CP&L
and APEC formed Eastern North Carolina Natural Gas Company, LLC (ENCNG). CP&L
and APEC are joint owners of ENCNG, which will be subject to the rules and
regulations of the NCUC. CP&L will utilize NCNG to operate both the transmission
and distribution systems, and APEC will help ensure 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, CP&L and APEC filed a
joint request with the NCUC for $186 million of a $200 million state bond
package established for natural gas infrastructure to pay for the portion of the
project that likely could not be recovered from future gas customers through
rates. On June 15, 2000, the NCUC issued an order awarding ENCNG an exclusive
franchise to all 14 counties and 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. The NCUC will consider approval
of bond funding for subsequent phases of the project at a later date.
On March 7, 2001, ENCNG was dissolved and reorganized into a corporation named
Eastern North Carolina Natural Gas Company (Eastern). Progress Energy and APEC
are the sole shareholders of Eastern with each entity owning 50% of Eastern.
Progress Energy has agreed to fund a portion of the project, which is
currently estimated to be approximately $22 million.
24
<PAGE>
REGULATORY MATTERS
- - - - - - ------------------
General
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
During 2000, NCNG had five rate changes related to gas costs: a decrease
effective January 1, 2000; and 4 increases effective June 1, 2000; August 1,
2000; September 1, 2000; and November 1, 2000. In addition, NCNG filed one more
rate increase on December 17, 2000, with an effective date of January 1, 2001.
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.
As part of the October 27, 1995 order, the NCUC also approved the establishment
of a PSVA mechanism that became effective November 1, 1995. The PSVA excludes
from NCNG's revenue requirement the margin from eight large, fuel-switchable
customers, and requires that all actual margins earned on deliveries of gas to
such customers be passed through to all other customers.
The NCUC, in a general rule making proceeding, revised its purchased gas
adjustment procedures in April 1992. The revised procedures continue to allow
NCNG to recover all of the prudently incurred gas costs, but such procedures
provide for several significant changes that include:
o the immediate recovery of 100% of prudently incurred fixed costs of new
pipeline capacity and storage costs without the requirement of a general
rate case;
o the establishment of a tariff provision that allows NCNG to recover margin
losses from negotiated rates to large non-PSVA commercial and industrial
customers;
o a comparison of actual fixed gas costs incurred to fixed gas costs
collected from NCNG's customers, for which any over or under collection is
recovered or refunded, as applicable, through the use of a deferred gas
account;
o an annual review of NCNG's lost, unaccounted for and company use volumes
compared to such volumes included in the last general rate case; and
o an annual review of NCNG's gas costs, including the prudence thereof, by
the NCUC and a hearing before the NCUC. The penalty for gas purchases that
are not prudent is a potential disallowance of gas costs. NCNG has not been
found imprudent in any of the previous purchases.
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.
OTHER
- - - - - - -----
GENERAL
- - - - - - -------
The other segment primarily includes SRS, Energy Ventures, Progress Capital,
Progress Telecommunications Corporation (Progress Telecom), and Caronet.
SRS offers a comprehensive suite of innovative solutions for energy management
and building automation including facilities management software applications.
SRS' portfolio of software, 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
nationwide.
Energy Ventures is a subsidiary created in 2000 that is involved in the
development and construction of gas-fired merchant generation plants and has an
ownership interest in three synthetic fuel facilities. These synthetic fuel
facilities combine a chemical change agent with coal fines to produce a
synthetic fuel. Because this process is accomplished through a significant
chemical reaction, the resulting product has been classified as a synthetic fuel
25
<PAGE>
within the meaning of Section 29 of the IRS 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.
Monroe Power, a non-regulated merchant plant located in Monroe, Georgia, began
operations in December 1999. Monroe added an additional generating unit in March
of 2001 that will provide additional output and contracted sales in the future.
Progress Capital is a wholly-owned subsidiary of FPC and holds the capital stock
of, and provides funding for, FPC's non-utility subsidiaries. Its primary
subsidiary is EFC. Formed in 1976, EFC is an energy and transportation company
with operations organized into three business units. EFC's energy and related
services business unit supplies coal to Florida Power's Crystal River Energy
Complex and other utility and industrial customers. This business unit also
produces and sells natural gas and synthetic fuel along with operating terminal
services and offshore marine transportation. EFC is currently responsible for
managing all of Progress Energy's synthetic fuel facilities as described above.
EFC's inland marine transportation business unit, MEMCO Barge Line, Inc.
(MEMCO), transports coal and dry-bulk cargoes primarily on the Mississippi,
Illinois and Ohio rivers. The rail services business unit, led by Progress Rail
Services Corporation (Progress Rail), is one of the largest integrated
processors and suppliers of railroad materials in the country. With operations
in 24 states, Canada and Mexico, Progress Rail offers a full range of railcar
parts, maintenance-of-way equipment, rail and other track material, railcar
repair facilities, railcar scrapping and metal recycling as well as railcar
sales and leasing.
Progress Energy has announced its intention to sell two of EFC's business
segments, Inland Marine Transportation and Rail Services. Therefore, these
segments are currently reported as net assets held for sale on the Progress
Energy consolidated financial statements and have been excluded from Progress
Energy's consolidated results of operations.
Progress Telecom owns and operates a voice and data fiber network that stretches
from Washington, D.C. to Miami, Florida and conducts primarily a carrier's
carrier business. Progress Telecom markets wholesale fiber-optic-based capacity
service in the Southeastern 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. As of December 31, 2000, Progress Telecom owned and
managed approximately 4,000 route miles and approximately 115,000 fiber miles of
fiber optic cable.
Caronet, a subsidiary of CP&L formerly reported as Interpath, serves the
telecommunications industry by providing fiber-optic telecommunications
services. Pursuant to a Contribution Agreement effective June 28, 2000 between
CP&L, Caronet and Interpath Communications, Inc., a Delaware corporation formed
in conjunction with the transaction, Caronet contributed the assets used in the
application service provider business to Interpath. Under the terms of the
agreement, Caronet owns 35% of Interpath's stock (15% voting stock) and Bain
Capital, Inc. a private equity fund, and its affiliates (Bain) own 65% of
Interpath's stock. On July 6, 2000, Caronet and Bain each invested $25 million
of additional equity in Interpath. Additionally, as discussed in "Significant
Transactions" above, Caronet sold its limited partnership interest in BellSouth
Carolinas PCS in September 2000.
COMPETITION
- - - - - - -----------
Progress Energy's non-utility subsidiaries compete in their respective
marketplaces in terms of price, quality of service, location and other factors.
SRS competes with other providers of energy and facility management software and
services on a national basis. Progress Telecom and Caronet compete with other
providers of fiber-optic telecommunications services, including local exchange
carriers and competitive access providers, in the Southeast United States.
EFC's and Energy Venture's synthetic fuel operations, EFC's coal operations and
Progress Energy's 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 EFC and Energy Ventures, taken as a whole, is not subject to
significant seasonal fluctuation.
26
<PAGE>
OPERATING STATISTICS - PROGRESS ENERGY
- - - - - - --------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31
2000 (e) 1999 1998 1997 1996
------------ ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - coal 31,132 28,260 27,576 25,545 24,859
nuclear 23,857 22,451 22,014 21,690 20,284
hydro 441 520 790 799 882
oil/gas 1,337 435 386 189 68
Purchased 5,724 5,132 5,675 6,318 7,292
------------ ----------- ----------- ----------- -----------
Total energy supply (Company share) 62,491 56,798 56,441 54,541 53,385
Jointly-owned share (a) 4,505 4,353 4,349 4,101 3,616
------------ ----------- ----------- ----------- -----------
Total system energy supply 66,996 61,151 60,790 58,642 57,001
============ =========== =========== =========== ===========
Average fuel cost (per million BTU)
Fossil $ 1.96 $ 1.75 $ 1.71 $ 1.75 $ 1.75
Nuclear fuel $ 0.45 $ 0.46 $ 0.46 $ 0.46 $ 0.45
All fuels $ 1.30 $ 1.16 $ 1.14 $ 1.14 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 15,365 13,348 13,117 12,488 12,611
Commercial 12,221 11,068 10,664 10,010 9,615
Industrial 14,762 14,568 14,911 15,073 14,456
Other Retail 1,626 1,359 1,357 1,294 1,263
Wholesale 15,691 14,416 14,427 13,900 13,383
------------ ----------- ----------- ----------- -----------
Total energy sales 59,665 54,759 54,476 52,765 51,328
Company uses and losses 2,826 2,039 1,964 1,776 2,057
------------ ----------- ----------- ----------- -----------
Total energy requirements 62,491 56,798 56,440 54,541 53,385
============ =========== =========== =========== ===========
Natural gas sales (millions of dt) (b) 57,026 27,564 - - -
Electric customers billed
Residential 2,282,892 1,020,864 996,398 972,385 945,703
Commercial 332,950 183,914 178,588 172,821 167,151
Industrial 7,524 5,045 5,056 5,072 5,066
Government and municipal 22,703 2,731 2,757 2,785 2,774
Resale 61 39 35 43 27
------------ ----------- ----------- ----------- -----------
Total electric customers billed 2,646,130 1,212,593 1,182,834 1,153,106 1,120,721
============ =========== =========== =========== ===========
Electric revenues (in thousands)
Retail $ 2,799,422 $ 2,530,562 $ 2,532,234 $ 2,450,509 $ 2,417,011
Wholesale 616,149 548,766 528,253 507,720 512,579
Miscellaneous revenue 149,710 59,518 69,558 65,860 66,125
------------ ----------- ----------- ----------- -----------
Total electric revenues $ 3,565,281 $ 3,138,846 $ 3,130,045 $ 3,024,089 $ 2,995,715
============ =========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System (c) 19,839 10,948 10,529 10,030 9,812
Company 19,167 10,344 9,875 9,344 9,264
Total capability at year-end (thousands of kW)
Fossil plants 14,747 6,736 6,571 6,571 6,331
Nuclear plants 4,008 3,174 3,174 3,064 3,064
Hydro plants 218 218 218 218 218
Purchased 2,650 1,088 1,538 1,588 1,603
------------ ----------- ----------- ----------- -----------
Total system capability 21,623 11,216 11,501 11,441 11,216
Less jointly-owned portion (d) 662 593 593 690 686
------------ ----------- ----------- ----------- -----------
Total Company capability 20,961 10,623 10,908 10,751 10,530
============ =========== =========== =========== ===========
</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 2000, this represents the combined summer non-coincident 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.
27
<PAGE>
OPERATING STATISTICS - CAROLINA POWER & LIGHT COMPANY
- - - - - - -----------------------------------------------------
<TABLE>
<CAPTION>
Years Ended December 31
2000 1999 1998 1997 1996
------------ ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Energy supply (millions of kWh)
Generated - coal 29,520 28,260 27,576 25,545 24,859
nuclear 23,275 22,451 22,014 21,690 20,284
hydro 441 520 790 799 882
oil/gas 733 435 386 189 68
Purchased 4,878 5,132 5,675 6,318 7,292
------------ ----------- ----------- ----------- -----------
Total energy supply (Company share) 58,847 56,798 56,441 54,541 53,385
Power Agency share (a) 4,505 4,353 4,349 4,101 3,616
------------ ----------- ----------- ----------- -----------
Total system energy supply 63,352 61,151 60,790 58,642 57,001
============ =========== =========== =========== ===========
Average fuel cost (per million BTU)
Fossil $ 1.83 $ 1.75 $ 1.71 $ 1.75 $ 1.75
Nuclear fuel $ 0.45 $ 0.46 $ 0.46 $ 0.46 $ 0.45
All fuels $ 1.21 $ 1.16 $ 1.14 $ 1.14 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 14,091 13,348 13,117 12,488 12,611
Commercial 11,432 11,068 10,664 10,010 9,615
Industrial 14,446 14,568 14,911 15,073 14,456
Other Retail 1,423 1,359 1,357 1,294 1,263
Wholesale 15,261 14,416 14,427 13,900 13,383
------------ ----------- ----------- ----------- -----------
Total energy sales 56,653 54,759 54,476 52,765 51,328
Company uses and losses 2,194 2,039 1,964 1,776 2,057
------------ ----------- ----------- ----------- -----------
Total energy requirements 58,847 56,798 56,440 54,541 53,385
============ =========== =========== =========== ===========
Electric customers billed
Residential 1,048,607 1,020,864 996,398 972,385 945,703
Commercial 189,475 183,914 178,588 172,821 167,151
Industrial 4,989 5,045 5,056 5,072 5,066
Government and municipal 2,717 2,731 2,757 2,785 2,774
Resale 43 39 35 43 27
------------ ----------- ----------- ----------- -----------
Total electric customers billed 1,245,831 1,212,593 1,182,834 1,153,106 1,120,721
============ =========== =========== =========== ===========
Electric revenues (in thousands)
Retail $ 2,608,727 $ 2,530,562 $ 2,532,234 $ 2,450,509 $ 2,417,011
Wholesale 592,740 548,766 528,253 507,720 512,579
Miscellaneous revenue 122,209 59,518 69,558 65,860 66,125
------------ ----------- ----------- ----------- -----------
Total electric revenues $ 3,323,676 $ 3,138,846 $ 3,130,045 $ 3,024,089 $ 2,995,715
============ =========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System 11,157 10,948 10,529 10,030 9,812
Company 10,555 10,344 9,875 9,344 9,264
Total capability at year-end (thousands of kW)
Fossil plants 7,569 6,736 6,571 6,571 6,331
Nuclear plants 3,174 3,174 3,174 3,064 3,064
Hydro plants 218 218 218 218 218
Purchased 1,350 1,088 1,538 1,588 1,603
------------ ----------- ----------- ----------- -----------
Total system capability 12,311 11,216 11,501 11,441 11,216
Less Power Agency-owned portion (b) 593 593 593 690 686
------------ ----------- ----------- ----------- -----------
Total Company capability 11,718 10,623 10,908 10,751 10,530
============ =========== =========== =========== ===========
</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.
28
<PAGE>
ITEM 2. PROPERTIES
- - - - - - -------------------
The Company believes that its physical properties and those of its subsidiaries
are adequate to carry on its and their businesses as currently conducted. The
Company and its subsidiaries maintain property insurance against loss or damage
by fire or other perils to the extent that such property is usually insured.
ELECTRIC - CP&L
- - - - - - ---------------
As of December 31, 2000, CP&L's seventeen 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 10,961 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, 2000, CP&L's major generating facilities and their gross summer
capacities were as follows:
Major Installed Generating Facilities
-------------------------------------
At December 31, 2000
--------------------
<TABLE>
<CAPTION>
Summer
Maximum
Primary/ 1st Year of Dependable
Alternate Commercial Capacity
Plants Unit No. Fuel Location Operation MW
- - - - - - ----------------------------- ------------- ----------- --------------------- -------------------- ------------------
<S> <C> <C> <C> <C> <C>
Asheville: Unit #1 Coal Skyland, N.C. 1964 198 MW
Unit #2 Coal 1971 194 MW
Unit #3 Gas/Oil 1999 165 MW
Unit #4 Gas/Oil 2000 165 MW
Cape Fear: Unit #5 Coal Moncure, N.C. 1956 143 MW
Unit #6 Coal 1958 173 MW
Darlington County: Unit #12 Gas/Oil Hartsville, S.C. 1997 120 MW
Unit #13 Gas/Oil 1997 120 MW
H.F. Lee: Unit #1 Coal Goldsboro, N.C. 1952 79 MW
Unit #2 Coal 1951 76 MW
Unit #3 Coal 1962 252 MW
H.B. Robinson: Unit #1 Coal Hartsville, S.C. 1960 174 MW
Unit #2 Uranium 1971 683 MW
Roxboro: Unit #1 Coal Roxboro, N.C. 1966 385 MW
Unit #2 Coal 1968 670 MW
Unit #3 Coal 1973 707 MW
Unit #4* Coal 1980 700 MW
L.V. Sutton: Unit #1 Coal Wilmington, N.C. 1954 97 MW
Unit #2 Coal 1955 106 MW
Unit #3 Coal 1972 410 MW
Brunswick: Unit #1* Uranium Southport, N.C. 1977 820 MW
Unit #2* Uranium 1975 811 MW
Mayo* Unit #1 Coal Roxboro, N.C. 1983 745 MW
Harris* Unit #1 Uranium New Hill, N.C. 1987 860 MW
Wayne County: Unit #1 Gas/Oil Goldsboro, N.C. 2000 177 MW
Unit #2 Gas/Oil 2000 177 MW
Unit #3 Gas/Oil 2000 157 MW
Unit #4 Gas/Oil 2000 157 MW
</TABLE>
*Facilities are jointly owned by CP&L and Power Agency, and the capacity shown
includes Power Agency's share.
In addition to the major generating facilities listed above, many of which have
additional smaller units on site, CP&L also operates the following plants:
Walters (North Carolina), Marshall (North Carolina), Tillery (North Carolina),
Blewett (North Carolina), Weatherspoon (North Carolina) and Morehead City (North
Carolina).
As of December 31, 2000, including both the total generating capacity of
10,961 MW and the total firm contracts for purchased power of approximately
1,350 MW, CP&L had total capacity resources of approximately 12,311 MW.
29
<PAGE>
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 Harris
Unit No. 1 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, 2000, CP&L had 5,598 pole miles of transmission lines
including 292 miles of 500 kilovolt (kV) lines and 2,865 miles of 230 kV lines,
and distribution lines of approximately 44,443 pole miles of overhead lines and
approximately 14,681 miles of underground lines. Distribution and transmission
substations in service had a transformer capacity of approximately 34,645
kilovolt-ampere (kVA) in 2,012 transformers. Distribution line transformers
numbered 452,419 with an aggregate 19,598,000-kVA capacity.
ELECTRIC - FLORIDA POWER
- - - - - - ------------------------
As of December 31, 2000, the total summer generating capacity (including
jointly-owned capacity) of Florida Power's generating facilities was 8,012 MW.
This capacity was generated by 13 steam units with a capacity of 4,716 MW, two
combined cycle units with a capacity of 689 MW and 47 combustion turbine units
with a capacity of 2,607 MW. Florida Power's generating plants (all located in
Florida) and their gross summer capacities at December 31, 2000, were as
follows:
<TABLE>
<CAPTION>
Summer Net
Maximum
Primary/ 1st Year of Combined Combustion Dependable
Alternate Location Commercial Steam Cycle Turbine Capacity
Plants Fuel (County) Operation MW MW MW MW
- - - - - - ------------------- ------------ --------------- --------------- ------------------------------------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
Crystal River: Citrus
Unit #1 Coal 1966 379 -- -- 379
Unit #2 Coal 1969 486 -- -- 486
Unit #3 * Uranium 1977 834 -- -- 834
Unit #4 Coal 1982 720 -- -- 720
Unit #5 Coal 1984 717 -- -- 717
----------- --------------
3,136 3,136
Anclote Oil/Gas Pasco 1974 993 -- -- 993
Bartow Oil/Gas Pinellas 1958 444 -- 187 631
Suwannee River Oil/Gas Suwannee 1953 143 -- 164 307
Hines Unit 1 Gas/Oil Polk 1999 -- 482 -- 482
Tiger Bay Gas Polk 1997 -- 207 -- 207
Avon Park Oil/Gas Highlands 1968 -- -- 52 52
Bayboro Oil Pinellas 1973 -- -- 184 184
DeBary Oil/Gas Volusia 1975 -- -- 667 667
Higgins Gas Pinellas 1969 -- -- 122 122
Intercession City** Oil/Gas Osceola 1974 -- -- 1,029 1,029
Rio Pinar Oil Orange 1970 -- -- 13 13
Turner Oil Volusia 1970 -- -- 154 154
University of Fla. Gas Alachua 1994 -- -- 35 35
------------------------------------- --------------
4,716 689 2,607 8,012
===================================== ==============
</TABLE>
* Represents 100% gross of co-owners total plant capacity. Florida
Power's ownership percentage is approximately 91.8%.
** 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.
As of December 31, 2000, including both the total generating capacity of 8,012
MW and the total firm contracts for purchased power of approximately 1,300 MW,
Florida Power had total capacity resources of approximately 9,312 MW.
30
<PAGE>
Substantially all of Florida Power's utility plant is pledged as collateral for
Florida Power's First Mortgage Bonds.
As of December 31, 2000, Florida Power distributed electricity through 359
substations with an installed transformer capacity of 51,557,000 kVA. Of this
capacity, 36,658,000 kVA is located in transmission substations and 14,899,000
kVA in distribution substations. Florida Power has the second largest
transmission network in Florida. Florida Power has 4,688 circuit miles of
transmission lines, of which 2,642 circuit miles are operated at 500, 230, or
115 kV and the balance at 69 kV. Florida Power has 26,801 circuit miles of
distribution lines, which operate at various voltages ranging from 2.4 to 25 kV.
NATURAL GAS
- - - - - - -----------
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 1,128 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 2,865 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 will primarily be used to transport natural gas
to an electric generating plant currently under construction in Richmond County
by CP&L. See Progress Energy's PART II, ITEM 7, "Future Outlook" for a
discussion of recent developments with the Richmond County plant.
OTHER
- - - - - - -----
EFC owns and/or operates approximately 6,000 railcars, 100 locomotives, 1,200
river barges and 20 river towboats that are used for the transportation and
shipping of coal, steel and other bulk products. Through joint ventures, EFC has
four oceangoing tug/barge units. An EFC subsidiary, through another joint
venture, owns one-third of a large bulk products terminal located on the
Mississippi River south of New Orleans. The terminal handles coal and other
products. EFC provides dry-docking and repair services to towboats, offshore
supply vessels and barges through operations it owns near New Orleans,
Louisiana. Certain river barges and tug/barge units owned or operated by EFC are
subject to liens in favor of certain lenders.
EFC controls, either directly or through subsidiaries, coal reserves located in
eastern Kentucky and southwestern Virginia. EFC owns properties that contain
estimated coal reserves of approximately 2 million tons and controls, through
mineral leases, additional estimated coal reserves of approximately 22 million
tons. The reserves controlled by EFC include substantial quantities of high
quality, low sulfur coal that is appropriate for use at Florida Power's existing
generating units. EFC's total production of coal during 2000 was approximately
3.7 million tons.
In connection with its coal operations, EFC subsidiaries own and operate an
underground mining complex located in southeastern Kentucky and southwestern
Virginia. Other EFC 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. EFC and its subsidiaries employ
both company and contract miners in their mining activities.
An EFC subsidiary owns a majority interest in a partnership, located in eastern
Kentucky, which produces synthetic fuel from 3 facilities. In addition, another
EFC subsidiary has a minority interest in two other synthetic fuel facilities
located in West Virginia. In October 1999, EFC subsidiaries purchased four
additional synthetic fuel facilities. Two of the facilities were relocated and
began operation at EFC coal mines in Kentucky and Virginia in 1999. The two
other facilities were relocated and began operation at river terminal locations
in West Virginia during 2000. Also during 2000, Energy Ventures purchased 90%
interests in two of these four recently-acquired facilities.
31
<PAGE>
A subsidiary of EFC has acquired oil and gas leases on 20,000 acres in Garfield
and Mesa Counties, Colorado, containing proven natural gas net reserves of 60.7
billion cubic feet. This subsidiary currently operates 54 gas wells on the
property. Total natural gas production in 2000 was 4.8 net billion cubic feet.
Progress Rail, an EFC subsidiary, 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 24 states, Mexico and
Canada.
Another subsidiary of EFC 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.
Monroe Power owns and operates a combustion turbine in Georgia. The full output
of 155 MW is received by MEAG, which represents 48 municipal electric utilities
located in Georgia. Monroe Power added an additional generating unit in March of
2001 that produces an output of 160 megawatts. Monroe Power has another unit
power sales agreement in place for this second unit.
In November 2000, CP&L Energy (now known as Progress Energy) announced its
intention to build its second power plant in the state of Georgia on a tract in
Effingham County. The plant will be owned and operated by Effingham County
Power, LLC, a wholly-owned subsidiary of Energy Ventures. The 480-megawatt
combined cycle plant will be fueled primarily by natural gas and will be used to
provide peaking capacity to the region. The first phase of the construction,
used for peaking operation, is expected to begin construction in the summer of
2001 and become available for commercial operation in June 2002. The second
phase of the construction which involves conversion of the peaking generators to
combined-cycle operation is expected to be completed in June 2003.
Progress Telecom provides wholesale telecommunications services throughout the
Southeastern United States. Progress Telecom incorporates approximately 115,000
fiber miles in its network including over 100 Points-of-Presence. As a result of
the acquisition of FPC, Progress Telecom now manages the Caronet fiber optic
network stretching from Atlanta to Washington, D. C. Progress Telecom plans to
combine its fiber network with Caronet's fiber network in 2001.
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
32
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANTS
<TABLE>
<CAPTION>
Name Age Recent Business Experience
- - - - - - ---- --- --------------------------
<S> <C> <C>
William Cavanaugh III 62 Chairman, President and Chief Executive
Officer, Progress Energy, Inc. (formerly
known as (i) CP&L Holdings, Inc. from
August 1999 to February 2000 and (ii)
CP&L Energy, Inc. from February 2000 to
December 2000), August 1999 to present,
Chairman, Progress Energy Service
Company, LLC, (formerly known as CP&L
Service Company LLC), August 2000 to
present; Chairman, Florida Power
Corporation, November 30, 2000 to
present; Chairman, Progress Energy
Ventures, Inc. (formerly known as CPL
Energy 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 6 1993.
William S. Orser 56 Group President, CP&L and Florida Power
Corporation, November 30, 2000 to
present; Executive Vice President, CP&L,
Energy Supply, June 1998 to tovember 30,
2000; Executive Vice President and Chief
Nuclear Officer, NP&L, December 1996 to
June 1998; Executive Vice President,
CP&L, Nuclear Generation, April 1993 to
December 1996.
Robert B. McGehee 58 Executive Vice President, Progress
Energy, Inc. (formerly known as (i) CP&L
Holdings, Inc. from August 1999 to
February 2000 and (ii) CP&L Energy, Inc.
from February 2000 to December 2000) and
CP&L, February, 2001 to present;
President and Chief Executive Officer,
Progress Energy Service Company, LLC
(formerly known as CP&L Service Company
LLC), from August, 2000 to present;
Executive Vice President and General
Counsel, Progress Energy, 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.
C. S. Hinnant 56 Senior Vice President, Florida Power
Corporation, November 30, 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 May 1998;
Vice President, CP&L, Robinson Nuclear
Plant, March 1994 to March 1997.
</TABLE>
33
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Tom D. Kilgore 53 Group President, CP&L, November 30, 2000
to present; President and CEO, Progress
Energy Ventures, Inc. (formerly known as
CPL Energy Ventures), March 2000 to
present; Senior Vice President, CP&L,
Power Operations, August 1998 to
November 30, 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.
Robert H. Bazemore, Jr. 46 Controller and Chief Accounting Officer,
Progress Energy, Inc. (formerly known as
CP&L Energy, Inc.), June 2000 to
present; Controller, Florida Power
Corporation, November 30, 2000 to
present; Vice President and Controller,
Progress Energy Service Company, LLC
(formerly CP&L Service Company LLC),
August 2000 to present; Vice President
and Controller, CP&L, May 2000 to
present; Director, Operations &
Environmental Support Department,
December 1998 to May 2000; Manager,
Financial & Regulatory Accounting,
September 1995 to December 1998.
Don K. Davis 55 Executive Vice President, CP&L, May 2000
to present; President and Chief
Executive Officer, North Carolina
Natural Gas Corporation, 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. From
January 1992 to December 1996, he was
Chief Executive Officer and Director of
PRISM Consulting, Inc., a utility
management consulting firm he founded.
Fred N. Day, IV 57 Executive Vice President, CP&L and
Florida Power Corporation, November 30,
2000 to present; Senior Vice President,
CP&L, Energy Delivery, July 1997 to
November 30, 2000; Vice President, CP&L,
Western Region, 1995 to July 1997.
*Wayne C. Forehand 42 Senior Vice President, Florida Power
Corporation, November 30, 2000 to
present; Vice President, Florida Power
Corporation, September 1993 to November
2000.
Cecil L. Goodnight 57 Senior Vice President, Progress Energy
Service Company, LLC (formerly CP&L
Service Company LLC), August 2000 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; Senior Vice President, CP&L, Human
Resources and Support Services, March
1995 to December 1996.
*H. William Habermeyer, Jr. 58 President and Chief Executive Officer,
Florida Power Corporation, November 30,
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 39 Senior Vice President, Progress Energy
Service Company, LLC, November 30, 2000
to present; Vice President, CP&L,
Strategic Planning, February 1999 to
November 30, 2000; Vice President and
</TABLE>
34
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Controller, CP&L, February 1997 to
February 1999; Manager, Tax Department,
CP&L, September 1995 to February 1997.
William D. Johnson 47 Executive Vice President, General
Counsel and Secretary, Progress Energy,
Inc. (formerly known as (i) CP&L
Holdings, Inc. from August 1999 to
February 2000 and (ii) CP&L Energy, Inc.
from February 2000 to December 2000),
February 2001 to present; Executive Vice
President and Corporate Secretary,
Progress Energy, Inc., June 2000 to
February 2001; Senior Vice President and
Secretary, CP&L Holdings, Inc., August
1999 to June 2000; Executive Vice
President, General Counsel and Corporate
Secretary, Progress Energy Service
Company, LLC (formerly CP&L 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.
Peter M. Scott 51 Executive Vice President and CFO,
Progress Energy, Inc. (formerly known as
CP&L Energy, Inc.) June 2000 to present;
Executive Vice President and CFO,
Florida Power, November 30, 2000 to
present, Executive Vice President and
CFO, Progress Energy Service Company,
LLC (formerly known as CP&L Service
Company, LLC), August 2000 to present;
Executive Vice President and CFO, CP&L,
May 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.
E. Michael Williams 52 Senior Vice President, Florida Power
Corporation, November 30, 2000 to
present; Senior Vice President, CP&L,
June 2000 to present; Before joining the
Company, Mr. Williams held the position
of Vice President, Fossil Generation,
Central and South West Corp., an
investor-owned utility.
</TABLE>
*Indicates individual is an executive officer of Progress Energy, Inc., but not
CP&L.
35
<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:
<TABLE>
<CAPTION>
2000 High Low Dividends Declared
- - - - - - ---- ---- --- ------------------
<S> <C> <C> <C>
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
1999 High Low Dividends Declared
- - - - - - ---- ---- --- ------------------
First Quarter $47.88 $37.63 .500
Second Quarter 45.00 36.63 .500
Third Quarter 43.25 34.13 .500
Fourth Quarter 36.81 29.25 .515
</TABLE>
The December 31 closing price of the Company's Common Stock was $49.19 in 2000
and $30.44 in 1999.
As of February 28, 2001, the Company had 79,058 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.
36
<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
2000 (a) 1999 (b) 1998 1997 1996
------------ ------------ -------------- -------------- -----------
<S> <C> <C> <C> <C> <C>
(dollars in thousands except per share data)
Operating results
Operating revenues $ 4,118,873 $ 3,357,615 $ 3,191,668 $ 3,036,587 $ 2,999,273
Net income $ 478,361 $ 379,288 $ 396,271 $ 382,265 $ 381,668
Ratio of earnings to fixed charges 3.27 4.04 4.29 3.99 3.86
Ratio of earnings to fixed charges
and preferred stock dividends 3.27 4.04 4.29 3.99 3.86
Per share data
- - - - - - --------------
Basic earnings per
common share $ 3.04 $ 2.56 $ 2.75 $ 2.66 $ 2.66
Diluted earnings per
common share $ 3.03 $ 2.55 $ 2.75 $ 2.66 $ 2.66
Dividends declared per common
share $ 2.075 $ 2.015 $ 1.955 $ 1.895 $ 1.835
Assets $ 20,091,012 $ 9,494,019 $ 8,401,406 $ 8,220,728 $ 8,364,862
- - - - - - ------
Capitalization
Common stock equity $ 5,424,201 $ 3,412,647 $ 2,949,305 $ 2,818,807 $ 2,690,454
Preferred stock - redemption
not required 92,831 59,376 59,376 59,376 143,801
Long-term debt, net 5,890,099 3,028,561 2,614,414 2,415,656 2,525,607
------------ ------------ -------------- -------------- -----------
Total capitalization $ 11,407,131 $ 6,500,584 $ 5,623,095 $ 5,293,839 $ 5,359,862
============ ============ ============== ============== ===========
</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.
37
<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
2000 (a) 1999 (b) 1998 1997 1996
----------- ------------ -------------- ------------- -----------
<S> <C> <C> <C> <C> <C>
(dollars in thousands)
Operating results
Operating revenues $ 3,543,907 $ 3,357,615 $ 3,191,668 $ 3,036,587 $ 2,999,273
Net income $ 461,028 $ 382,255 $ 399,238 $ 388,317 $ 391,277
Earnings for common stock $ 458,062 $ 379,288 $ 396,271 $ 382,265 $ 381,668
Ratio of earnings to fixed charges 3.99 4.12 4.38 4.17 4.12
Ratio of earnings to fixed
charges and preferred
stock dividends 3.92 4.03 4.28 3.98 3.83
Assets $ 9,260,388 $ 9,494,019 $ 8,401,406 $ 8,220,728 $ 8,364,862
- - - - - - ------
Capitalization
- - - - - - --------------
Common stock equity $ 2,852,038 $ 3,412,647 $ 2,949,305 $ 2,818,807 $ 2,690,454
Preferred stock - redemption
not required 59,334 59,376 59,376 59,376 143,801
Long-term debt, net 3,619,984 3,028,561 2,614,414 2,415,656 2,525,607
----------- ------------ -------------- -------------- -----------
Total capitalization $ 6,531,356 $ 6,500,584 $ 5,623,095 $ 5,293,839 $ 5,359,862
=========== ============ ============== ============== ===========
</TABLE>
(a) Operating results and balance sheet data do not include information for
NCNG, SRS, Monroe Power and Energy Ventures 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.
38
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
- - - - - - --------------------------------------------------------------------------------
OF OPERATIONS
- - - - - - -------------
PROGRESS ENERGY, INC.
- - - - - - ---------------------
RESULTS OF OPERATIONS
- - - - - - ---------------------
For 2000 as compared to 1999 and 1999 as compared to 1998
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) was initially formed as
CP&L Energy, Inc. (CP&L Energy), which was the holding company into which
Carolina Power & Light Company (CP&L) reorganized on June 19, 2000. All shares
of common stock of CP&L were exchanged for an equal number of shares of CP&L
Energy. On December 4, 2000, the Company changed its name from CP&L Energy 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 for
2000 reflect 12 months of operations for CP&L Energy and one month of operations
for FPC.
The operations of Progress Energy and its subsidiaries are divided into four
major categories: two electric utilities (both CP&L and Florida Power
Corporation), a natural gas utility and other. The other category includes
non-regulated energy businesses including merchant energy generation and coal
and synthetic fuel operations. The other category also provides various products
and services for energy and facility management and telecommunications and
includes holding company operations.
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 and usage 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 nuclear generation facilities for a
$193 million after-tax effect and the December operations of FPC. Florida
Progress Corporation contributed net income of $28.7 million for the month of
December 2000. The Company issued 46.5 million shares of common stock in
connection with the acquisition of FPC, which resulted in a dilution of earnings
per common share.
In 1999, Progress Energy's net income was $379.3 million, a 4.3% decrease from
$396.3 million in 1998. Basic earnings per share decreased from $2.75 in 1998 to
$2.56 in 1999. Earnings were negatively affected by the effects of Hurricanes
Dennis and Floyd, a decline in electric sales to industrial customers and a
decline in electric revenues due to increased utilization of the real-time
pricing tariff. Continued customer growth and the addition of North Carolina
Natural Gas Corporation (NCNG) on July 15, 1999, positively affected net income.
The Company issued 8.3 million shares of common stock in connection with the
acquisition of NCNG, which resulted in a dilution of earnings per common share.
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 contingent value obligations (CVO) valued at approximately $49.3
million. See Note 2A to the Progress Energy consolidated financial statements
for additional discussion of the FPC acquisition.
Progress Energy funded the cash portion of the acquisition with commercial
paper, backed by a credit facility. Progress Energy replaced a majority of the
short-term financing with long-term senior notes during the first quarter of
2001. See "Financing Activities" discussion under LIQUIDITY AND CAPITAL
RESOURCES for more details.
The acquisition was accounted for by Progress Energy using the purchase method
of accounting. Preliminary goodwill of approximately $3.4 billion has been
recorded and is being amortized on a straight-line basis over a period of
primarily 40 years. One month of amortization, or approximately $7.0 million,
was recorded in 2000. As part of the NCUC order approving the acquisition,
Progress Energy agreed to have CP&L exclude all cost increases
39
<PAGE>
attributable to the acquisition from retail rates. Management expects synergies
from the combination of the two companies to offset the amortization of
goodwill.
Progress Energy has announced its intention to sell two of the non-utility
business segments acquired in the transaction, Rail Services and Inland Marine
Transportation. Therefore, the results of operations of these segments are not
included in Progress Energy's consolidated earnings and the related assets and
liabilities are presented as net assets held for sale on the consolidated
balance sheets.
As part of the acquisition of FPC, Progress Energy is now a holding company
whose subsidiaries operate in multiple states. Therefore, Progress Energy is now
registered with, and subject to, regulation by the Securities and Exchange
Commission (SEC) under the Public Utility Holding Company Act of 1935, as
amended (PUHCA). Pursuant to the SEC's order dated November 27, 2000, the
Company has committed to divest of certain immaterial non-utility businesses.
The Company has also agreed to file a response or responses with the SEC by
November 30, 2001 that will either provide a legal basis for retaining certain
other non-utility businesses or a commitment to divest of those businesses. On
March 22, 2001, the Company filed a post effective amendment requesting an SEC
order to divest of certain holdings of EFC.
Electric
The electric segment is 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
Corporation (Florida Power). The territory in the Carolinas served by CP&L
includes 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. CP&L serves an area of approximately 34,000 square miles, with a
population of approximately 4.2 million. As of December 31, 2000, CP&L provided
electricity to approximately 1.2 million customers. The Florida territory served
by Florida Power is in the west central part of the state, including the area
around Orlando and the cities of St. Petersburg and Clearwater. Florida Power
serves an area of approximately 20,000 square miles, with a population of
approximately 4.5 million. As of December 31, 2000, 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. Operating results are primarily influenced by the level of electric
sales to each electric utility's customer base and the costs associated with
those sales.
CP&L
- - - - - - ----
Revenues
CP&L's electric revenue fluctuations as compared to the prior year were due to
the following factors (in millions):
2000 1999
---- ----
----------------------------------------------- -------------- --------------
Customer growth and usage $ 114 $ 50
Weather 55 (14)
Price (16) (31)
Sales to Power Agency 12 -
Sales to other utilities 18 4
Other 2 -
----------------------------------------------- -------------- --------------
Total Increase $ 185 $ 9
An increase in the number of customers served and changes in usage patterns
contributed to revenue increases for both periods. CP&L added over 33,000 new
customers in 2000 and 29,700 in 1999. Residential and commercial sales increased
in both periods. Industrial sales usage increased in 2000 after declining in
1999. Industrial sales in 2000 were boosted by the textile industry and lumber
and wood industry, which experienced increased market demand. This increase was
partially offset by the chemicals and paper industries, which continued to
decline. The increase in the weather component for 2000 is primarily
attributable to the fourth quarter when colder-than-normal weather conditions
existed. The decrease in the weather component for 1999 reflects overall
milder-than-normal weather conditions compared to 1998.
The change in price in 2000 reflects decreases in wholesale prices and the
continuing effects of the real-time pricing rate schedule. For the 1999
comparison period, the price-related decrease is due to increased utilization of
the real-
40
<PAGE>
time pricing tariff, which went into effect in late 1998. Sales to North
Carolina Eastern Municipal Power Agency (Power Agency) and sales to other
utilities each increased in 2000 after remaining relatively flat in the prior
period. The increase in revenue related to sales to Power Agency is primarily
due to increased usage due to colder-than-normal weather in the fourth quarter.
The increase in sales to other utilities was primarily due to increased demand
due to weather and competitive prices in the fourth quarter.
Expenses
CP&L had an increase in fuel expense in 2000, primarily due to increases in
volume and increases in fuel prices associated with gas and oil-fired units. For
1999, the change in fuel expense primarily reflects changes in the Company's
generation mix.
For the 2000 and 1999 comparison periods, purchased power decreased due mainly
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.
CP&L's other operation and maintenance expenses increased in 2000 due to
increases in benefit plan-related expenses and emission allowances. A total of
$23 million of emission allowances was expensed in 2000. For the 1999 comparison
period, other operation and maintenance expenses were negatively affected by
$28.6 million of storm restoration expenses incurred as a result of Hurricanes
Dennis and Floyd, as well as an increase in general and administrative expenses.
Depreciation expense increased substantially in 2000 over 1999. As approved by
regulators, CP&L recorded an additional $275 million to depreciation expense in
2000 related to accelerated cost recovery of nuclear generating assets.
Depreciation expense for 1999 included $68 million of accelerated amortization
related to certain regulatory assets. See "Retail Rate Matters" discussion under
OTHER MATTERS for more details.
Interest expense increased over 1999 due to higher short-term interest rates and
higher debt balances. Debt balances increased to fund construction programs.
CP&L Electric operations contributed net income of $367.5 million, $422.6
million and $439.7 million in 2000, 1999 and 1998, respectively.
Florida Power
- - - - - - -------------
Florida Power, a subsidiary of FPC, is a regulated public utility engaged in the
generation, transmission, distribution and sale of electricity in portions of
Florida. As of December 31, 2000, Florida Power operated a system of 14 power
plants with installed generating capacity of over 8,000 megawatts, of which 61%
was gas/oil, 29% was coal and 10% was nuclear.
Progress Energy's operating results include only the month of December 2000 for
Florida Power after the acquisition was completed. Electric operating revenues
were $241.6 million, while fuel and purchased power expenses were $98.9 million
and other operation and maintenance expenses totaled $50.3 million. Revenues and
kWh sales in December 2000 were favorably affected by colder-than-normal weather
conditions. Florida Power's operations contributed net income of $21.8 million.
Natural Gas
On July 15, 1999, the Company acquired NCNG, a natural gas utility. NCNG
transports, distributes and sells natural gas to approximately 173,000
residential, commercial, industrial, wholesale and electric power generation
customers. NCNG serves 110 towns and cities and four municipal gas distribution
systems in south central and eastern North Carolina. Natural gas operations are
subject to the rules and regulations of the NCUC.
The ability to offer natural gas to customers furthers Progress Energy's
strategy to be a total energy provider while securing fuel supplies for planned
gas-fired electric generation. To this end, construction of the 84-mile
Sandhills Pipeline in North Carolina, from Iredell County to CP&L's Richmond
County combustion turbine generation site was completed in March of 2001.
Another project, Eastern NCNG (ENCNG), is proceeding with construction of a
pipeline that will bring natural gas transmission and distribution to 14 eastern
North Carolina counties over the next three to five years. CP&L and the
Albemarle-Pamlico Economic Development Corporation (APEC) will be the joint
owners of the operations of ENCNG, which will be subject to the rules and
regulations of the NCUC. On June 15, 2000, the NCUC issued an order awarding
ENCNG an exclusive franchise for all 14 counties and granted $38.7 million in
state bond funding
41
<PAGE>
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. The NCUC will consider
approval of bond funding for subsequent phases of the project at a later date.
The Company cannot predict the outcome of this matter.
On March 7, 2001, ENCNG was dissolved and reorganized into a corporation named
Eastern North Carolina Natural Gas Company (Eastern). Progress Energy and APEC
are the sole shareholders of Eastern with each entity owning 50% of Eastern.
Progress Energy has agreed to fund a portion of the project, which is
currently estimated to be approximately $22 million.
The natural gas segment only includes NCNG's regulated utility operations. For
the year ending December 31, 2000, natural gas revenues totaled $324.5 million,
while gas purchased for resale totaled $250.9 million. These amounts reflect
increases in the market price of natural gas during 2000. NCNG was able to file
four rate increases during 2000 to keep pace with these market price increases
and also filed two additional rate increases that were effective on January 1,
2001, and February 1, 2001.
The ability to pass the increases in the market price of gas costs through to
the customers on a timely basis reduces NCNG's exposure to market fluctuations.
Commodity gas costs tracked in rates are compared to the actual commodity gas
costs incurred with the differences either charged to or returned to customers,
as appropriate, through NCNG's deferred gas cost mechanism. NCNG defers gas
costs incurred in meeting customer demand that exceed, or are less than, a
benchmark gas cost rate charged to customers.
It is not anticipated that the recent increases in the market price of gas will
have a material adverse effect on the consolidated results of operations, cash
flows or financial position of the Company.
The natural gas segment contributed net income of $7.1 million and $1.3 million
in 2000 and 1999, respectively.
Other
Progress Energy's other segment primarily includes Strategic Resource Solutions
Corp. (SRS), Progress Energy Ventures, Inc. (Energy Ventures), Progress Capital
Holdings, Inc. (Progress Capital), Progress Telecommunications Corporation
(Progress Telecom), and Caronet, Inc. (Caronet). This segment also includes
other non-regulated operations of CP&L, FPC and NCNG, as well as holding company
results.
SRS serves the educational, governmental, commercial and industrial markets by
providing software, systems and services for facility and energy management
purposes. In 2000, SRS's operations achieved profitability due to strong revenue
growth in the education and federal markets and a continued focus on reducing
overhead costs. For the 1999 period, SRS's operating losses were $9.9 million,
down from a $34.7 million loss in 1998. This improved performance was
attributable to large performance contracts in the education and federal
markets, as well as strong sales in commercial and industrial building
automation.
Energy Ventures is a subsidiary created in 2000 that is involved in the
development and construction of gas-fired merchant generation plants and has an
ownership interest in three synthetic fuel facilities.
Monroe Power, a non-regulated merchant plant located in Monroe, Georgia, began
operations in December 1999. Monroe Power contributed operating income of $4.5
million for the year ended December 31, 2000 on contracted capacity and energy
sales. Monroe added an additional generating unit in March of 2001 that will
provide additional output and contracted sales in the future.
Progress Capital is a holding company for FPC's diversified operations led by
Electric Fuels Corporation (EFC), an energy and transportation company. EFC has
three primary business segments: Rail Services, Inland Marine Transportation and
Energy & Related Services. Rail Services and Inland Marine Transportation are
currently reported as net assets held for sale on the Progress Energy
consolidated financial statements and have been excluded from consolidated
results of operations. Energy & Related Services' operating results are
primarily affected by the supply and demand for low-sulfur coal, natural gas and
the demand for a coal-based synthetic fuel. EFC has an ownership interest in
nine synthetic fuel facilities that combine a chemical change agent with coal
fines to produce a synthetic fuel. EFC is currently responsible for managing all
of Progress Energy's synthetic fuel facilities.
Progress Telecom, acquired as part of the FPC acquisition, provides broadband
capacity services, dark fiber and wireless services in Florida and the Southeast
United States. Progress Telecom's operations for the month of December did not
have a significant effect on Progress Energy's results of operations. In
December 2000, Progress Telecom signed an important agreement with Emergia, a
subsidiary of Telefonica, to be the preferred U.S. provider handling
international telecommunications traffic to and from South America.
Additionally, Progress Telecom will
42
<PAGE>
complete the integration of its fiber network with CP&L's Caronet network (see
discussion below) in the first quarter of 2001, giving it a fiber network
stretching from southern Florida to Washington, D.C.
Caronet serves the telecommunications industry by providing fiber-optic
telecommunications services. Effective June 28, 2000, Caronet, formerly reported
as Interpath, contributed the net assets used in its application service
provider business to a newly formed company 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. On September 28, 2000, Caronet sold its 10% limited partnership
interest in BellSouth Carolinas PCS for a pre-tax gain of $200 million, which is
recorded as other income. Caronet's operating losses were $66.1 million and
$44.6 million in 2000 and 1999, respectively.
The other segment also includes Progress Energy's holding company results. As
part of the acquisition of FPC, goodwill of approximately $3.4 billion was
recorded and the amortization of $7.0 million is included in the other segment.
As described in Note 11 to the Progress Energy consolidated financial
statements, the holding company also recorded an $8.9 million decrease in the
liability related to the CVOs. Additionally, interest expense of $28.0 million
on the $3.5 billion of short-term debt used to finance the acquisition of FPC is
included in these results.
Income taxes fluctuate with changes in income before income taxes. In addition,
2000 income tax expense was decreased by income tax credits generated through
the synthetic fuel operations of Energy Ventures and EFC.
LIQUIDITY AND CAPITAL RESOURCES
- - - - - - -------------------------------
Progress Energy is a registered holding company and, as such, has no operations
of its own. While Progress Energy conducts all of its operations through its
subsidiaries, the ability to meet its obligations is dependent on the earnings
and cash flows of those subsidiaries and the ability of those subsidiaries to
pay dividends or to advance or repay funds to Progress Energy. The following
discussion of Progress Energy's liquidity and capital resources is on a
consolidated basis. The consolidated results contain information for FPC since
the date of acquisition.
Progress Energy continues to focus on its strategy of becoming an integrated
energy holding company through its acquisition of FPC and investments in its
subsidiaries.
Cash Flows from Operations
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. Fuel and purchased power expenses are
significant operating costs for the two electric utilities, CP&L and Florida
Power. Both utilities recover essentially all of these costs from customers
through fuel and energy cost recovery clauses.
Cash from operations is the primary source used to meet the net cash
requirements; however, approximately 20% of the total capital expenditures in
2000, excluding the acquisition of FPC, were funded by external debt. The
increase in cash from operating activities for the 2000 period is largely the
result of higher net income and the addition of FPC.
Going forward, cash generated from Progress Energy's regulated businesses (CP&L,
Florida Power and NCNG) is expected to provide the majority of the funds for the
Company's business needs. In addition, approximately 10%-15% of the Company's
total projected capital expenditures for the next three years are expected to be
funded by external debt.
Investing Activities
Cash used in investing activities was $3.5 billion greater in 2000 than in 1999,
primarily due to the acquisition of FPC. Progress Energy paid approximately $3.5
billion in cash as part of the total purchase consideration. Progress Energy's
property additions increased approximately $261 million in 2000 primarily due to
the expansion of CP&L's generation fleet. The sale of the Company's limited
partnership interest in BellSouth Carolinas PCS resulted in cash proceeds of
approximately $200 million. See Note 2 to the consolidated financial statements.
In addition, Progress Energy intends to sell the Rail Services and Inland Marine
Transportation business segments and would use any of the proceeds received from
the sale to reduce debt.
Estimated capital requirements for 2001 through 2003 primarily reflect
construction expenditures to add regulated and non-regulated generation,
transmission and distribution facilities, as well as to upgrade existing
facilities. Those capital requirements are reflected in the following table (in
millions):
43
<PAGE>
2001 2002 2003
---- ---- ----
Construction expenditures $ 1,522 $ 1,512 $ 1,523
Nuclear fuel expenditures 119 60 110
AFUDC (32) (38) (46)
------- ------- -------
Total $ 1,609 $ 1,534 $ 1,587
======= ======= =======
The table includes expenditures of approximately $172 million expected to be
incurred at fossil-fueled electric generating facilities to comply with the
Clean Air Act and approximately $300 million for the expansion of Progress
Telecom's fiber network.
Financing Activities
Cash provided by financing activities increased approximately $3.5 billion over
1999, primarily due to the proceeds received from the issuance of commercial
paper used to fund the FPC acquisition. In addition, financing activities were
marginally affected by the issuance and redemption of long-term debt.
During 2000, CP&L issued $300 million principal amount of Senior Notes and
$497.6 million principal amount of variable auction-rate First Mortgage Bonds,
Pollution Control Series. In addition, CP&L retired or redeemed $47.3 million
principal amount of Promissory Notes, $150 million principal amount of First
Mortgage Bonds and $497.6 million principal amount of variable rate Pollution
Control Obligations. For the period from 2001 to 2003, the Company's mandatory
retirements of long-term debt are $184 million, $182 million and $282 million,
respectively.
On November 30, 2000, Progress Energy funded 65% of the acquisition cost of FPC
with approximately $3.5 billion of commercial paper, backed by its $3.75 billion
credit facility. The remaining 35% was funded through the issuance of 46.5
million shares of common stock.
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 of 7.06%. Proceeds from this issuance were used to
retire commercial paper and other short-term indebtedness issued in connection
with the FPC acquisition.
As a registered holding company under PUHCA, Progress Energy obtained approval
from the SEC for the issuance and sale of securities as well as the
establishment of intracompany extensions of credit. As a result, Progress Energy
has approval for the issuance of common stock, preferred securities and short
and long-term debt. The total amount of debt of Progress Energy, excluding
subsidiaries, cannot exceed $5 billion and it must also maintain a common equity
ratio of at least 30%. Progress Energy also has established a utility and
non-utility money pool to facilitate the efficient use of cash flows among the
Company's utility and non-utility subsidiaries.
At December 31, 2000, the Company had lines of credit totaling $5.5 billion, all
of which are used to support its commercial paper borrowings. As of December 31,
2000, $845 million was drawn under these lines of credit. Based on the Company's
commercial paper borrowings at December 31, 2000, the Company had an available
balance on these facilities of $541 million. The Company is required to pay
minimal annual commitment fees to maintain its credit facilities. See Note 6 to
the Progress Energy consolidated financial statements.
Florida Power and Progress Capital 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, 2000, there
were no outstanding loans against these facilities.
Florida Power and CP&L both have public medium-term note programs providing for
the issuance of either fixed or floating interest rate notes. At December 31,
2000, $250 million and $300 million, respectively, were available for issuance.
In addition, Progress Capital has a private medium-term note program of $400
million for the issuance of either fixed or floating rate interest notes. At
December 31, 2000, there were no medium-term notes outstanding under this
program.
Progress Energy has on file with the SEC a shelf registration statement under
which senior notes, junior debentures, trust preferred securities, common stock
and preferred stock are available for issuance by the Company. As of December
31, 2000, the Company had $4.0 billion available under this shelf registration.
Progress Energy's issuance of $3.2 billion of senior unsecured notes in February
2001, as discussed above, reduced the amount available for issuance under this
registration statement.
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<PAGE>
The following table shows Progress Energy's capital structure as of December 31,
2000 and 1999:
2000 1999
---- ----
Common Stock Equity 34.9% 49.7%
Preferred Stock of Subsidiaries 0.6% 0.9%
Short and Long-term Debt 64.5% 49.4%
The acquisition of FPC through the issuance of approximately $3.5 billion of
commercial paper resulted in an increase in Progress Energy's consolidated total
debt to capital ratio. The increase in leverage was the primary reason that the
credit ratings of both CP&L and Florida Power were downgraded in the fall of
2000 by Standard & Poor's, Inc. (S&P) and Moody's Investor Service (Moody's).
As of February 28, 2001, ratings for senior secured, senior unsecured and
commercial paper are as follows:
CP&L Florida Power Progress Energy
Moody's/ S&P Moody's/ S&P Moody's/S&P
------------ ------------ ---------------
Senior secured notes A3/BBB+ A1/BBB+ not applicable
Senior unsecured notes Baa1/BBB+ A2/BBB+ Baa1/BBB
Commercial Paper P-2/A-2 P-1/A-2 P-2/A-2
The amount and timing of future sales of Company securities will depend on
market conditions 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.
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.
FPC's future operations will contribute to a substantial increase in Progress
Energy's operating income. Progress Energy will also have annual amortization
expense of approximately $84 million related to the $3.4 billion of preliminary
goodwill recorded for the purchase of FPC. Cost savings from synergies are
expected to offset the goodwill amortization. Additionally, the issuance of
approximately $3.5 billion in commercial paper to consummate the FPC transaction
will increase interest expense. Progress Energy refinanced the majority of this
debt in February 2001 to take advantage of lower long-term interest rates.
In February 2001, the Financial Accounting Standards Board (FASB) issued a
revised Exposure Draft of its proposed statement, Business Combinations and
Intangible Assets. The revised Exposure Draft contains the FASB's tentative
decisions about requiring the use of a non-amortization approach to account for
goodwill. Under that approach, rather than being amortized, goodwill would be
reviewed periodically for impairment. The FASB expects to issue a final
statement by June 2001. The Company cannot currently predict what impact the
final FASB statement will have on the Company's goodwill.
The acquisition of FPC positions Progress Energy as a regional energy company
focusing on the high-growth Southeast region of the United States. Progress
Energy has more than 19,000 megawatts of generation capacity and serves
approximately 2.8 million 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. Successful
integration of FPC and CP&L is the Company's immediate priority. The Company is
dedicated to expanding the region's electric generation capacity and delivering
reliable, competitively priced energy.
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 provided to retail customers are
set by the state regulatory commissions under cost-based regulatory principles.
See Note 12 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, competition, energy conservation practiced by
customers, the elasticity of demand, and the rate of economic growth in the
traditional service area.
45
<PAGE>
Regulatory issues facing Progress Energy are discussed in the "Current
Regulatory Environment" discussion under OTHER MATTERS below.
The Company is focused on both regulated and non-regulated generation expansion,
power marketing and synthetic fuel production. 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 reserve margins at the regulated
subsidiaries, and to take advantage of merchant generation opportunities. The
Company will continue to assess the appropriate mix between regulated and
non-regulated generation capacity, taking into account anticipated demand within
its service territories, financing considerations, regulatory requirements and
other factors. As part of this strategy, the Company is seeking regulatory
approval to transfer generation facilities under construction in Richmond
County, North Carolina and Rowan County, North Carolina from CP&L to Energy
Ventures and its subsidiaries. Upon completion of two construction phases, the
Richmond County facility will have generation capacity of approximately 1,270
MW. The Company anticipates that for a period of time after commencement of
commercial operations, the output of the Richmond County facility will be sold
to CP&L pursuant to an approved power purchase agreement. Upon completion of two
construction phases, the Rowan County facility will have generation capacity of
approximately 950 MW. Output from the Rowan County facility is either under
contract or will be sold to unaffiliated purchasers in the wholesale market.
Progress Energy's electric utilities are involved in the development of the
GridSouth Regional Transmission Organization (RTO) with Duke Energy Corporation
and South Carolina Electric and Gas Company, and the GridFlorida RTO, with
Florida Power & Light Company and Tampa Electric Company. The Company continues
to assess the structural options that may be available to maximize the value of
its transmission assets. Refer to the "Current Regulatory Environment"
discussion under OTHER MATTERS below for further discussion of transmission and
the Company's compliance with Federal Energy Regulatory Commission (FERC) Order
No. 2000.
The Company is focused on both the distribution and retail components,
delivering a high-level of customer service while offering value-added products
and services to its customers. The Company will emphasize maintenance and
enhancement of infrastructure, power quality and reliability, and work to
establish appropriate codes of conduct to insure efficient recovery of any
capital investment in energy delivery.
The fiber assets of Caronet and Progress Telecom are being combined under the
management of Progress Telecom with a focus primarily on the carriers' carrier
business. Management believes that there are synergies with the infrastructure
service capabilities of its core businesses and Progress Telecom. The Company
expects to complete the extension of the network within its current "footprint"
(from Washington, D.C. to Miami, Florida, including Virginia, North Carolina,
South Carolina and Georgia) and partner with others to gain access to capacity
outside this region. The Company will focus on lit fiber expansion (with
electronics attached), with some expansion of its dark fiber capacity.
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 unregulated 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."
OTHER MATTERS
- - - - - - -------------
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 SCPSC and the FPSC,
respectively. The electric businesses are also subject to regulation by FERC,
the
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U.S. Nuclear Regulatory Commission (NRC) and the U.S. Environmental Protection
Agency (EPA), and by environmental authorities in the states in which they
operate. In addition, the Company is subject to regulation by the 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.
Florida Power has previously entered into a stipulation agreement committing
several parties not to seek any reduction in Florida Power's base rates or
authorized range of return on equity. That agreement expires on June 30, 2001.
On July 7, 2000, the FPSC opened a docket to review Florida Power's earnings
including the effects of the acquisition by Progress Energy. The FPSC's decision
expected by late March 2001 has been deferred. Florida Power has agreed that if
the FPSC subsequently takes formal action under the interim rate statute, the
effective date of that action will be March 13, 2001. The Company cannot predict
the outcome of this matter.
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 related to deregulation of
the electric industry in California and other states.
o 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.
o South Carolina. The Company expects the South Carolina General Assembly
will continue to monitor the experiences of states that have
implemented electric restructuring legislation.
o Florida. On 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
legislative session begins during the first week of March and concludes
during the first week of May. The wholesale restructuring outline is
intended to facilitate the evolution of a more robust wholesale
marketplace in Florida. Some of the key provisions proposed include:
- independent power producers, including affiliates of utilities,
would be allowed to compete in the Florida wholesale market;
- continued recovery of contract cost under the PURPA (current
recovery of these costs is made through capacity recovery
clauses);
- generating assets owned by regulated utilities would be
transferred at net book value to affiliates (nuclear asset
transfer would be optional);
- capacity from transferred generating assets would be committed
back to the utility using cost-based transition contracts which
phase out over a six year period;
- following the transition period, all new capacity, including that
acquired from utility affiliates, would be acquired competitively
in the open market;
- utilities would continue to have to prove that the means by which
they acquire power are prudent and result in the lowest
acquisition cost; and
- existing base rates would be frozen for three years (base rates
cover costs not recovered through pass-through clauses - fuel,
purchased power and energy conservation expenses - and these
would continue under the recommendations).
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Management cannot predict whether the Florida legislature will
act on any of the study commission's recommendations or what
impact the recommendations would have on the Company if adopted
as proposed. The study commission has a deadline of December 2001
to propose recommendations with respect to retail restructuring,
but the Company cannot predict the timing or substance of any
such recommendations.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
Regional Transmission Organizations
On December 20, 1999, FERC issued Order No. 2000 on RTOs. The Order required
public utilities that own, operate or control interstate electricity
transmission facilities to have filed, by October 2000, either a proposal to
participate in an RTO or an alternative filing describing efforts and plans to
participate in an RTO. To date, the Company's electric utilities have responded
to the order as follows:
o CP&L. 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. The three companies are continuing to make progress in
developing GridSouth and are planning to make a supplemental filing to
the original GridSouth RTO application in mid 2001 that will include
generator interconnection procedures and more detail on congestion
management. On March 14, 2001, FERC conditionally approved GridSouth,
provided it make certain modifications to the board selection process,
passive owners' veto powers and take steps to expand its geographic
area. FERC directed GridSouth to file a status report by May 13, 2001
on efforts to expand the scope of the proposed RTO. FERC also directed
GridSouth to file its rates sixty days prior to operation, and submit a
plan setting out its specific milestones for transmission planning and
expansion by the date of operation.
o Florida Power. In October 2000, Florida Power, along with Florida Power
& Light Company and Tampa Electric Company, filed with FERC an
application for approval of an RTO for peninsular Florida, currently
named GridFlorida. On January 10, 2001, FERC rendered a positive order
on certain aspects of the GridFlorida RTO application, specifically
governance and certain financial obligations. The three companies are
continuing to make progress towards the development of GridFlorida.
Energy Costs Provisions
Operating costs not covered by a utility's base rates include increases in fuel,
purchased power and energy conservation expenses. 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 the Company's
electric utilities, by state, are as follows:
o North Carolina - fuel costs and the fuel portion of purchased power;
o South Carolina - fuel costs, purchased power costs, and emission
allowance expense; and
o Florida - fuel costs, purchased power costs and energy conservation
expenses.
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.
Additionally, the natural gas utility is allowed to recover the difference
between the actual gas costs incurred and the gas costs collected from its
customers. Therefore, any past over- or under-recovery is refunded or collected,
as applicable, through the use of a deferred gas account.
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. Pursuant to the
orders, CP&L's 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
48
<PAGE>
further accelerate the cost recovery of its nuclear generation facilities in
2000 by $125 million. This additional depreciation will allow CP&L to reduce the
minimum annual depreciation in 2001 through 2004 to $75 million. The resulting
total accelerated depreciation in 2000 was $275 million. 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 June 2000, CP&L filed a request with the NCUC seeking approval to defer
sulfur dioxide (SO2) emission allowance expenses, effective as of January 1,
2000, for recovery in a future general rate case proceeding or by such other
means as the NCUC may find appropriate. On January 5, 2001, the NCUC issued an
order authorizing CP&L to defer, effective January 1, 2000, the cost of SO2
emission allowances purchased pursuant to the Clean Air Act. CP&L is allowed to
recover emission allowance expense through the fuel clause adjustment in its
South Carolina retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004. The
cap on base retail electric rates in South Carolina was extended to December
2005 in conjunction with regulatory approval to form a holding company. NCNG
also agreed to cap its North Carolina margin rates for gas sales and
transportation services, with limited exceptions, through November 1, 2003.
Management is of the opinion that these agreements will not have a material
effect on the Company's consolidated results of operations or financial
position.
In conjunction with the merger with FPC, 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
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. Also in conjunction with the merger, the
FPSC opened a docket to review Florida Power's earnings including the effects of
the merger. The FPSC's decision expected by late March 2001 has been deferred.
Florida Power has agreed that if the FPSC subsequently takes formal action under
the interim rate statute, the effective date of that action will be March 13,
2001. The Company cannot predict the outcome of this matter.
Florida Power, with the approval of the FPSC, established a regulatory liability
to defer a portion of 2000 revenues. If an alternative proposal is not filed by
April 2, 2001, Florida Power will be directed to apply the deferred revenues of
$63 million, plus accrued interest, to offset certain regulatory assets related
to deferred purchased power termination costs.
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 1G 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. 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 will respond to
the petition and the request for stay. The Company 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 19 to the Progress Energy consolidated financial
statements for a discussion of recent spent nuclear fuel and DOE developments.
49
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Synthetic Fuels
Progress Energy, through its subsidiaries, is a majority owner in seven
facilities and a minority owner in two facilities that produce synthetic fuel
from coal fines, 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 fines used to produce such
synthetic fuel. In 1999, three of the majority-owned facilities applied for and
received a Private Letter Ruling (PLR) from the Internal Revenue Service (IRS)
regarding several issues relating to the facilities' qualification for tax
credits. During 2000, the four other majority-owned facilities applied for PLRs
with the IRS. On October 26, 2000, the IRS released Revenue Procedure 2000-47,
which notified taxpayers that the IRS National Office will not issue PLRs on the
question of whether a solid synthetic fuel produced from coal is a "qualified
fuel" under Section 29, except in the case of coke and in the case of solid
synthetic fuels produced from "waste coal." The procedure also advised
taxpayers, with pending ruling requests, that they can modify their requests to
advise the IRS if they are producing solid synthetic fuels from waste coal
sources. On December 6, 2000, the Company submitted a letter to advise the IRS
that the facilities with pending ruling requests are producing solid synthetic
fuel from waste coal sources and requested that they issue favorable rulings.
The IRS has yet to act on the PLRs. 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 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 EPA,
the Florida Department of Environment and 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 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 EFC 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.
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 have
recently been asked to provide information to the EPA as part of this initiative
and have cooperated in providing the requested information. The EPA has
initiated enforcement actions against other 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. 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 and South Carolina, 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. A portion
of this amount that is committed to be spent from 2001 to 2003 is discussed in
the "Investing Activities" section under LIQUIDITY AND
50
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CAPITAL RESOURCES above. 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 ozone standard. The cost of those controls are included
in the cost estimate of $370 million set forth above. 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 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 are participating in litigation
challenging the EPA's action. The Company cannot predict the outcome of this
matter.
Both electric utilities and the gas utility 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 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 1I to the Progress Energy consolidated financial statements for a
discussion of the impact of new accounting standards.
CAROLINA POWER & LIGHT COMPANY
- - - - - - ------------------------------
The information required by this item is incorporated herein by reference to the
following portions of Progress Energy's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate to CP&L:
RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER
MATTERS.
RESULTS OF OPERATIONS
- - - - - - ---------------------
On July 1, 2000, CP&L distributed its ownership interest in the stock of NCNG,
SRS, Monroe Power and Energy Ventures 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 the period 1999 compared to 1998. Additionally, the results of
operations for the CP&L Electric segment are identical between CP&L and Progress
Energy. The primary difference between the results of operations of Progress
Energy and CP&L for the 2000 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 Energy Ventures and therefore a comparison to the prior period
is not meaningful. Additionally, the other segment operations for Progress
Energy include amounts related to non-electric subsidiaries subsequent to the
FPC acquisition in November 30, 2000.
LIQUIDITY AND CAPITAL RESOURCES
- - - - - - -------------------------------
The statement of cash flows for CP&L does not include amounts related to NCNG,
SRS, Monroe Power and Energy Ventures 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.
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CP&L's estimated capital requirements for 2001, 2002 and 2003 are $691 million,
$608 million and $645 million, respectively, and primarily reflect construction
expenditures to add regulated generation and upgrade existing facilities.
See Note 6 to the CP&L consolidated financial statements for information on
CP&L's available credit facilities and future maturities of long-term debt at
December 31, 2000.
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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 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, 2000 and 1999,
respectively, 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. 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.
December 31, 2000
- - - - - - -----------------
<TABLE>
<CAPTION>
Fair Value
December 31,
2001 2002 2003 2004 2005 Thereafter Total 2000
- - - - - - --------------------------------------------------------------------------------------------------------------------------
<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 - - $ 986 - - - $ 986 $ 986
Average interest rate - - 7.25% - - - 7.25% -
Extendible notes - $ 500 - - - $ 500 $ 500
Average interest 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 (1) - $ 500 - - - - $ 500 $ (9.1)
Interest rate forward
contracts related to
anticipated long-term debt
issuances (2) $1,125 - - - - - $1,125 $(37.5)
</TABLE>
(1) Receives floating rate based on three-month LIBOR and pays fixed rate
of 7.17%
(2) Receives floating rate based on three-month LIBOR and pays weighted-average
fixed rates of approximately 6.77%.
53
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December 31, 1999
- - - - - - -----------------
<TABLE>
<CAPTION>
Fair Value
December 31,
2000 2001 2002 2003 2004 Thereafter Total 1999
- - - - - - --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
(Dollars in millions)
Fixed rate long-term debt $ 197 - $ 100 $ 7 $ 300 $1,319 $1,923 $1,845
Average interest rate 6.15% - 7.17% 12.88% 6.88% 7.09% 7.01% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 622
Average interest rate - - - - - 3.32% 3.32% -
Commercial paper $ 363 - - - - - $ 363 $ 363
Average interest rate 6.07% - - - - - 6.07% -
Extendible notes $ 332 - - - - - $ 332 $ 332
Average interest rate 5.88% - - - - - 5.88% -
- - - - - - -------------------------------------------------------------------------------------------------------------------------
</TABLE>
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents, which
are exposed to price fluctuations in equity markets and to changes in interest
rates. At December 31, 2000 the fair value of this fund was $812.0 million, of
which $411.3 million related to CP&L. At December 31, 1999 the fair value of
this fund was $379.9 million which only includes the trust funds of CP&L, as
Florida Power was acquired in November 2000. 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 the costs as recovered through the Company's
regulated electric rates 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 valued at fair value and unrealized
gains and losses from changes in fair value are recognized in earnings. At
December 31, 2000, the fair value of these CVOs was $40.4 million. A
hypothetical 10% decrease in market price would result in a $4.0 million
decrease in the fair value of the CVOs.
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. For the December 31, 2000 interest rate risk
information, the quantitative information incorporated from the Progress Energy
market risk disclosures mainly relates to CP&L except for approximately $1.7
billion of fixed-rate long term debt with a fair value of approximately $1.7
billion and an average interest rate of 6.73%; $500 million of variable rate
commercial paper with a fair value of $500 million and an average interest rate
of 7.10% and $300 million of FPC mandatorily redeemable securities of trust with
a fair value of $272 million and a fixed interest rate of 7.10%. These interest
rate risk sensitive instruments have been issued by FPC and its subsidiaries.
Additionally, the approximate $1.1 billion notional amount of interest rate
forward contracts have been issued by Progress Energy.
54
<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
----
Progress Energy, Inc.
- - - - - - ---------------------
<S> <C>
Independent Auditors' Report - Deloitte & Touche LLP 56
Independent Auditors' Report - KPMG LLP 57
Consolidated Financial Statements - Progress Energy:
Consolidated Statements of Income for the Years Ended December 31, 2000, 1999, and 1998, 58
Consolidated Balance Sheets as of December 31, 2000 and 1999 59
Consolidated Statements of Cash Flow for the Years Ended December 31, 2000, 1999
and 1998 60
Consolidated Schedules of Capitalization as of December 31, 2000 and 1999 61
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2000, 1999
and 1998 62
Consolidated Quarterly Financial Data (Unaudited) 62
Notes to Consolidated Financial Statements 63
Carolina Power & Light Company
- - - - - - ------------------------------
Independent Auditors' Report - Deloitte & Touche LLP 84
Consolidated Financial Statements - CP&L:
Consolidated Statements of Income for the Years Ended December 31, 2000, 1999, and 1998 85
Consolidated Balance Sheets as of December 31, 2000 and 1999 86
Consolidated Statements of Cash Flow for the Years Ended December 31, 2000, 1999
and 1998 87
Consolidated Schedules of Capitalization as of December 31, 2000 and 1999 88
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2000, 1999
and 1998 88
Consolidated Quarterly Financial Data (Unaudited) 89
Notes to Consolidated Financial Statements 90
Consolidated Financial Statement Schedules for the Years Ended December 31,
2000, 1999, and 1998:
II-Valuation and Qualifying Accounts - Progress Energy, Inc. 106
II-Valuation and Qualifying Account - Carolina Power & Light Company 107
</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.
55
<PAGE>
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets and schedules of
capitalization of Progress Energy, Inc. and its subsidiaries (the Company) as of
December 31, 2000 and 1999, and the related consolidated statements of income,
retained earnings, and cash flows for each of the three years in the period
ended December 31, 2000. Our audits also include the financial statement
schedule listed in the Index at Item 8. These financial statements and financial
statement schedule are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements 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 as of December 31, 2000. Those
financial statements were audited by other auditors whose report has been
furnished to us, and our opinion, insofar as is relates to the amounts included
for Florida Progress Corporation, 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
consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, 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, present fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 15, 2001
56
<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
57
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
- - - - - - ---------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands except per share data) 2000 1999 1998
- - - - - - ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $ 3,565,281 $ 3,138,846 $ 3,130,045
Natural gas 324,499 98,903 -
Diversified businesses 229,093 119,866 61,623
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 4,118,873 3,357,615 3,191,668
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 686,754 581,340 571,419
Purchased power 364,977 365,425 382,547
Gas purchased for resale 250,902 67,465 -
Other operation and maintenance 823,549 682,407 642,478
Depreciation and amortization 740,470 495,670 487,097
Taxes other than on income 165,393 142,741 141,504
Harris Plant deferred costs, net 14,278 7,435 7,489
Diversified businesses 352,992 174,589 111,584
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 3,399,315 2,517,072 2,344,118
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Operating Income 719,558 840,543 847,550
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 26,984 10,336 9,526
Gain on sale of assets 200,000 - -
Other, net (3,122) (33,706) (29,075)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 223,862 (23,370) (19,549)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Income before Interest Charges and Income Taxes 943,420 817,173 828,001
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 237,494 180,676 169,901
Other interest charges 45,459 10,298 11,156
Allowance for borrowed funds used during construction (20,668) (11,510) (6,821)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 262,285 179,464 174,236
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Income before Income Taxes 681,135 637,709 653,765
Income Taxes 202,774 258,421 257,494
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Net Income $ 478,361 $ 379,288 $ 396,271
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 157,169 148,344 143,941
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share $ 3.04 $ 2.56 $ 2.75
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share $ 3.03 $ 2.55 $ 2.75
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.075 $ 2.015 $ 1.955
- - - - - - ---------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Progress Energy, Inc. consolidated financial statements.
58
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
- - - - - - ---------------------------
<TABLE>
<CAPTION>
(In thousands) December 31
Assets 2000 1999
- - - - - - ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric utility plant in service $ 18,124,036 $ 10,633,823
Gas utility plant in service 378,464 354,773
Accumulated depreciation (9,350,235) (4,975,405)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 9,152,265 6,013,191
Held for future use 16,302 11,282
Construction work in progress 1,043,439 536,017
Nuclear fuel, net of amortization 224,692 204,323
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 10,436,698 6,764,813
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 101,296 79,871
Accounts receivable 925,911 446,367
Inventory 420,985 247,913
Deferred fuel cost 217,806 81,699
Prepayments 50,040 42,631
Assets held for sale, net 747,745 -
Other current assets 192,347 180,852
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 2,656,130 1,079,333
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Income taxes recoverable through future rates 208,997 229,008
Deferred purchased power contract termination costs 226,656 -
Harris Plant deferred costs 44,813 56,142
Unamortized debt expense 38,771 10,924
Nuclear decommissioning trust funds 811,998 379,949
Diversified business property, net 729,662 239,982
Miscellaneous other property and investments 510,935 252,454
Goodwill, net 3,652,429 288,970
Prepaid pension costs 373,151 -
Other assets and deferred debits 400,772 192,444
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 6,998,184 1,649,873
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Assets $ 20,091,012 $ 9,494,019
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Capitalization (See consolidated schedules of capitalization)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Common stock equity $ 5,424,201 $ 3,412,647
Preferred stock of subsidiaries-not subject to mandatory redemption 92,831 59,376
Long-term debt, net 5,890,099 3,028,561
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Capitalization 11,407,131 6,500,584
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 184,037 197,250
Accounts payable 828,568 269,053
Interest accrued 121,433 47,607
Dividends declared 107,645 80,939
Short-term obligations 3,972,674 168,240
Other current liabilities 448,302 130,036
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 5,662,659 893,125
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,807,192 1,632,778
Accumulated deferred investment tax credits 261,255 203,704
Postretirement benefit obligation 273,671 109,859
Other liabilities and deferred credits 679,104 153,969
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,021,222 2,100,310
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 19)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 20,091,012 $ 9,494,019
- - - - - - ---------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Progress Energy, Inc. consolidated financial statements.
59
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
- - - - - - -------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2000 1999 1998
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities
Net income $ 478,361 $ 379,288 $ 396,271
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 834,950 588,123 578,348
Harris Plant deferred costs 11,329 3,878 3,704
Deferred income taxes (73,446) (32,495) (38,517)
Investment tax credit (5,261) (10,299) (10,206)
Gain on sale of assets (200,000) - -
Deferred fuel credit (76,704) (39,052) (22,017)
Net increase in receivables, inventories, prepaid expenses
and other current assets (48,187) (168,148) (62,351)
Net (decrease) increase in payables and accrued expenses (12,214) 31,991 43,652
Other (48,920) 75,867 2,330
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 859,908 829,153 891,214
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (950,198) (689,054) (424,263)
Nuclear fuel additions (59,752) (75,641) (102,511)
Acquisition of Florida Progress Corporation (3,461,917) - -
Proceeds from sale of assets 212,825 - -
Contributions to nuclear decommissioning trust (32,391) (30,825) (30,848)
Net cash flow of company-owned life insurance program (4,291) (6,542) (1,954)
Investments in non-utility activities (242,688) (199,525) (103,543)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (4,538,412) (1,001,587) (663,119)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 783,052 400,970 6,255
Net increase in short-term indebtedness 3,782,071 339,100 242,100
Net increase (decrease) in outstanding payments 193,107 (117,643) 26,211
Retirement of long-term debt (710,373) (113,335) (208,050)
Dividends paid on common stock (368,004) (293,704) (279,717)
Other (66) 6,169 (448)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 3,679,787 221,557 (213,649)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents 1,283 49,123 14,446
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Increase in Cash from Acquisition (See Noncash Activities) 20,142 1,876 -
Cash and Cash Equivalents at Beginning of the Year 79,871 28,872 14,426
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 101,296 $ 79,871 $ 28,872
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 244,224 $ 174,101 $ 171,946
income taxes $ 367,665 $ 284,535 $ 329,739
</TABLE>
Noncash Activities
On July 15, 1999, the Company purchased all outstanding shares of North Carolina
Natural Gas Corporation (NCNG). In conjunction with the purchase of NCNG, the
Company issued 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.
60
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED SCHEDULES of CAPITALIZATION
- - - - - - ----------------------------------------
<TABLE>
<CAPTION>
December 31
(Dollars in thousands except per share data) 2000 1999
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common Stock Equity
Common stock without par value, authorized 500,000,000 shares, issued and
outstanding 206,089,047 and 159,599,650 shares, respectively $ 3,621,610 $ 1,754,187
Unearned restricted stock awards (12,708) (7,938)
Unearned ESOP common stock (127,211) (140,153)
Capital stock issuance expense - (794)
Retained earnings 1,942,510 1,807,345
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total Common Stock Equity $ 5,424,201 $ 3,412,647
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-not subject to mandatory redemption
Carolina Power & Light Company:
Authorized - 300,000 shares $5.00 cumulative, $100 par value Preferred Stock;
20,000,000 shares cumulative, $100 par value Serial Preferred Stock
$5.00 Preferred - 236,997 and 237,259 shares outstanding, respectively
(redemption price $110.00) $ 24,349 $ 24,376
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000 10,000
$5.44 Serial Preferred - 249,850 and 250,000 shares outstanding, respectively
(redemption price $101.00) 24,985 25,000
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
59,334 59,376
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Florida Power Corporation:
Authorized - 4,000,000 shares cumulative, $100 par value Preferred Stock;
5,000,000 shares cumulative, no par value preferred stock; 1,000,000 shares,
$100 par value Preference Stock
$100 par value Preferred Stock:
4.00% - 39,980 shares outstanding (redemption price $104.25) 3,998 -
4.40% - 75,000 shares outstanding (redemption price $102.00) 7,500 -
4.58% - 99,990 shares outstanding (redemption price $101.00) 9,999 -
4.60% - 39,997 shares outstanding (redemption price $103.25) 4,000 -
4.75% - 80,000 shares outstanding (redemption price $102.00) 8,000 -
- - - - - - ----------------------------------------------------------------------------------------------------------------------------
33,497 -
- - - - - - -----------------------------------------------------------------------------------------------------------------------------
Total Preferred Stock of Subsidiaries - not subject to mandatory redemption $ 92,831 $ 59,376
- - - - - - -----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt (maturities and weighted average interest
rates as of December 31, 2000)
Carolina Power and Light Company:
First mortgage bonds, maturing 2002-2024 7.02% $ 1,800,000 $ 1,866,130
Pollution control obligations, maturing 2014-2024 4.99% 713,770 497,640
Unsecured subordinated debentures, maturing 2025 8.55% 125,000 125,000
Extendible notes, maturing 2002 6.76% 500,000 331,760
Commercial paper reclassified to long-term debt 7.40% 486,297 362,600
Miscellaneous notes 8,360 54,846
Unamortized premium and discount, net (12,407) (12,165)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
3,621,020 3,225,811
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Florida Power Corporation:
First mortgage bonds, maturing 2003-2023 6.94% 510,000 -
Pollution control revenue bonds, maturing 2014-2027 6.59% 240,865 -
Medium-term notes, maturing 2001-2028 6.69% 531,100 -
Commercial paper reclassified to long-term debt 6.89% 200,000 -
Unamortized premium and discount, net (2,849) -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
1,479,116 -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Florida Progress Funding Corporation:
Mandatorily redeemable preferred securities, maturing 2039 7.10% 300,000 -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
300,000 -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Progress Capital Holdings:
Medium-term notes, maturing 2001-2008 6.85% 374,000 -
Commercial paper reclassified to long-term debt 7.24% 300,000 -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
674,000 -
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Current portion of long-term debt (184,037) (197,250)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net $ 5,890,099 $ 3,028,561
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Total Capitalization $11,407,131 $ 6,500,584
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Progress Energy, Inc. consolidated financial statements.
61
<PAGE>
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
- - - - - - --------------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands except per share data) 2000 1999 1998
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $ 1,807,345 $ 1,728,301 $ 1,613,881
Net income 478,361 379,288 396,271
Common stock dividends at annual per share rate of
$2.075, $2.015 and $1.955, respectively (343,196) (300,244) (281,851)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,942,510 $ 1,807,345 $ 1,728,301
- - - - - - ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
PROGRESS ENERGY, INC.
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
- - - - - - -------------------------------------------------
<TABLE>
<CAPTION>
(In thousands except per share data) First Quarter (a) Second Quarter (a) Third Quarter (a) Fourth Quarter (a)
- - - - - - ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Year ended December 31, 2000
Operating revenues $ 877,140 $ 892,304 $ 1,084,200 $ 1,265,229
Operating income 185,110 214,184 296,592 23,672 (c)
Net income 85,261 107,460 297,083 (b) (11,443) (c)
Common stock data:
Basic earnings per common share .56 .70 1.94 (b) (0.07) (c)
Diluted earnings per common share .56 .70 1.93 (b) (0.07) (c)
Dividends paid per common share .515 .515 .515 .515
Price per share - high 37.00 38.00 41.94 49.38
Low 28.25 31.00 31.50 38.00
- - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Operating revenues $ 762,902 $ 762,822 $ 1,024,756 $ 807,135
Operating income 199,361 157,371 308,963 174,848
Net income 91,470 62,417 147,112 78,289
Common stock data:
Basic and diluted earnings per common share .63 .43 .97 .51
Dividends paid per common share .50 .50 .50 .50
Price per share - high 47.88 45.00 43.25 36.81
low 37.63 36.63 34.13 29.25
- - - - - - ------------------------------------------------------------------------------------------------------------------------------------
</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.
See Notes to Progress Energy, Inc. consolidated financial statements.
62
<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. 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. The
Company also engages in business areas such as telecommunications, coal and
synthetic fuel operations, energy management and related services and
merchant energy generation.
The Company's results of operations include the results of Florida Progress
Corporation for the period 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 1999 and 1998 have been reclassified
to conform to the 2000 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with generally
accepted accounting principles, 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. Subsequent to the acquisition of
Florida Progress Corporation, Florida Power's utility plant continues 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.
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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:
2000 1999
----------- ----------
Electric
Production plant (7-33 years) $10,014,635 $6,413,121
Transmission plant (30-75 years) 1,964,652 1,018,114
Distribution plant (12-50 years) 5,292,134 2,676,881
General plant and other (8-75 years 852,615 525,707
----------- -----------
Total electric utility plant $18,124,036 $10,633,823
Gas plant (10-40 years) 378,464 354,773
----------- -----------
Utility plant in service $18,502,500 $10,988,596
=========== ===========
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 $15.5 million and $3.9 million in 2000
and 1999, respectively. There were no amounts credited to other income for
AFUDC during 1998. The composite AFUDC rate for CP&L's electric utility
plant was 8.16%, 6.4% and 5.6% in 2000, 1999 and 1998, respectively. The
composite AFUDC rate for Florida Power's electric utility plant was 7.8% in
2000. The composite AFUDC rate for NCNG's gas utility plant was 10.09% in
2000 and 1999.
E. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2000 1999
-------- ---------
Property, plant and equipment $566,972 $ 195,892
Construction work in progress 188,584 65,848
Accumulated depreciation (25,894) (21,758)
-------- ---------
Diversified business property, net $729,662 $ 239,982
======== =========
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; computers, office equipment
and software - 3 to 10 years; merchant generation and synthetic fuel
facilities - 7 to 25 years. Depletion of coal reserves is provided on the
units-of-production method based upon the estimates of recoverable tons of
clean coal.
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 4.1% in 2000 and 3.9% in 1999 and 1998.
Depreciation provisions totaled $721.0 million, $409.6 million and $394.4
million in 2000, 1999 and 1998, 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 $275
million during 2000 (See
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Note 12B). 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 and 1998.
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 to obligations to the DOE for the decommissioning and
decontamination of enrichment facilities are also charged to fuel expense.
Goodwill, the excess of purchase price over fair value of net assets of
businesses acquired, is being amortized on a straight-line basis over
periods ranging from 7 to 40 years. Accumulated amortization was $24.5
million and $11.5 million at December 31, 2000 and 1999, respectively. The
recoverability of goodwill is reviewed whenever events or changes in
circumstances indicate that the carrying value may not be recoverable. Such
evaluation is based on various analyses, including undiscounted cash flows
of the acquired operation.
The Financial Accounting Standards Board (FASB) is proceeding with its
project related to business combinations and accounting for goodwill. This
project, as proposed, would eliminate the amortization of goodwill and,
instead, would require goodwill to be reviewed periodically for impairment.
The FASB plans to issue a final statement in June 2001.
G. 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 $32.5 million in 2000 and $33.3
million in 1999 and 1998.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $1.0 billion and $568.0 million at December 31, 2000 and
1999, 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.
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, was
$515.8 million and is subject to change based on the same factors as
discussed above for CP&L's estimates. 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, 2000 this reserve was approximately $134.6 million and was
included in accumulated depreciation.
The FASB is proceeding with its project regarding accounting practices
related to obligations associated with the retirement of long-lived assets.
An exposure draft was issued in February 2000 and a final statement is
expected to
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<PAGE>
be issued during the second quarter of 2001. It is uncertain what effects
it may ultimately have on the Company's accounting for decommissioning,
dismantlement and other retirement costs.
H. 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.
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by the electric utilities' regulators. These
clauses allow the utilities to recover fuel costs and portions of purchased
power costs through surcharges on customer rates. NCNG is also allowed to
recover the costs of gas purchased for resale through customer rates.
Other property and investments are stated principally at cost. The Company
maintains an allowance for doubtful accounts receivable, which totaled
approximately $28.1 million and $16.8 million at December 31, 2000 and
1999, respectively. Inventory, which includes fuel, materials and supplies,
and gas in storage, 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, except that the balance existing at December 31,
1996 was amortized on a three-year accelerated basis. The Company considers
all highly liquid investments with original maturities of three months or
less to be cash equivalents.
I. Impact of New Accounting Standard
Effective January 1, 2001, the Company 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 consolidated
balance sheet and measure those instruments at fair value. The Company
estimates that the transition adjustment to implement this new standard
will be a decrease in other comprehensive income of $23.6 million, net of
tax. This adjustment will be recognized as of January 1, 2001, as a
cumulative effect of a change in accounting principle. There will not be a
significant transition adjustment affecting the consolidated statement of
income. The ongoing effects of SFAS No. 133 will depend on future market
conditions and the Company's positions in derivative instruments and
hedging activities.
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 11). The
purchase price includes $18.6 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 is Electric Fuels
Corporation, an energy and transportation company. The primary segments of
Electric Fuels are energy and related services, rail services, and inland
marine transportation.
The acquisition has been 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 estimated fair values of $6.9 billion and $4.9
billion, respectively. The excess of the purchase price over the estimated
fair value of the net identifiable assets and liabilities acquired has been
recorded as goodwill. The goodwill, of approximately $3.4 billion, is being
amortized on a straight-line basis over a period of primarily 40 years.
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. The allocation of the purchase
66
<PAGE>
price included estimated amounts expected to be realized from the sale of
FPC's Rail Services and Inland Marine Transportation business segments
which are classified as net assets held for sale (See Note 4). The SEC
order approving the merger requires the Company to divest of certain other
immaterial non-regulated investments of Florida Power.
The allocation of purchase price includes 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 had
been paid as of December 31, 2000. In addition, the Company began the
implementation of a plan to combine operations of the companies resulting
in a non-executive involuntary termination cost accrual of approximately
$52.2 million. Approximately $41.8 million is attributable to Florida Power
employees and has been reflected as part of the purchase price allocation,
while approximately $10.4 million attributable to acquiring company
employees was charged to operating results. The Company expects to complete
the implementation of the plan by the end of June 2001.
Preliminary actuarial valuations resulted in adjustments to increase the
other postretirement benefits liability by $16.8 million and the prepaid
pension asset by $222.0 million. These preliminary adjustments were
substantially offset by the establishment of an other postretirement
benefits regulatory asset of approximately $15.9 million and a pension
regulatory liability of $207.2 million. In addition, an adjustment
increased the supplementary defined benefit retirement plan liability by
$24.4 million.
The final purchase price allocation and estimated life of goodwill are
subject to adjustment for changes in the Company's preliminary assumptions
and analyses, pending additional information concerning asset and liability
valuations and the evaluation of certain pre-acquisition contingent
liabilities, including but not limited to:
o final actuarial valuations of pension and other postretirement benefit
plan obligations
o proceeds realized from the disposition of assets held for sale
o valuations of non-regulated businesses and individual assets and
liabilities
The following unaudited pro forma combined results of operations for the
years ended December 31, 2000 and 1999 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 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 $7,087,543 $6,181,494
Net income $ 585,863 $ 445,570
Basic and diluted earnings per share $ 2.93 $ 2.29
Average shares 199,722 194,591
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.
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
Effective with the acquisition of FPC on November 30, 2000, the Company has
changed the basis of segment reporting and measurement of segment
profitability beginning with the fourth quarter of 2000. Prior periods have
been restated to reflect this change. The Company currently provides
services through the following business segments: CP&L electric, Florida
Power electric, natural gas and other.
FPC's operations consisted mainly of the Florida Power electric segment and
certain other subsidiaries, which have
67
<PAGE>
been included in the other segment.
The electric segments (CP&L and Florida Power) generate, transmit,
distribute and sell 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 natural gas segment transports, distributes and sells gas in portions
of North Carolina. Gas operations are subject to the rules and regulations
of the NCUC.
The other segment is primarily made up of merchant energy generation, coal
and synthetic fuel operations and holding company operations. The other
segment also includes telecommunication services, energy management
services and 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.
<TABLE>
<CAPTION>
Florida
CP&L Power Natural Segment
(In thousands) Electric Electric Gas Other Totals
- - - - - - --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
FOR THE YEAR ENDED 12/31/00
Revenues
Unaffiliated $ 3,323,676 $ 241,606 $ 318,602 $ 229,092 $ 4,112,976
Intersegment - - 5,897 - 5,897
---------------------------------------------------------------------------
Total Revenues $ 3,323,676 $ 241,606 $ 324,499 $ 229,092 $ 4,118,873
Depreciation and Amortization $ 684,356 $ 28,873 $ 18,984 $ 22,911 $ 755,124
Net Interest Charges $ 221,856 $ 9,777 $ 7,122 $ 24,572 $ 263,327
Segment Income $ 367,511 $ 21,765 $ 7,066 $ 82,019 $ 478,361
Total Segment Assets $ 9,247,479 $ 4,918,776 $ 673,124 $ 5,251,633 $ 20,091,012
Capital and Investment Expenditures $ 805,489 $ 49,805 $ 94,899 $ 242,693 $ 1,192,886
====================================================================================================================
- - - - - - --------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED 12/31/99
Revenues
Unaffiliated $ 3,138,846 $ - $ 97,886 $ 119,866 $ 3,356,598
Intersegment - - 1,017 - 1,017
---------------------------------------------------------------------------
Total Revenues $ 3,138,846 $ - $ 98,903 $ 119,866 $ 3,357,615
Depreciation and Amortization $ 486,502 $ - $ 9,168 $ 16,804 $ 512,474
Net Interest Charges $ 183,098 $ - $ 3,225 $ (5,456) $ 180,867
Segment Income $ 422,581 $ - $ 1,284 $ (44,577) $ 379,288
Total Segment Assets $ 8,705,547 $ - $ 550,132 $ 238,340 $ 9,494,019
Capital and Investment Expenditures $ 671,401 $ - $ 24,047 $ 193,131 $ 888,579
====================================================================================================================
- - - - - - --------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED 12/31/98
Revenues
Unaffiliated $ 3,130,045 $ - $ - $ 61,623 $ 3,191,668
Intersegment - - - - -
---------------------------------------------------------------------------
Total Revenues $ 3,130,045 $ - $ - $ 61,623 $ 3,191,668
Depreciation and Amortization $ 487,097 $ - $ - $ 2,951 $ 490,048
Net Interest Charges $ 174,433 $ - $ - $ (48) $ 174,385
Segment Income $ 439,738 $ - $ - $ (43,467) $ 396,271
Total Segment Assets $ 8,211,372 $ - $ - $ 190,034 $ 8,401,406
Capital and Investment Expenditures $ 463,729 $ - $ - $ 64,077 $ 527,806
====================================================================================================================
</TABLE>
Segment totals for depreciation and amortization expense include expenses
related to the other segments that are included in diversified business
operating expenses on a consolidated basis. Segment totals for interest
expense include expenses related to the other segments that are included in
other, net on a consolidated basis.
4. Net Assets Held for Sale
At December 31, 2000, the Company's net assets held for sale reflect
management's estimate of the proceeds expected to be realized from the
disposal of FPC's Rail Services and Inland Marine Transportation business
segments. Rail Services' operations include railcar repair, rail parts
reconditioning and sales, scrap metal recycling and other rail related
services. Inland Marine Transportation provides transportation of coal,
agriculture and other dry-bulk commodities as well as fleet management
services. The Company intends to sell these business lines during 2001 in
order to focus on growing core businesses.
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<PAGE>
The Company's post-acquisition results of operations exclude a $0.7 million
net loss from the FPC's Rail Services and Inland Marine Transportation
businesses and allocated interest expense, net of tax, totaling
approximately $1 million. Both the expected earnings from these businesses
and allocated interest expense, net of tax, during the holding period on
the incremental debt incurred to finance the purchase of these business
segments has been included in the determination of net assets held for
sale.
Net assets held for sale related to the Inland Marine Transportation
segment are subject to certain commitments under operating leases (See Note
8).
5. Related Party Transactions
The Company operates two internal money pools, one for the utilities and
one for the non-utility subsidiaries, 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. The Company can loan money to either of
these two pools but is not allowed to borrow from either pool.
Prior to the acquisition of FPC, the Company purchased a 90% membership
interest in two synfuel related limited liability companies from a
wholly-owned subsidiary of FPC. Interest expense incurred during the
pre-acquisition period was approximately $3.3 million. Subsequent to the
acquisition date, intercompany amounts have been eliminated in
consolidation.
See Note 3 for NCNG gas sales to CP&L.
6. Debt and Credit Facilities
At December 31, 2000, the Company had lines of credit totaling $5.5
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 used to support the issuance of commercial paper (in millions).
<TABLE>
<CAPTION>
Subsidiary Description Short-term Long-term Total
---------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Progress Energy 364-Day $ 3,750 $ - $ 3,750
CP&L 364-Day - 375 375
CP&L 5-Year (4 years remaining) - 375 375
Florida Power 364-Day 200 - 200
Florida Power 5-Year (4 years remaining) - 200 200
Progress Capital 364-Day 100 - 100
Progress Capital 364-Day 200 - 200
Progress Capital 5-Year (3 years remaining) - 300 300
------------------------------
$ 4,250 $ 1,250 $ 5,500
</TABLE>
As of December 31, 2000, $845 million was drawn under Progress Energy's
credit facility. There were no loans outstanding under the other
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 $986 million has been reclassified to long-term debt
at December 31, 2000. Commercial paper, pollution control bonds, and other
short-term indebtedness of approximately $363 million, $56 million, and
$331 million, respectively, were reclassified to long-term debt at December
31, 1999. As of December 31, 2000 and 1999, the Company had an additional
$4 billion and $168 million, respectively of outstanding commercial paper
and other short-term debt classified as short-term obligations. The
weighted-average interest rates of such short-term obligations at December
31, 2000 and 1999 were 7.4% and 6.1%, 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, 2000.
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<PAGE>
Florida Power and CP&L both have public medium-term note programs providing
for the issuance of either fixed or floating interest rate notes. These
notes may have maturities ranging from 9 months to 30 years. Florida Power
and CP&L have balances of $250 million and $300 million, respectively,
available for issuance at December 31, 2000. In addition, Progress Capital
has a private medium-term note program with essentially the same terms as
the other programs. A balance of $400 million is available for issuance
under this program.
The combined aggregate maturities of long-term debt for 2001 through 2005
are approximately $184 million, $682 million, $1.3 billion, $368 million,
and $348 million, respectively.
7. FPC-Obligated Mandatorily Redeemable Preferred Securities (QUIPS) 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 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. Leases
The Company leases office buildings, computer equipment, vehicles, 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 $26.8 million,
$21.3 million and $20.0 million for 2000, 1999 and 1998, respectively.
Assets recorded under capital leases at December 31 consist of (in
thousands):
2000 1999
---- ----
Buildings $27,626 $27,626
Equipment 9,366 -
Less: Accumulated amortization (8,018) (6,760)
------- -------
$28,974 $20,866
------- -------
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases,
including the synthetic lease described below, as of December 31, 2000 are
(in thousands):
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<PAGE>
Capital Leases Operating Leases
-------------- ----------------
2001 $ 3,441 $ 96,433
2002 3,233 73,985
2003 3,233 69,998
2004 3,233 76,184
2005 3,233 59,084
Thereafter 35,330 251,808
------ -------
$ 51,703 $ 627,492
Less amount representing imputed interest (22,729)
-------
Present value of net minimum lease payments
under capital leases $ 28,974
--------
On August 6, 1998, MEMCO Barge Line, Inc. (MEMCO), an indirect,
wholly-owned subsidiary of FPC, entered into a synthetic lease financing,
accomplished via a sale and leaseback, for an aggregate of approximately
$175 million in inland river barges and $25 million in towboats (vessels).
MEMCO sold and leased back $153 million of vessels as of December 31, 1998,
and the remaining $47 million of vessels in May 1999. The lease (charter)
is an operating lease for financial reporting purposes and a secured
financing for tax purposes.
The term of the noncancelable charter expires on December 30, 2012, and
provides MEMCO one 18-month renewal option on the same terms and
conditions. MEMCO is responsible for all executory costs, including
insurance, maintenance and taxes, in addition to the charter payments.
MEMCO has options to purchase the vessels throughout the term of the
charter, as well as an option to purchase at the termination of the
charter. Assuming MEMCO exercises no purchase options during the term of
the charter, the purchase price for all vessels totals $141.8 million at
June 30, 2014. In the event that MEMCO does not exercise its purchase
option for all vessels, it will be obligated to remarket the vessels and,
at the expiration of the charter, pay a maximum residual guarantee amount
of $89.3 million.
The minimum future charter payments as of December 31, 2000, are $15.4
million, $15.4 million, $15.8 million, $15.8 million and $16.0 million for
2001 through 2005, respectively, and $140.4 million thereafter (excluding
the purchase option payment). All MEMCO payment obligations under the
transaction documents are unconditionally guaranteed by Progress Capital;
those obligations are guaranteed by FPC.
The Company is also a lessor of land and/or buildings and other types of
properties it owns under operating leases with various terms and expiration
dates. The leased buildings are depreciated under the same terms as other
buildings included in diversified business property. Minimum rentals
receivable under noncancelable leases as of December 31, 2000, are (in
thousands):
Amounts
--------
2001 $ 40,999
2002 31,743
2003 21,962
2004 16,396
2005 13,336
Thereafter 38,062
------
$162,498
--------
9. 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, 2000 and 1999, there were miscellaneous
investments with carrying amounts of approximately $61 million and $60
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 $6.1 billion
and $3.2 billion at December 31, 2000 and 1999, respectively. The estimated
fair value of this debt, as obtained from quoted market prices for the same
or similar issues, was $6.0 billion and $3.2 billion at December 31, 2000
and 1999, respectively.
External funds have been established as a mechanism to fund certain costs
of nuclear decommissioning (See Note 1G). These nuclear decommissioning
trust funds are invested in stocks, bonds and cash equivalents. Nuclear
71
<PAGE>
decommissioning trust funds are presented at amounts that approximate fair
value. Fair value is obtained from quoted market prices for the same or
similar investments.
10. Capitalization
As of December 31, 2000, the Company had 227,647,066 shares of authorized
but unissued common stock reserved and available for issuance, 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 Stock
Purchase-Savings Plan or with open market purchases of common stock shares,
as appropriate. During 2000 and 1999, the Company issued common stock in
conjunction with the FPC and NCNG acquisitions, respectively (See Note 2).
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2000,
there were no significant restrictions on the use of retained earnings.
11. Contingent Value Obligations
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, 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 (See Note
2A). The CVO liability was marked-to-market based on the year-end market
price. The liability, included in other liabilities and deferred credits,
at December 31, 2000, was $40.4 million.
12. 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. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of."
At December 31, 2000 and 1999, the balances of the utilities' regulatory
assets (liabilities) were as follows (in thousands):
2000 1999
---- ----
Income taxes recoverable through future rates* $208,997 $229,008
Harris Plant deferred costs 44,813 56,142
Loss on reacquired debt* 25,495 4,719
Other postretirement benefits 15,670 -
Deferred fuel 217,806 81,699
Abandonment costs* - 1,675
Deferred DOE enrichment facilities-related costs 36,027 40,897
Deferred purchased power contract termination costs 226,656 -
Defined benefit retirement plan (203,137) -
Deferred revenues (63,000) -
Other regulatory assets and liabilities, net 2,477 -
-------- --------
Total $511,804 $414,140
======== ========
* All or certain portions of these regulatory assets have been subject to
accelerated amortization (See Note 1F).
72
<PAGE>
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 1F). 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 will allow CP&L to reduce the minimum accelerated annual
depreciation in 2001 through 2004 to $75 million. The resulting total
accelerated depreciation in 2000 was $275 million. 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 June 2000, CP&L filed a request with the NCUC seeking approval to defer
sulfur dioxide (SO2) emission allowance expenses, effective as of January
1, 2000, for recovery in a future general rate case proceeding or by such
other means as the NCUC may find appropriate. On January 5, 2001, the NCUC
issued an order authorizing CP&L to defer, effective January 1, 2000, the
cost of SO2 emission allowances purchased pursuant to the Clean Air Act.
CP&L is allowed to recover emission allowance expense through the fuel
clause adjustment in its South Carolina retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. NCNG also agreed to cap its North Carolina margin rates for gas
sales and transportation services, with limited exceptions, through
November 1, 2003. Management is of the opinion that this agreement will not
have a material effect on the Company's consolidated results of operations
or financial position.
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 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. Also in conjunction
with the merger, the FPSC opened a docket to review Florida Power's
earnings including the effects of the merger. The FPSC's decision expected
by late March 2001 has been deferred. Florida Power has agreed that if the
FPSC subsequently takes formal action under the interim rate statute, the
effective date of that action will be March 13, 2001. The Company cannot
predict the outcome of this matter.
Florida Power, with the approval of the FPSC, established a regulatory
liability to defer a portion of 2000 revenues. If an alternative proposal
is not filed by April 2, 2001, Florida Power will be directed to apply the
deferred revenues at December 31, 2000 of $63 million, plus accrued
interest, to offset certain regulatory assets related to deferred purchased
power termination costs.
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. The balance of this reserve at December
31, 2000, was approximately $11 million.
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
and $24.2 million in 1999 and 1998, respectively.
13. 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.
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<PAGE>
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 2000, 1999 and 1998, 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
consolidated balance sheet at fair value, with changes in fair value
recognized in earnings. Gains and losses from such contracts were not
material during 2000, 1999 and 1998. Also, the Company did not have
material outstanding positions in such contracts at December 31, 2000 or
1999.
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 consolidated 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, 2000 or 1999.
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 $9.1 million liability position at December 31, 2000. Interest
rate swaps are accounted for using the settlement basis of accounting. 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 agreements, with a total notional amount of $1.125
billion, will be cash settled at the time that the hedged debt is issued.
These agreements have computational periods of two, five and ten years,
with $375 million notional amount for each computational period. Under the
agreements, the Company receives a floating rate based on the three-month
LIBOR and pays weighted-average fixed rates of approximately 6.65%, 6.76%
and 6.89% for the two, five and ten year computational periods,
respectively. The fair value of the swaps was a $37.5 million liability
position at December 31, 2000. Forward starting swaps are carried on the
consolidated balance sheet at fair value, with corresponding deferred gains
or losses. The resulting deferred losses or gains will be amortized and
recorded as adjustments to interest expense over the life of the related
debt issuances.
The notional amounts of the interest rate swaps and the forward starting
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.
14. Stock-Based Compensation Plans
A. Employee Stock Ownership Plan
The Company sponsors the Stock Purchase-Savings Plan (SPSP) for which
substantially all full-time employees and certain part-time employees of
the former CP&L Energy, Inc. (See Note 1A) are eligible. The SPSP, 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 SPSP, as amended in 1989, is an
Employee Stock Ownership Plan (ESOP) that can enter into acquisition loans
to acquire Company common stock to satisfy SPSP common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the SPSP. Common stock acquired with the proceeds of an
ESOP loan is held by the SPSP 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
74
<PAGE>
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 5,782,376 and 6,365,364 ESOP suspense shares at December 31,
2000 and 1999, respectively, with a fair value of $284.4 million and $193.7
million, respectively. ESOP shares allocated to plan participants totaled
13,549,257 and 12,966,269 at December 31, 2000 and 1999, respectively. The
Company's matching and incentive goal compensation cost under the SPSP is
determined based on matching percentages and incentive goal attainment as
defined in the plan. Such compensation cost is allocated to participants'
accounts in the form of Company common stock, with the number of shares
determined by dividing compensation cost by the common stock market value
at the time of allocation. The Company currently meets common stock share
needs with open market purchases and with shares released from the ESOP
suspense account. Matching and incentive cost met with shares released from
the suspense account totaled approximately $15.6 million, $16.3 million and
$15.3 million for the years ended December 31, 2000, 1999 and 1998,
respectively. The Company has a long-term note receivable from the SPSP
Trustee related to the purchase of common stock from the Company in 1989.
The balance of the note receivable from the SPSP 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. Other Stock-Based Compensation Plans
The Company has compensation plans for officers and key employees of the
Company that are stock-based in whole or in part. The two primary active
stock-based compensation programs are the Performance Share Sub-Plan (PSSP)
and the Restricted Stock Awards program (RSA), both of which were
established pursuant to the Company's 1997 Equity Incentive Plan.
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, which began in 1998, allows the Company to grant shares of
restricted common stock to 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 $36.97, $36.63 and $42.03 in
2000, 1999 and 1998, 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:
2000 1999 1998
---- ---- ----
Beginning balance 331,900 265,300 -
Granted 359,844 66,600 274,800
Forfeited (38,400) - (9,500)
---------------------------------------------
Ending balance 653,344 331,900 265,300
============================================
The total amount expensed for other stock-based compensation plans was
$15.6 million, $2.2 million and $1.3 million in 2000, 1999 and 1998,
respectively.
15. 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.
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<PAGE>
The components of net periodic pension benefit are (in thousands):
2000 1999 1998
---- ---- ----
Expected return on plan assets $(87,628) $ (75,124) $ (69,920)
Service cost 22,123 20,467 18,357
Interest cost 56,924 46,846 45,877
Amortization of transition obligation 125 106 106
Amortization of prior service benefit (1,314) (1,314) (158)
Amortization of actuarial gain (5,721) (3,932) (6,440)
--------- ---------- ----------
Net periodic pension benefit $(15,491) $ (12,951) $ (12,178)
========= ========== ==========
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.
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):
2000 1999
------ -----
Pension obligation
Pension obligation at January 1 $ 688,124 $678,210
Interest cost 56,924 46,846
Service cost 22,123 20,467
Benefit payments (55,291) (41,585)
Actuarial loss (gain) 39,798 (50,120)
Plan amendments - 5,546
Acquisitions 625,181 28,760
---------- --------
Pension obligation at December 31 $1,376,859 $688,124
Fair value of plan assets at December 31 1,843,410 947,143
---------- --------
Funded status $ 466,551 $259,019
Unrecognized transition obligation 495 582
Unrecognized prior service benefit (16,861) (18,175)
Unrecognized actuarial gain (158,541) (245,343)
----------- --------
Prepaid (accrued) pension cost at December 31, net $ 291,644 $ (3,917)
=========== =========
The net prepaid pension cost of $291.6 million at December 31, 2000 is
recognized in the accompanying consolidated balance sheet 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 accrued pension cost at
December 31, 1999 did not have prepaid components and, therefore, is reflected
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 $83.6 million at December 31, 2000, and those plans have no plan
assets.
Reconciliations of the fair value of pension plan assets are (in thousands):
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<PAGE>
2000 1999
----- -----
Fair value of plan assets at January 1 $ 947,143 $ 830,213
Actual return on plan assets 24,840 127,167
Benefit payments (55,291) (41,585)
Employer contributions 1,329 -
Acquisitions 925,389 31,348
----------- ---------
Fair value of plan assets at December 31 $ 1,843,410 $ 947,143
=========== =========
The weighted-average discount rate used to measure the pension obligation
was 7.5% in 2000 and 1999. The weighted-average rate of increase in future
compensation for non-bargaining unit employees used to measure the pension
obligation was 4.0% in 2000 and 4.2% in 1999. The corresponding rate of
increase in future compensation for bargaining unit employees was 3.5% in
2000. There were no bargaining unit employees in 1999. The expected
long-term rate of return on pension plan assets used in determining the net
periodic pension cost was 9.25% in 2000, 1999 and 1998.
In addition to pension benefits, the Company and some of its subsidiaries
provide contributory postretirement benefits (OPEB), including certain
health care and life insurance benefits, for retired employees who meet
specified criteria.
The components of net periodic OPEB cost are (in thousands):
2000 1999 1998
------- -------- -------
Expected return on plan assets $(4,045) $ (3,378) $(3,092)
Service cost 10,067 7,936 7,182
Interest cost 15,446 13,914 13,402
Amortization of prior service cost 107 - -
Amortization of transition obligation 5,878 5,760 5,641
Amortization of actuarial gain (819) (1) (549)
------- -------- --------
Net periodic OPEB cost $26,634 $ 24,231 $ 22,584
======= ======== ========
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):
2000 1999
---- ----
OPEB obligation
OPEB obligation at January 1 $ 213,488 $ 196,846
Interest cost 15,446 13,914
Service cost 10,067 7,936
Benefit payments (7,258) (5,769)
Actuarial gain (12,590) (7,307)
Plan amendment - 1,062
Acquisitions 155,770 6,806
--------- ----------
OPEB obligation at December 31 $ 374,923 $ 213,488
Fair value of plan assets at December 31 54,642 43,235
--------- ----------
Funded status $(320,281) $ (170,253)
Unrecognized transition obligation 70,715 76,593
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Unrecognized prior service cost 955 1,062
Unrecognized actuarial gain (25,060) (17,261)
---------- -----------
Accrued OPEB cost at December 31 $(273,671) $ (109,859)
========== ===========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2000 1999
---- ----
Fair value of plan assets at January 1 $43,235 $ 37,304
Actual return on plan assets 124 5,931
Acquisition 11,283 -
Employer contribution 7,258 5,769
Benefits paid (7,258) (5,769)
------- --------
Fair value of plan assets at December 31 $54,642 $ 43,235
======= ========
The assumptions used to measure the OPEB obligation are:
2000 1999
------ ------
Weighted-average discount rate 7.50% 7.50%
Initial medical cost trend rate for
pre-Medicare benefits 7.2% - 7.5% 7.50%
Initial medical cost trend rate for
post-Medicare benefits 6.2% - 7.5% 7.25%
Ultimate medical cost trend rate 5.0% - 5.3% 5.00%
Year ultimate medical cost trend rate is achieved 2005 - 2009 2006
The expected weighted-average long-term rate of return on plan assets used
in determining the net periodic OPEB cost was 9.20% in 2000 and 9.25% in
1999 and 1998. 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 2000 would
increase by $4.3 million, and the OPEB obligation at December 31, 2000,
would increase by $36.0 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 2000 would decrease by $3.6 million and the
OPEB obligation at December 31, 2000, would decrease by $34.5 million.
The Company has assets in a rabbi trust for the purpose of providing
benefits to the participants in the supplementary defined benefit
retirement plans and certain other plans for higher level employees. The
assets of the rabbi trust are not reflected as plan assets because the
assets could be subject to creditors' claims. The assets and liabilities of
the supplementary defined benefit retirement plans are included in Other
Assets and Deferred Debits and Other Liabilities and Deferred Credits on
the accompanying Consolidated Balance Sheets.
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. FPC's benefit plans are expected to be merged with those of the
Company effective January 1, 2002.
16. 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. Restricted stock awards and
contingently issuable shares had a dilutive effect on earnings per share
for 2000 and 1999 and increased the weighted-average number of common
shares outstanding for dilutive purposes by 454,924 in 2000, 290,474 in
1999 and 250,660 in 1998. The weighted-average number of common shares
outstanding for dilutive purposes was 157.6 million, 148.6 million and
144.2 million for 2000, 1999 and 1998, respectively.
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17. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. A regulatory asset or liability has been recognized for the
impact of tax expenses or benefits that are recovered or refunded in
different periods by the utilities pursuant to rate orders.
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
2000 1999
Accelerated depreciation and property
cost differences $ 2,054,509 $ 1,583,610
Deferred costs, net 63,085 70,478
Income tax credit carry forward (103,754) -
Miscellaneous other temporary differences, net (150,969) 26,403
Valuation allowance 10,868 -
----------- -----------
Net accumulated deferred income
tax liability $ 1,873,739 $ 1,680,491
=========== ===========
Total deferred income tax liabilities were $2.79 billion and $2.20 billion
at December 31, 2000 and 1999, respectively. Total deferred income tax
assets were $919 million and $519 million at December 31, 2000 and 1999,
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 has established a valuation allowance of $10.9 million 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:
2000 1999 1998
---- ---- ----
Effective income tax rate 29.7% 40.3% 39.2%
Harris accelerated depreciation (1.9) - -
State income taxes, net of federal benefit (4.8) (4.6) (4.7)
Synthetic fuel income tax credits 12.2 - -
Investment tax credit amortization 4.2 1.6 1.5
Other differences, net (4.4) (2.3) (1.0)
----- ----- -----
Statutory federal income tax rate 35.0% 35.0% 35.0%
===== ===== =====
The provisions for income tax expense are comprised of (in thousands):
2000 1999 1998
Income tax expense (credit)
Current - federal $254,967 $ 253,140 $ 254,400
state 61,309 48,075 51,817
Deferred - federal (84,605) (30,011) (34,842)
state (10,761) (2,484) (3,675)
Investment tax credit (18,136) (10,299) (10,206)
--------- ---------- ----------
Total income tax expense $202,774 $ 258,421 $ 257,494
========= ========== ==========
The Company is a majority owner in seven facilities and a minority owner in
two facilities that produce synthetic fuel from fine coal feedstock, as
defined under the Internal Revenue Service Code Section 29 (Section 29).
The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 if certain requirements are
satisfied. Should the tax credits be denied on future audits, and the
Company fails to prevail
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<PAGE>
through the Internal Revenue Service or legal process, there could be
significant tax liability owed for previously-taken Section 29 credits,
with a significant impact on consolidated results of operations and cash
flows. Management believes it is probable, although it cannot provide
certainty, that it will prevail on any credits taken.
18. 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 interest in the jointly owned
generating facilities are listed below with related information as of
December 31, 2000 (dollars in thousands):
<TABLE>
<CAPTION>
Company
Megawatt Ownership Plant Accumulated Under
Subsidiary Facility Capability Interest Investment Depreciation Construction
---------- -------- ---------- -------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
CP&L Mayo Plant 745 83.83% $ 451,769 $ 218,029 $ 12,248
CP&L Harris Plant 860 83.83% 3,026,074 1,255,008 71,250
CP&L Brunswick Plant 1,631 81.67% 1,422,640 1,121,880 12,555
CP&L Roxboro Unit No. 4 700 87.06% 242,605 122,651 57,190
Florida Power Crystal River Plant 834 91.78% 773,300 754,100 14,100
</TABLE>
In the table above, plant investment and accumulated depreciation, which
includes accumulated nuclear decommissioning, are not reduced by the
regulatory disallowances related to the Harris Plant.
19. Commitments and Contingencies
A. 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 $33.9 million, $36.5 million and $34.4
million for 2000, 1999 and 1998, respectively. In 1987, the NCUC ordered
CP&L to reflect the recovery of the capacity portion of these costs on a
levelized basis over the original 15-year buyback period, thereby deferring
for future recovery the difference between such costs and amounts collected
through rates. In 1988, the SCPSC ordered similar treatment, but with a
10-year levelization period. At December 31, 2000 and 1999, CP&L had
deferred purchased capacity costs, including carrying costs accrued on the
deferred balances, of $44.8 million and $56.1 million, respectively.
Increased purchases (which are not being deferred for future recovery)
resulting from the 1993 agreement with Power Agency were approximately $26
million, $23 million and $19 million for 2000, 1999 and 1998, respectively.
During 2000, CP&L had 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 an estimated minimum annual
payment of approximately $31 million, representing capital-related capacity
costs. Total purchases (including transmission use charges) under the
Rockport agreement amounted to $61 million, $59.2 million and $59.3 million
for 2000, 1999 and 1998, respectively. During 1998 and part of 1999, CP&L
had an additional long-term agreement to purchase power and related
transmission services from Duke Energy. Total purchases under this
agreement amounted to $33.8 million and $75.5 million for 1999 and 1998,
respectively.
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 $104.5 million for 2000.
Minimum purchases under
80
<PAGE>
these contracts, representing capital-related capacity costs, are
approximately $50 million annually through 2003 and $30 million annually
during 2004 and 2005.
B. Other Commitments
The Company has certain future commitments related to synthetic fuel
facilities purchased. These agreements require payments to the seller based
on the tons of synthetic fuel produced and sold. During 2000, payments made
under these agreements amounted to $42 million.
C. Insurance
The Company is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, the
Company is insured for $500 million at each of its nuclear plants. In
addition to primary coverage, NEIL also provides decontamination, premature
decommissioning and excess property insurance with limits of $1.0 billion
on the Brunswick Plant, $1.0 billion on the Harris Plant, $800 million on
the Robinson Plant, and $1.1 billion on CR3. An additional shared limit
policy of $1 billion in excess of $1 billion is also provided through NEIL
on the Brunswick and Harris Plants for decontamination, premature
decommissioning and excess property.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. The Company is insured thereunder,
following a twelve week deductible period, for 52 weeks in weekly amounts
of $2.25 million at Brunswick Unit No. 1, $2.25 million at Brunswick Unit
No. 2, $2.4 million at the Harris Plant, $1.96 million at Robinson Unit No.
2 and $2.1 million at CR3. An additional 104 weeks of coverage is provided
at 80% of the above weekly amounts. For the current policy period, the
Company is subject to retrospective premium assessments of up to
approximately $13.5 million with respect to the primary coverage, $15.4
million with respect to the decontamination, decommissioning and excess
property coverage, $2.6 million with respect to the shared limit excess
coverage and $7.1 million for the incremental replacement power costs
coverage, in the event covered expenses at insured facilities exceed
premiums, reserves, reinsurance and other NEIL resources. These resources
as of December 31, 2000 totaled approximately $4.6 billion. Pursuant to
regulations of the NRC, the 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. The Company is responsible to the extent
losses may exceed limits of the coverage described above.
The Company is insured against public liability for a nuclear incident up
to $9.54 billion per occurrence. In the event that public liability claims
from an insured nuclear incident exceed $200 million, CP&L and Florida
Power would be subject to a pro rata assessment of up to $83.9 million and
$88.1 million, respectively, for each reactor owned per occurrence. Payment
of such assessment would be made over time as necessary to limit the
payment in any one year to no more than $10 million per reactor owned.
Florida Power self-insures its transmission and distribution lines against
loss due to storm damage and other natural disasters. Pursuant to a
regulatory order, Florida Power is accruing $6 million annually to a storm
damage reserve and may defer any losses in excess of the reserve. The
reserve balance at December 31, 2000 was $29.5 million.
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 Environment and 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 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.
81
<PAGE>
Both electric utilities, the gas utility and Electric Fuels 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.
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 have recently been asked to provide information
to the EPA as part of this initiative and have cooperated in providing the
requested information. The EPA has initiated enforcement actions against
other 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. 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 and South Carolina,
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. 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 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 are participating in litigation challenging the EPA's action. The
Company cannot predict the outcome of this matter.
Both electric utilities and the gas utility 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 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 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 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.
82
<PAGE>
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
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 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. 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, with certain modifications to its
storage pools currently underway, 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.
20. Subsequent Event
In February 2001, the Company issued $3.2 billion of senior unsecured notes
with maturities ranging from three to thirty years. Proceeds from this
issuance were used to retire short-term obligations issued in connection
with the FPC acquisition.
83
<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, 2000 and 1999, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in the
period ended December 31, 2000. Our audits also included the financial statement
schedule listed in the Index at Item 8. These financial statements and financial
statement schedule are the responsibility of CP&L's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of CP&L as of December 31, 2000 and
1999, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2000, 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, 2001
84
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of INCOME
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2000 1999 1998
- - - - - - -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Electric $ 3,323,676 $ 3,138,846 $ 3,130,045
Natural gas 147,448 98,903 -
Diversified businesses 72,783 119,866 61,623
- - - - - - -------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,543,907 3,357,615 3,191,668
- - - - - - -------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 627,463 581,340 571,419
Purchased power 325,366 365,425 382,547
Gas purchased for resale 103,734 67,465 -
Other operation and maintenance 741,466 682,407 642,478
Depreciation and amortization 693,971 495,670 487,097
Taxes other than on income 148,037 142,741 141,504
Harris Plant deferred costs, net 14,278 7,435 7,489
Diversified businesses 135,258 174,589 111,584
- - - - - - -------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,789,573 2,517,072 2,344,118
- - - - - - -------------------------------------------------------------------------------------------------------
Operating Income 754,334 840,543 847,550
- - - - - - -------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 26,226 10,336 9,526
Gain on sale of assets 200,000 - -
Other, net (7,795) (30,739) (26,108)
- - - - - - -------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 218,431 (20,403) (16,582)
- - - - - - -------------------------------------------------------------------------------------------------------
Income before Interest Charges and Income Taxes 972,765 820,140 830,968
- - - - - - -------------------------------------------------------------------------------------------------------
Interest Charges
Long-term debt 223,562 180,676 169,901
Other interest charges 16,441 10,298 11,156
Allowance for borrowed funds used during construction (18,537) (11,510) (6,821)
- - - - - - -------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 221,466 179,464 174,236
- - - - - - -------------------------------------------------------------------------------------------------------
Income before Income Taxes 751,299 640,676 656,732
Income Taxes 290,271 258,421 257,494
- - - - - - -------------------------------------------------------------------------------------------------------
Net Income 461,028 382,255 399,238
Preferred Stock Dividend Requirement 2,966 2,967 2,967
- - - - - - -------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 458,062 $ 379,288 $ 396,271
- - - - - - -------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Carolina Power & Light Company consolidated financial statements.
85
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
- - - - - - ---------------------------
(In thousands)
<TABLE>
<CAPTION>
December 31
Assets 2000 1999
- - - - - - ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Utility Plant
Electric utility plant in service $ 11,125,901 $ 10,633,823
Gas utility plant in service - 354,773
Accumulated depreciation (5,505,731) (4,975,405)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 5,620,170 6,013,191
Held for future use 7,105 11,282
Construction work in progress 815,246 536,017
Nuclear fuel, net of amortization 184,813 204,323
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 6,627,334 6,764,813
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 30,070 79,871
Accounts receivable 466,774 446,367
Receivables from affiliated companies 362,834 -
Taxes receivable 15,412 3,770
Inventory 233,369 247,913
Deferred fuel cost 119,853 81,699
Prepayments 24,284 42,631
Other current assets 75,451 177,082
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,328,047 1,079,333
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Income taxes recoverable through future rates 210,571 229,008
Harris Plant deferred costs 44,813 56,142
Unamortized debt expense 15,716 10,924
Nuclear decommissioning trust funds 411,279 379,949
Diversified business property, net 102,294 239,982
Miscellaneous other property and investments 395,995 252,454
Goodwill, net - 288,970
Other assets and deferred debits 124,339 192,444
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,305,007 1,649,873
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Assets $ 9,260,388 $ 9,494,019
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of capitalization)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Common stock equity $ 2,852,038 $ 3,412,647
Preferred stock - not subject to mandatory redemption 59,334 59,376
Long-term debt, net 3,619,984 3,028,561
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Capitalization 6,531,356 6,500,584
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt - 197,250
Accounts payable 281,026 269,053
Payables to affiliated companies 275,976 -
Interest accrued 56,259 47,607
Dividends declared 1,482 80,939
Short-term obligations - 168,240
Other current liabilities 146,191 130,036
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 760,934 893,125
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,491,660 1,632,778
Accumulated deferred investment tax credits 197,207 203,704
Other liabilities and deferred credits 279,231 263,828
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,968,098 2,100,310
- - - - - - ----------------------------------------------------------------------- ---------------------------------------------
-
Commitments and Contingencies (Note 15)
- - - - - - ---------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 9,260,388 $ 9,494,019
- - - - - - ---------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Carolina Power & Light Company consolidated financial statements.
86
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of CASH FLOWS
- - - - - - -------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2000 1999 1998
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities
Net income $ 461,028 $ 382,255 $ 399,238
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 788,727 588,123 578,348
Harris Plant deferred costs 11,329 3,878 3,704
Deferred income taxes (83,553) (32,495) (38,517)
Investment tax credit (4,512) (10,299) (10,206)
Gain on sale of assets (200,000) - -
Deferred fuel credit (40,763) (39,052) (22,017)
Net decrease in receivables, inventories, prepaid expenses
and other current assets (215,841) (168,148) (62,351)
Net (decrease) increase in payables and accrued expenses 299,512 31,991 43,652
Other 29,180 75,867 2,330
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,045,107 832,120 894,181
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (821,991) (689,054) (424,263)
Nuclear fuel additions (59,752) (75,641) (102,511)
Proceeds from sale of assets 200,000 - -
Contributions to nuclear decommissioning trust (30,727) (30,825) (30,848)
Net cash flow of company-owned life insurance program (4,291) (6,542) (1,954)
Investments in non-utility activities (163,714) (199,525) (103,543)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (880,475) (1,001,587) (663,119)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 783,052 400,970 6,255
Net increase in short-term indebtedness 123,697 339,100 242,100
Net increase (decrease) in outstanding payments 21,069 (117,643) 26,211
Retirement of long-term debt (695,163) (113,335) (208,050)
Redemption of preferred stock (42) - -
Dividends paid on preferred stock (2,966) (2,967) (2,967)
Dividends paid on common stock (432,325) (293,704) (279,717)
Other - 6,169 (448)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (202,678) 218,590 (216,616)
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Net Increase in Cash and Cash Equivalents (38,046) 49,123 14,446
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Increase in Cash from Acquisition (See Noncash Activities) - 1,876 -
Decrease in Cash from Stock Distribution (See Note 1) (11,755) - -
Cash and Cash Equivalents at Beginning of the Year 79,871 28,872 14,426
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 30,070 $ 79,871 $ 28,872
- - - - - - ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest $ 205,250 $ 174,101 $ 171,946
income taxes $ 434,908 $ 284,535 $ 329,739
</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 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 Corporation,
Monroe Power Company and Progress Energy Ventures, Inc. to Progress Energy, Inc.
This resulted in a noncash dividend to its parent of approximately $555.9
million.
See Notes to Carolina Power & Light Company consolidated financial statements.
87
<PAGE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES of CAPITALIZATION
- - - - - - ----------------------------------------
<TABLE>
<CAPTION>
December 31
(Dollars in thousands except per share data) 2000 1999
- - - - - - --------------------------------------------------------------------------------------------------------------------
Common Stock Equity
<S> <C> <C>
Common stock without par value, authorized 200,000,000 shares, issued and
outstanding 159,608,055 and 159,599,650 shares, respectively $ 1,766,607 $ 1,754,187
Unearned restricted stock awards (12,708) (7,938)
Unearned ESOP common stock (127,211) (140,153)
Capital stock issuance expense (794) (794)
Retained earnings 1,226,144 1,807,345
- - - - - - --------------------------------------------------------------------------------------------------------------------
Total Common Stock Equity $ 2,852,038 $ 3,412,647
- - - - - - --------------------------------------------------------------------------------------------------------------------
- - - - - - --------------------------------------------------------------------------------------------------------------------
Preferred Stock - not subject to mandatory redemption
Authorized - 300,000 shares $5.00 cumulative, $100 par value Preferred Stock;
20,000,000 shares cumulative, $100 par value Serial Preferred Stock
$5.00 Preferred - 236,997 and 237,259 shares, respectively (redemption
price $110.00) $ 24,349 $ 24,376
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price
$102.00) 10,000 10,000
$5.44 Serial Preferred - 249,850 and 250,000 shares,
respectively (redemption price $101.00) 24,985 25,000
- - - - - - --------------------------------------------------------------------------------------------------------------------
Total Preferred Stock $ 59,334 $59,376
- - - - - - --------------------------------------------------------------------------------------------------------------------
- - - - - - --------------------------------------------------------------------------------------------------------------------
Long-Term Debt (maturities and weighted average interest rates as of
December 31, 2000)
First mortgage bonds, maturing 2002-2024 7.02% $ 1,800,000 $ 1,866,130
Pollution control obligations, maturing 2014-2024 4.99% 713,770 497,640
Unsecured subordinated debentures, maturing 2025 8.55% 125,000 125,000
Extendible notes, maturing 2002 6.76% 500,000 331,760
Commercial paper reclassified to long-term debt 7.40% 486,297 362,600
Miscellaneous notes 7,324 54,846
Unamortized premium and discount, net (12,407) (12,165)
Current portion - (197,250)
- - - - - - --------------------------------------------------------------------------------------------------------------------
Total Long-Term Debt 3,619,984 3,028,561
- - - - - - --------------------------------------------------------------------------------------------------------------------
- - - - - - --------------------------------------------------------------------------------------------------------------------
Total Capitalization $6,531,356 $ 6,500,584
- - - - - - --------------------------------------------------------------------------------------------------------------------
</TABLE>
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
- - - - - - --------------------------------------------
<TABLE>
<CAPTION>
Years ended December 31
(In thousands) 2000 1999 1998
- - - - - - --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Retained Earnings at Beginning of Year $ 1,807,345 $ 1,728,301 $1,613,881
Net income 461,028 382,255 399,238
Preferred stock dividends at stated rates (2,966) (2,967) (2,967)
Common stock dividends (1,039,263) (300,244) (281,851)
- - - - - - --------------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,226,144 $ 1,807,345 $1,728,301
- - - - - - --------------------------------------------------------------------------------------------------------------------
</TABLE>
See Notes to Carolina Power & Light Company consolidated financial statements.
88
<PAGE>
CAROLINA POWER & LIGHT COMPANY
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, 2000
Operating revenues $ 877,140 $ 892,304 $ 943,112 $ 831,351
Operating income 185,110 214,184 330,675 24,365 (c)
Net income 86,003 108,202 291,914 (b) (25,091) (c)
- - - - - - ------------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 1999
Operating revenues $ 762,902 $ 762,822 $ 1,025,746 $ 806,145
Operating income 199,408 157,371 308,963 174,801
Net income 92,212 63,159 147,854 79,030
</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.
See Notes to Carolina Power & Light Company consolidated financial statements.
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<PAGE>
CAROLINA POWER & LIGHT COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina and South Carolina. CP&L is a
wholly-owned subsidiary of Progress Energy, Inc. (the Company), 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 (PUCHA) of 1935. Both the Company and its
subsidiaries are subject to the regulatory provisions of the PUCHA.
On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas (NCNG), Strategic Resource Solutions Corporation
(SRS), Monroe Power Company (Monroe Power) and Progress Energy Ventures,
Inc. (Energy Ventures) to the Company. As a result, those companies are
direct subsidiaries of the 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 1999 and
1998 have been reclassified to conform to the 2000 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with generally
accepted accounting principles, 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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<PAGE>
The balances of utility plant in service at December 31 are listed below
(in thousands), with a range of depreciable lives for each:
2000 1999
Electric --------------- ----------------
Production plant (7-33 years) $ 6,659,111 $ 6,413,121
Transmission plant (30-75 years) 1,060,080 1,018,114
Distribution plant (12-50 years) 2,869,104 2,676,881
General plant and other (8-75 years) 537,606 525,707
-------------- ----------------
Total electric utility plant $11,125,901 $10,633,823
Gas plant (10-40 years) - 354,773
-------------- ----------------
Utility plant in service $11,125,901 $10,988,596
=============== ================
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 $14.5 million and $3.9 million in 2000
and 1999, respectively. There were no amounts credited to other income for
the equity funds portion of AFUDC during 1998. The composite AFUDC rate for
CP&L's electric utility plant was 8.2%, 6.4% and 5.6% in 2000, 1999 and
1998, respectively. The composite AFUDC rate for NCNG's gas utility plant
was 10.09% in 2000 and 1999.
E. Diversified Business Property
The following is a summary of diversified business property (in thousands):
2000 1999
-------- ---------
Property, plant and equipment $ 85,062 $ 195,892
Construction work in progress 25,603 65,848
Accumulated depreciation (8,371) (21,758)
-------- ---------
Diversified business property, net $102,294 $ 239,982
======== =========
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; computers, office equipment
and software - 3 to 10 years; merchant generation facilities - 25 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 2000 and 3.9% in 1999 and 1998.
Depreciation provisions totaled $688.8 million, $409.6 million and $394.4
million in 2000, 1999 and 1998, 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 $275
million during 2000 (See Note 8B). Pursuant to authorizations from the NCUC
and the SCPSC, CP&L accelerated the amortization of certain
91
<PAGE>
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 and 1998.
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 to obligations to the DOE for the decommissioning and
decontamination of enrichment facilities are also charged to fuel expense.
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 2000 and $33.3
million in 1999 and 1998.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $599.3 million and $568.0 million at December 31, 2000
and 1999, 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 is proceeding with its project
regarding accounting practices related to obligations associated with the
retirement of long-lived assets. An exposure draft was issued in February
2000 and a final statement is expected to be issued during the second
quarter of 2001. It is uncertain what effects it may ultimately have on
CP&L's accounting for decommissioning and other retirement costs.
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.
Other property and investments are stated principally at cost. CP&L
maintains an allowance for doubtful accounts receivable, which totaled
approximately $17.0 million and $16.8 million at December 31, 2000 and
1999, respectively. Inventory, which includes fuel, materials and supplies,
and gas in storage, 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, except that the balance existing at December 31,
1996 was amortized on a three-year accelerated basis. CP&L considers all
highly liquid investments with original maturities of three months or less
to be cash equivalents.
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<PAGE>
I. Impact of New Accounting Standard
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 consolidated balance sheet and
measure those instruments at fair value. There will not be a significant
transition adjustment affecting other comprehensive income or affecting the
consolidated statement of income. The ongoing effects of SFAS No. 133 will
depend on future market conditions and CP&L's positions in derivative
instruments and hedging activities.
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 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 results of operations and NCNG's assets and
liabilities are no longer included in CP&L's consolidated balance sheet.
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 Energy Ventures 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 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 by business segment for CP&L-Electric for the
years ended December 31, 2000, 1999 and 1998 is as follows:
<TABLE>
<CAPTION>
Year Ended Year Ended Year Ended
(In thousands) December 31, 2000 December 31, 1999 December 31, 1998
- - - - - - -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Revenues
Unaffiliated $ 3,323,676 $ 3,138,846 $ 3,130,045
Intersegment - - -
------------------------------------------------------------------
Total Revenues $ 3,323,676 $ 3,138,846 $ 3,130,045
Depreciation and Amortization $ 684,356 $ 486,502 $ 487,097
Net Interest Charges $ 221,856 $ 183,098 $ 174,433
Segment Income $ 367,511 $ 422,581 $ 439,738
Total Segment Assets $ 9,247,479 $ 8,705,547 $ 8,211,372
Capital and Investment Expenditures $ 805,489 $ 671,401 $ 463,729
===========================================================================================================
</TABLE>
The primary differences between the CP&L Electric and CP&L consolidated
financial information relate to other non-electric operations and elimination
entries.
93
<PAGE>
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, 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 sheet.
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 SEC. CP&L has an agreement with PESC under
which services, including purchasing, accounting, treasury, tax, marketing,
legal and human resources, are rendered to CP&L at cost. Amounts billed to
CP&L by PESC for these services during 2000 amounted to $52.4 million.
During the year ended December 31, 2000 and the period from July 15, 1999
to December 31, 1999, gas sales from NCNG to CP&L amounted to $5.9 million
and $1.0 million, respectively.
Subsequent to July 1, 2000 (See Note 1A) the consolidated statement of
income contains interest income received from NCNG in the amount of $4.1
million. Prior to this date, the interest income received from NCNG was
eliminated in consolidation. At December 31, 2000, CP&L had $135.9 million
of notes receivable from NCNG that are included in receivables from
affiliated companies on the consolidated balance sheet.
See Note 11B related to restricted stock purchases for affiliated
companies.
The remaining amounts of receivables and payables from (to) affiliate
companies at December 31, 2000 represent intercompany amounts generated
through CP&L's normal course of operations.
5. Leases
CP&L leases office buildings, computer equipment, vehicles, and other
property and equipment with various terms and expiration dates. Rent
expense (under operating leases) totaled $13.8 million, $15.7 million and
$15.8 million for 2000, 1999 and 1998, respectively.
Assets recorded under capital leases consist of (in thousands):
2000 1999
---- ----
Buildings $27,626 $27,626
Less: Accumulated amortization (8,018) (6,760)
------- -------
$19,608 $20,866
------- -------
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as
of December 31, 2000 are (in thousands):
Capital Leases Operating Leases
2001 $ 2,366 $ 17,217
2002 2,159 12,332
2003 2,159 8,176
2004 2,159 6,696
2005 2,159 6,290
Thereafter 24,589 34,108
-------- ----------
$ 35,591 $ 84,819
Less amount representing imputed
interest (15,983)
--------
Present value of net minimum lease
payments under capital leases $ 19,608
--------
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<PAGE>
CP&L is also a lessor of land and/or buildings it owns under operating
leases with various terms and expiration dates. The leased buildings are
depreciated under the same terms as other buildings included in diversified
business property. Minimum rentals receivable under noncancelable leases as
of December 31, 2000, are (in thousands):
Amounts
2001 $ 5,429
2002 5,074
2003 4,991
2004 4,683
2005 4,299
Thereafter 19,022
------
$43,498
-------
6. Debt and Credit Facilities
At December 31, 2000, CP&L had lines of credit totaling $750 million, all
of which are used to support its commercial paper borrowings. CP&L is
required to pay minimal annual commitment fees to maintain its credit
facilities. The following table summarizes CP&L's credit facilities used to
support the issuance of commercial paper (in millions).
Description Short-term Long-term Total
---------------------------------------------------------------------------
364-Day $ - $ 375 $ 375
5-Year (4 years remaining) - 375 375
-------------------------------------------------
$ - $ 750 $ 750
There were no loans outstanding under these facilities at December 31,
2000. 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 $486 million has been reclassified to long-term debt
at December 31, 2000. Commercial paper, pollution control bonds, and other
short-term indebtedness of approximately $363 million, $56 million, and
$331 million, respectively, were reclassified to long-term debt at December
31, 1999. As of December 31, 1999, CP&L had an additional $168 million of
outstanding commercial paper and other short-term debt classified as
short-term obligations. The weighted average interest rate of such
short-term obligations was 6.1%.
CP&L has a public medium-term note program providing for the issuance of
either fixed or floating interest rate notes. These notes may have
maturities ranging from 9 months to 30 years. CP&L has a balance of $300
million available for issuance at December 31, 2000
The combined aggregate maturities of long-term debt for 2002 through 2005
are approximately $600 million, $493 million, $300 million, and $300
million, respectively. There are no maturities of long-term debt in 2001.
7. 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, 2000 and 1999, there were miscellaneous
investments with carrying amounts of approximately $61 million and $60
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 CP&L's
long-term debt, including current maturities, was $3.6 billion and $3.2
billion at December 31, 2000 and 1999, respectively. The estimated fair
value of this debt, as obtained from quoted market prices for the same or
similar issues, was $3.6 billion and $3.2 billion at December 31, 2000 and
1999, respectively.
External funds have been established as a mechanism to fund certain costs
of nuclear decommissioning (See Note 1G). These nuclear decommissioning
trust funds are invested in stocks, bonds and cash equivalents. Nuclear
decommissioning trust funds are presented at amounts that approximate fair
value. Fair value is obtained from quoted market prices for the same or
similar investments.
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<PAGE>
8. Regulatory Matters
A. Regulatory Assets and Liabilities
As a regulated entity, CP&L is subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Accordingly,
CP&L records certain assets and liabilities resulting from the effects of
the ratemaking process, which would not be recorded under generally
accepted accounting principles for non-regulated entities. CP&L's ability
to continue to meet the criteria for application of SFAS No. 71 may be
affected in the future by competitive forces and restructuring in the
electric utility industry. In the event that SFAS No. 71 no longer applied
to a separable portion of CP&L's operations, related regulatory assets and
liabilities would be eliminated unless an appropriate regulatory recovery
mechanism 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".
At December 31, 2000 and 1999, the balances of the CP&L's regulatory assets
(liabilities) were as follows (in thousands):
2000 1999
---- ----
Income taxes recoverable through future rates* $210,571 $229,008
Harris Plant deferred costs 44,813 56,142
Loss on reacquired debt* - 4,719
Deferred fuel 119,853 81,699
Abandonment costs* - 1,675
Deferred DOE enrichment facilities-related costs 36,027 40,897
---------------------------------------------------------------------------
Total $411,264 $414,140
======== ========
* All or certain portions of these regulatory assets have been subject to
accelerated amortization (See Note 1F).
B. Retail Rate Matters
The NCUC and the 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 1F). 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 will allow CP&L to reduce the minimum accelerated
annual depreciation in 2001 through 2004 to $75 million. The resulting
total accelerated depreciation in 2000 was $275 million. 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 June 2000, CP&L filed a request with the NCUC seeking approval to defer
sulfur dioxide (SO2) emission allowance expenses, effective as of January
1, 2000, for recovery in a future general rate case proceeding or by such
other means as the NCUC may find appropriate. On January 5, 2001, the NCUC
issued an order authorizing CP&L to defer, effective January 1, 2000, the
cost of SO2 emission allowances purchased pursuant to the Clean Air Act.
CP&L is allowed to recover emission allowance expense through the fuel
clause adjustment in its South Carolina retail jurisdiction.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. Management is of the opinion that this agreement will not have a
material effect on CP&L's consolidated results of operations or financial
position.
In conjunction with the Company's merger with Florida Progress Corporation,
CP&L reached a settlement with the Public Staff of the NCUC in which it
agreed to reduce rates to all of its non-real time pricing customers by $3
million in 2002, $4.5 million in 2003, $6 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.
C. Plant-Related Deferred Costs
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<PAGE>
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 the 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 and $24.2 million in 1999 and 1998, respectively.
9. Risk Management Activities and Derivatives Transactions
CP&L 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. CP&L minimizes such risk by performing
credit reviews using, among other things, publicly available credit ratings
of such counterparties. Potential non-performance by counterparties is not
expected to have a material effect on the consolidated financial position
or consolidated results of operations of CP&L.
A. Commodity Derivatives - Non-Trading
CP&L 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 2000, 1999 and 1998,
CP&L principally sold electricity forward contracts, which can reduce price
risk on CP&L's available but unsold generation. While such contracts are
deemed to be economic hedges, CP&L 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
2000, 1999 and 1998. Also, CP&L did not have material outstanding positions
in such contracts at December 31, 2000 or 1999.
B. Commodity Derivatives - Trading
CP&L from time to time engages in the trading of electricity commodity
derivatives and, therefore, experiences net open positions. CP&L 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 CP&L did not have material outstanding
positions in such contracts at December 31, 2000 or 1999.
C. Other Derivative Instruments
CP&L may from time to time enter into derivative instruments to hedge
interest rate risk or equity securities risk.
CP&L 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, CP&L 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 $9.1 million
liability position at December 31, 2000. Interest rate swaps are accounted
for using the settlement basis of accounting. As such, payments or receipts
on interest rate swap agreements are recognized as adjustments to interest
expense.
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.
10. Capitalization
As of December 31, 2000 CP&L was authorized to issue up to 200,000,000
shares. All shares issued and outstanding are held by the Company effective
with the share exchange on June 19, 2000 (See Note 1A).
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2000,
there were no significant restrictions on the use of retained earnings.
11. Stock-Based Compensation Plans
A. Employee Stock Ownership Plan
CP&L sponsors the Stock Purchase-Savings Plan (SPSP) for which
substantially all full-time employees and certain
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part-time employees are eligible. The SPSP, which has matching and
incentive goal features, encourages systematic savings by employees and
provides a method of acquiring Progress Energy common stock and other
diverse investments. The SPSP, as amended in 1989, is an Employee Stock
Ownership Plan (ESOP) that can enter into acquisition loans to acquire
Progress Energy common stock to satisfy SPSP common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the SPSP. Common stock acquired with the proceeds of an
ESOP loan is held by the SPSP Trustee in a suspense account. The common
stock is released from the suspense account and made available for
allocation to participants as the ESOP loan is repaid. Such allocations are
used to partially meet common stock needs related to Progress Energy
matching and incentive contributions and/or reinvested dividends. 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 5,782,376 and 6,365,364 ESOP suspense shares at December 31,
2000 and 1999, respectively, with a fair value of $284.4 million and $193.7
million, respectively. ESOP shares allocated to plan participants totaled
13,549,257 and 12,966,269 at December 31, 2000 and 1999, respectively.
CP&L's matching and incentive goal compensation cost under the SPSP is
determined based on matching percentages and incentive goal attainment as
defined in the plan. Such compensation cost is allocated to participants'
accounts in the form of Progress Energy common stock, with the number of
shares determined by dividing compensation cost by the common stock market
value at the time of allocation. CP&L 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 $14.7 million, $16.3 million and
$15.3 million for the years ended December 31, 2000, 1999 and 1998,
respectively. CP&L has a long-term note receivable from the SPSP Trustee
related to the purchase of common stock from CP&L in 1989. The balance of
the note receivable from the SPSP Trustee is included in the determination
of unearned ESOP common stock, which reduces common stock equity. Interest
income on the note receivable is not recognized for financial statement
purposes.
B. Other Stock-Based Compensation Plans
CP&L has compensation plans for officers and key employees of CP&L that are
stock-based in whole or in part. The two primary active stock-based
compensation programs are the Performance Share Sub-Plan (PSSP) and the
Restricted Stock Awards program (RSA), both of which were established
pursuant to CP&L's 1997 Equity Incentive Plan.
Under the terms of the PSSP, officers and key employees of CP&L 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 Progress Energy's common stock, and dividend equivalents are
accrued on, and reinvested in, the performance shares. The PSSP has two
equally weighted performance measures, both of which are based on Progress
Energy's results as compared to a peer group of utilities. Compensation
expense is recognized over the vesting period based on the expected
ultimate cash payout. Compensation expense is reduced by any forfeitures.
The RSA, which began in 1998, allows CP&L to grant shares of restricted
common stock to key employees of CP&L. As a result of CP&L's reorganization
into a holding company structure, restricted common stock is common stock
of Progress Energy, Inc. (See Note 1A). 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 $34.14, $36.63 and $42.03 in 2000, 1999 and
1998, respectively. Compensation expense is reduced by any forfeitures.
Changes in CP&L's restricted stock shares outstanding were:
2000 1999 1998
---- ---- ----
Beginning balance 331,900 265,300 -
Granted 207,000 66,600 274,800
Transfers (256,700) - -
Forfeited (28,000) - (9,500)
----------------------------------------------------
Ending balance 254,200 331,900 265,300
====================================================
The transfers line item reflects the distribution of CP&L's ownership interest
in NCNG to the Company and the transfer of certain employees to PESC. The total
amount expensed for other stock-based compensation plans was
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$9.8 million, $2.2 million and $1.3 million in 2000, 1999 and 1998,
respectively. In addition to the balance of restricted stock reflected
above, at December 31, 2000, CP&L had purchased approximately $10.4 million
of restricted stock on behalf of affiliate companies, which is included in
unearned restricted stock awards in the consolidated schedules of
capitalization.
12. Postretirement Benefit Plans
CP&L and some of its subsidiaries have a non-contributory defined benefit
retirement (pension) plan for substantially all full-time employees. CP&L
also has a supplementary defined benefit pension plan that provides
benefits to higher-level employees.
The components of net periodic pension cost are (in thousands):
2000 1999 1998
-------- -------- --------
Expected return on plan assets $(76,508) $(75,124) $(69,920)
Service cost 18,804 20,467 18,357
Interest cost 49,821 46,846 45,877
Amortization of transition obligation 121 106 106
Amortization of prior service cost (benefit) (1,282) (1,314) (158)
Amortization of actuarial gain (5,607) (3,932) (6,440)
-------- -------- --------
Net periodic pension benefit $(14,651) $(12,951) $(12,178)
========= ========= =========
In addition to the net periodic benefit reflected above, in 2000 CP&L
recorded a charge of approximately $14.1 million to adjust its
supplementary defined benefit pension plan. The effect of the adjustment
for this plan is reflected in the actuarial loss (gain) line in the pension
obligation reconciliation below.
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the pension obligation
or the market-related value of assets are amortized over the average
remaining service period of active participants.
Reconciliations of the changes in the plan's benefit obligations and the
plan's funded status are (in thousands):
2000 1999
Pension obligation -------- ---------
Pension obligation at January 1 $ 688,124 $ 678,210
Interest cost 49,821 46,846
Service cost 18,804 20,467
Benefit payments (50,770) (41,585)
Actuarial loss (gain) 27,990 (50,120)
Plan amendments - 5,546
Acquisitions (transfers) (95,902) 28,760
-------- --------
Pension obligation at December 31 $ 638,067 $ 688,124
Fair value of plan assets at December 31 777,435 947,143
-------- --------
Funded status $ 139,368 $ 259,019
Unrecognized transition obligation 454 582
Unrecognized prior service benefit (15,355) (18,175)
Unrecognized actuarial gain (128,504) (245,343)
-------- --------
Prepaid (accrued) pension cost at December 31, net $ (4,037) $ (3,917)
========= ==========
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The net accrued pension cost of $4.0 million at December 31, 2000 is
recognized in the accompanying consolidated balance sheet as prepaid
pension cost of $10.4 million, which is included in other assets and
deferred debits, and accrued benefit cost of $14.4 million, which is
included in other liabilities and deferred credits. The accrued pension
cost at December 31, 1999 did not have prepaid components and, therefore,
is reflected in other liabilities and deferred credits. The aggregate
benefit obligation for the plan where the accumulated benefit obligation
exceeded the fair value of plan assets was $15.9 million at December 31,
2000, and the plan has no plan assets.
Reconciliations of the fair value of pension plan assets are (in
thousands):
2000 1999
--------- ---------
Fair value of plan assets at January 1 $947,143 $ 830,213
Actual return on plan assets (1,007) 127,167
Benefit payments (50,770) (41,585)
Employer contributions 1,160 -
Acquisitions (transfers) (119,091) 31,348
--------- ---------
Fair value of plan assets at December 31 $ 777,435 $ 947,143
========= =========
The weighted-average discount rate used to measure the pension obligation
was 7.5% in 2000 and 1999. The assumed rate of increase in future
compensation used to measure the pension obligation was 4.0% in 2000 and
4.2% in 1999. The expected long-term rate of return on pension plan assets
used in determining the net periodic pension cost was 9.25% in 2000, 1999
and 1998.
In addition to pension benefits, CP&L and some of its subsidiaries provide
contributory postretirement benefits (OPEB), including certain health care
and life insurance benefits, for retired employees who meet specified
criteria.
The components of net periodic OPEB cost are (in thousands):
2000 1999 1998
------- ------- -------
Expected return on plan assets $(3,852) $(3,378) $(3,092)
Service cost 8,868 7,936 7,182
Interest cost 13,677 13,914 13,402
Amortization of prior service cost 54 - -
Amortization of transition obligation 5,551 5,760 5,641
Amortization of actuarial gain (779) (1) (549)
------- ------- -------
Net periodic OPEB cost $23,519 $24,231 $22,584
======= ======= =======
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):
2000 1999
---- ----
OPEB obligation
OPEB obligation at January 1 $ 213,488 $196,846
Interest cost 13,677 13,914
Service cost 8,868 7,936
Benefit payments (6,425) (5,769)
Actuarial gain (14,739) (7,307)
Plan amendment - 1,062
Acquisitions (transfers) (27,306) 6,806
--------- ---------
OPEB obligation at December 31 $ 187,563 $ 213,488
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Fair value of plan assets at December 31 39,048 43,235
--------- ---------
Funded status $(148,515) $(170,253)
Unrecognized transition obligation 61,706 76,593
Unrecognized prior service cost - 1,062
Unrecognized actuarial gain (25,600) (17,261)
--------- ---------
Accrued OPEB cost at December 31 $(112,409) $(109,859)
========= =========
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2000 1999
---- ----
Fair value of plan assets at January 1 $43,235 $37,304
Actual return on plan assets (191) 5,931
Transfers (3,996) -
Employer contribution 6,425 5,769
Benefits paid (6,425) (5,769)
-------- --------
Fair value of plan assets at December 31 $39,048 $43,235
======== ========
The assumptions used to measure the OPEB obligation are:
2000 1999
---- ----
Weighted-average discount rate 7.50% 7.50%
Initial medical cost trend rate for
pre-Medicare benefits 7.50% 7.50%
Initial medical cost trend rate for
post-Medicare benefits 7.50% 7.25%
Ultimate medical cost trend rate 5.00% 5.00%
Year ultimate medical cost trend rate is achieved 2007 2006
The expected weighted-average long-term rate of return on plan assets used
in determining the net periodic OPEB cost was 9.25% in 2000, 1999 and 1998.
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 2000 would increase by $3.9 million, and
the OPEB obligation at December 31, 2000, would increase by $20.8 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for
2000 would decrease by $3.3 million and the OPEB obligation at December 31,
2000, would decrease by $18.8 million.
During 1999, CP&L completed the acquisition of NCNG. Effective January 1,
2000, NCNG's benefit plans were merged with those of CP&L. On July 1, 2000,
CP&L distributed its ownership interest in the stock of NCNG to the
Company. In addition, on August 1, 2000, the Company established Progress
Energy Service Company, LLC. The effects of the acquisition of NCNG, the
transfer of ownership interest in NCNG and the transfer of employees to
Progress Energy Service Company, LLC are reflected as appropriate in the
pension and OPEB liabilities, assets and net periodic costs presented
above.
13. 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>
Net accumulated deferred income tax liabilities at December 31 are (in
thousands):
2000 1999
---- ----
Accelerated depreciation and property
cost differences $ 1,474,167 $ 1,583,610
Deferred costs, net 51,549 70,478
Miscellaneous other temporary differences, net 30,749 26,403
------------ -----------
Net accumulated deferred income tax liability $ 1,556,465 $ 1,680,491
============ ===========
Total deferred income tax liabilities were $2.12 billion and $2.20 billion
at December 31, 2000 and 1999, respectively. Total deferred income tax
assets were $559 million and $519 million at December 31, 2000 and 1999,
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.
Reconciliations of CP&L's effective income tax rate to the statutory
federal income tax rate are:
2000 1999 1998
----- ----- -----
Effective income tax rate 38.6% 40.3% 39.2%
Nuclear accelerated depreciation (1.9) - -
State income taxes, net of federal benefit (4.5) (4.6) (4.7)
Synthetic fuel income tax credits 1.6 - -
Investment tax credit amortization 3.7 1.6 1.5
Other differences, net (2.5) (2.3) (1.0)
----- ------ -----
Statutory federal income tax rate 35.0% 35.0% 35.0%
===== ====== =====
The provisions for income tax expense are comprised of (in thousands):
2000 1999 1998
--------- --------- ----------
Income tax expense (credit):
Current - federal $ 328,982 $ 253,140 $ 254,400
state 62,228 48,075 51,817
Deferred - federal (71,929) (30,011) (34,842)
state (11,625) (2,484) (3,675)
Investment tax credit (17,385) (10,299) (10,206)
--------- --------- ----------
Total income tax expense $ 290,271 $ 258,421 $ 257,494
========= ========= ==========
14. Joint Ownership of Generating Facilities
CP&L holds undivided ownership interests in certain jointly owned
generating facilities, excluding related nuclear fuel and inventories. CP&L
is entitled to shares of the generating capability and output of each unit
equal to their respective ownership interests. CP&L also pays its ownership
share of additional construction costs, fuel inventory purchases and
operating expenses. CP&L's share of expenses for the jointly owned
facilities is included in the appropriate expense category.
CP&L's ownership interest in the jointly owned generating facilities is
listed below with related information as of December 31, 2000 (dollars in
thousands):
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<TABLE>
<CAPTION>
Company
Megawatt Ownership Plant Accumulated Under
Facility Capability Interest Investment Depreciation Construction
- - - - - - -------- ---------- -------- ----------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Mayo Plant 745 83.83% $ 451,769 $ 218,029 $ 12,248
Harris Plant 860 83.83% 3,026,074 1,255,008 71,250
Brunswick Plant 1,631 81.67% 1,422,640 1,121,880 12,555
Roxboro Unit No. 4 700 87.06% 242,605 122,651 57,190
</TABLE>
In the table above, plant investment and accumulated depreciation, which
includes accumulated nuclear decommissioning, are not reduced by the
regulatory disallowances related to the Harris Plant.
15. Commitments and Contingencies
A. 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 $33.9 million, $36.5 million and $34.4
million for 2000, 1999 and 1998, respectively. In 1987, the NCUC ordered
CP&L to reflect the recovery of the capacity portion of these costs on a
levelized basis over the original 15-year buyback period, thereby deferring
for future recovery the difference between such costs and amounts collected
through rates. In 1988, the SCPSC ordered similar treatment, but with a
10-year levelization period. At December 31, 2000 and 1999, CP&L had
deferred purchased capacity costs, including carrying costs accrued on the
deferred balances, of $44.8 million and $56.1 million, respectively.
Increased purchases (which are not being deferred for future recovery)
resulting from the 1993 agreement with Power Agency were approximately $26
million, $23 million and $19 million for 2000, 1999 and 1998, respectively.
During 2000, CP&L had 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 an estimated minimum annual
payment of approximately $31 million, representing capital-related capacity
costs. Total purchases (including transmission use charges) under the
Rockport agreement amounted to $61 million, $59.2 million and $59.3 million
for 2000, 1999 and 1998, respectively. During 1998 and part of 1999, CP&L
had an additional long-term agreement to purchase power and related
transmission services from Duke Energy. Total purchases under this
agreement amounted to $33.8 million and $75.5 million for 1999 and 1998,
respectively.
B. Insurance
CP&L is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, CP&L is
insured for $500 million at each of its nuclear plants. In addition to
primary coverage, NEIL also provides decontamination, premature
decommissioning and excess property insurance with limits of $1.0 billion
on the Brunswick Plant, $1.0 billion on the Harris Plant and $800 million
on the Robinson Plant. An additional shared limit policy of $1 billion in
excess of $1 billion is also provided through NEIL on the Brunswick and
Harris Plants for decontamination, premature decommissioning and excess
property.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. CP&L is insured thereunder, following
a twelve week deductible period, for 52 weeks in weekly amounts of $2.25
million at Brunswick Unit No. 1, $2.25 million at Brunswick Unit No. 2,
$2.4 million at the Harris Plant and $1.96 million at Robinson Unit No. 2.
An additional 104 weeks of coverage is provided at 80% of the above weekly
amounts. For the current policy period, CP&L is subject to retrospective
premium assessments of up to approximately $13.5 million with respect to
the primary coverage, $15.4 million with respect to the decontamination,
decommissioning and excess property coverage, $2.6 million with respect to
the shared limit excess coverage and $7.1 million for the incremental
replacement power costs coverage, in the event covered expenses at insured
facilities exceed premiums, reserves, reinsurance and other NEIL resources.
These resources as of December 31, 2000 totaled approximately $4.6 billion.
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Pursuant to regulations of the Nuclear Regulatory Commission, CP&L's
property damage insurance policies provide that all proceeds from such
insurance be applied, first, to place the plant in a safe and stable
condition after an accident and, second, to decontamination costs, before
any proceeds can be used for decommissioning, plant repair or restoration.
CP&L is responsible to the extent losses may exceed limits of the coverage
described above.
CP&L is insured against public liability for a nuclear incident up to $9.54
billion per occurrence. In the event that public liability claims from an
insured nuclear incident exceed $200 million, CP&L would be subject to a
pro rata assessment of up to $83.9 million for each reactor owned per
occurrence. Payment of such assessment would be made over time as necessary
to limit the payment in any one year to no more than $10 million per
reactor owned.
C. Claims and Uncertainties
1. CP&L 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 CP&L has some connection. In this regard, CP&L, 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) and the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM). Although CP&L may incur
costs at these sites about which it has been notified, based upon current
status of these sites, CP&L does not expect those costs to be material to
its consolidated financial position or results of operations.
CP&L is periodically notified by regulators such as the EPA and various
state agencies of their involvement or potential involvement in sites,
other than MGP sites, that may require investigation and/or remediation.
Although CP&L may incur costs at the sites about which they have been
notified, based upon the current status of these sites, CP&L does not
expect those costs to be material to its consolidated financial position or
results of operations.
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.
CP&L has recently been asked to provide information to the EPA as part of
this initiative and has cooperated in providing the requested information.
The EPA has initiated enforcement actions against other 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. 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. CP&L 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 and South Carolina,
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. Increased operation and maintenance costs relating
to the NOx SIP Call are not expected to be material to CP&L's results of
operations. Further controls are anticipated as electricity demand
increases. CP&L cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new
eight-hour ozone standard. In October 1999, the District of Columbia
Circuit Court of Appeals ruled against the EPA with regard to the federal
eight-hour ozone standard. The U.S. Supreme Court has upheld, in part, the
District of Columbia Circuit Court of Appeals decision. 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 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
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<PAGE>
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 are participating in litigation challenging
the EPA's action. CP&L cannot predict the outcome of this matter.
CP&L has filed claims with its general liability insurance carriers to
recover costs arising out of actual or potential environmental liabilities.
Some claims have settled and others are still pending. While management
cannot predict the outcome of these matters, the outcome is not expected to
have a material effect on the consolidated financial position or results of
operations.
2. As required under the Nuclear Waste Policy Act of 1982, CP&L entered
into a contract with the DOE under which the DOE agreed to begin taking
spent nuclear fuel by no later than January 31, 1998. All similarly
situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
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 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 is in the process of evaluating whether they should file a
similar action for damages.
CP&L also continues to monitor legislation that has been introduced in
Congress which might provide some limited relief. CP&L cannot predict the
outcome of this matter.
With certain modifications and additional approval by the NRC, CP&L's spent
nuclear fuel storage facilities will be sufficient to provide storage space
for spent fuel generated on its system through the expiration of the
current operating licenses for all of its nuclear generating units.
Subsequent to the expiration of these licenses, dry storage may be
necessary. CP&L obtained NRC approval to use additional storage space at
the Harris Plant in December 2000.
3. CP&L is involved in various litigation matters in the ordinary course of
business, some of which involve substantial amounts. Where appropriate,
accruals have been made in accordance with SFAS No. 5, "Accounting for
Contingencies," to provide for such matters. In the opinion of management,
the final disposition of pending litigation would not have a material
adverse effect on CP&L's consolidated results of operations or financial
position.
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PROGRESS ENERGY, INC.
Schedule II - Valuation and Qualifying Accounts
For the Years Ended December 31, 2000, 1999, and 1998
<TABLE>
<CAPTION>
Balance at Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Additions Deductions Period
- - - - - - ---------------------------- --------------- ------------------ ------------------- ---------------------- ----------------------
<S> <C> <C> <C> <C> <C>
Year Ended
December 31, 2000
Uncollectible accounts $16,809,765 $14,387,547 $ 8,254,368 a. $(11,335,875) b. $28,115,805
Nuclear refueling
outage reserve - $ 884,000 $ 10,592,000 a. $ (640,000) $10,836,000
--------------- -------------- ---------------- ------------------ ------------------
$16,809,765 $15,271,547 $ 18,846,368 $(11,975,875) $38,951,805
=============== ============== ================ ================== ==================
Year Ended
December 31, 1999
Uncollectible accounts $14,226,931 $ 6,966,304 $ 2,607,368 c. $ (6,990,838) b. $16,809,765
=============== ============== ================ ================== ==================
Year Ended
December 31, 1998
Uncollectible accounts $ 3,366,361 $17,993,081 $ - $ (7,132,511) b. $14,226,931
=============== ============== ================ ================== ==================
</TABLE>
a. Represents acquisition of FPC on November 30, 2000.
b. Represents write-off of uncollectible accounts, net of recoveries.
c. Represents acquisition of NCNG on July 15, 1999.
106
<PAGE>
CAROLINA POWER & LIGHT COMPANY
Schedule II - Valuation and Qualifying Accounts
For the Years Ended December 31, 2000, 1999, and 1998
<TABLE>
<CAPTION>
Balance at Charged to Balance at
Beginning Costs and End of
Description of Period Expenses Other Additions Deductions Period
- - - - - - ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Year Ended
December 31, 2000
Uncollectible accounts $16,809,765 $12,450,000 $ - $(12,283,672) a. $16,976,093
================= =============== =============== ================= ================
Year Ended
December 31, 1999
Uncollectible accounts $14,226,931 $6,966,304 $ 2,607,368 b. $(6,990,838) c. $16,809,765
================= =============== =============== ================= ================
Year Ended
December 31, 1998
Uncollectible accounts $3,366,361 $17,993,081 $ - $(7,132,511) c. $14,226,931
================= =============== =============== ================= ================
</TABLE>
a. Represents transfer of uncollectible account balances for SRS, NCNG, Monroe
Power and Energy Ventures to Progress Energy on July 1, 2000 of $2,846,873
as well as write-off of uncollectible accounts, net of recoveries of
$9,436,799.
b. Represents acquisition of NCNG on July 15, 1999.
c. Represents write-off of uncollectible accounts, net of recoveries.
107
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
- - - - - - -------------------------------------------------------------------------
FINANCIAL DISCLOSURE
- - - - - - --------------------
As a result of the acquisition of Florida Progress Corporation (FPC)
and Florida Power Corporation (Florida Power) by Progress Energy, Inc.
(Progress Energy), management decided to retain Deloitte & Touche LLP
(D&T) as its independent public accountants. D&T has served as the
independent public accountants for Progress Energy for over fifty
years. On March 21, 2001, the Audit Committee of the Board of Directors
approved this recommendation and formally elected to (i) engage D&T as
the independent accountants for FPC and Florida Power and (ii) dismiss
KPMG LLP (KPMG) as such independent accountants.
KPMG's reports on FPC's and Florida Power's financial statements for
2000 and 1999 (the last two fiscal years of KPMG's engagement)
contained no adverse opinion or a disclaimer of opinion, and were not
qualified or modified as to uncertainty, audit scope or accounting
principles. D&T became FPC's and Florida Power's independent
accountants upon the completion of the 2000 audit and issuance of the
related financial statements.
During FPC's and Florida Power's last two fiscal years and the
subsequent interim period to the date hereof, there were no
disagreements between FPC and Florida Power and KPMG on any matter of
accounting principles or practices, financial statement disclosure, or
auditing scope or procedure, which disagreements, if not resolved to
the satisfaction of KPMG, would have caused them to make reference to
the subject matter of the disagreements in connection with their report
on the financial statements for such years.
Progress Energy has requested KPMG to furnish it, as promptly as
possible, with a letter addressed to the Securities and Exchange
Commission stating whether it agrees with the above statements made by
Progress Energy in this Form 10-K. A copy of such letter, dated March
28, 2001 is filed as an Exhibit to this Form 10-K.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
- - - - - - -------- --------------------------------------------------
a) Information on Progress Energy, Inc.'s directors is set forth
in the Progress Energy 2000 definitive proxy statement dated
April 2, 2001, and incorporated by reference herein.
Information on Carolina Power & Light Company's directors is
set forth in the CP&L 2000 definitive proxy statement dated
April 2, 2001, and incorporated by reference herein.
b) Information on both Progress Energy's and CP&L's executive
officers is set forth in PART I and incorporated by reference
herein.
ITEM 11. EXECUTIVE COMPENSATION
- - - - - - -------- ----------------------
Information on Progress Energy, Inc.'s executive compensation is set
forth in the Progress Energy 2000 definitive proxy statement dated
April 2, 2001, and incorporated by reference herein. Information on
Carolina Power & Light Company's executive compensation is set forth
in the CP&L 2000 definitive proxy statement dated April 2, 2001, and
incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- - - - - - -------- --------------------------------------------------------------
a) Progress Energy knows of no person who is a beneficial owner
of more than five (5%) percent of any class of the Company's
voting securities.
b) Information on security ownership of the Progress Energy's and
Carolina Power & Light Company's management is set forth in
the Progress Energy and Carolina Power & Light Company 2000
definitive proxy statements dated April 2, 2001, and
incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- - - - - - -------- ----------------------------------------------
Information on certain relationships and related transactions is set
forth in the Progress Energy and CP&L 2000 definitive proxy statement
dated April 2, 2001, and incorporated by reference herein.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
- - - - - - -------- -----------------------------------------------------------------
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data.
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data
3. Exhibits Filed:
---------------
See EXHIBIT INDEX
b) Reports on Form 8-K filed during or with respect to the last
quarter of 2000 and the portion of the first quarter of 2001
prior to the filing of this Form 10-K:
108
<PAGE>
Progress Energy, Inc.
---------------------
1. Current Report on Form 8-K dated October 31, 2000
2. Current Report on Form 8-K dated December 1, 2000
3. Current Report on Form 8-K dated December 4, 2000
4. Current Report on Form 8-K dated January 23, 2001
5. Current Report on Form 8-K dated January 24, 2001
6. Current Report on Form 8-K dated February 27, 2001
7. Current Report on Form 8-K dated March 16, 2001
Carolina Power & Light Company
------------------------------
1. Current Report on Form 8-K dated October 31, 2000
2. Current Report on Form 8-K dated December 1, 2000
109
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY
------------------------------
Date: March 28, 2001 (Registrants)
--------------
By: /s/Peter M. Scott III
---------------------
Executive Vice President and
Chief Financial Officer
By: /s/Robert H. Bazemore, Jr.
--------------------------
Vice President and Controller
(Chief Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
- - - - - - --------- ----- ----
/s/ William Cavanaugh III Principal Executive March 21, 2001
- - - - - - -------------------------- Officer and Director
(William Cavanaugh III,
Chairman, President and Chief
Executive Officer)
/s/ Peter M. Scott III Principal Financial March 21, 2001
- - - - - - ----------------------- Officer
(Peter M. Scott, Executive
Vice President and Chief
Chief Financial Officer)
/s/ Edwin B. Borden Director March 21, 2001
- - - - - - --------------------
(Edwin B. Borden)
/s/ David L. Burner Director March 21, 2001
- - - - - - --------------------
(David L. Burner)
/s/ Charles W. Coker Director March 21, 2001
- - - - - - ---------------------
(Charles W. Coker)
/s/ Richard L. Daugherty Director March 21, 2001
- - - - - - -------------------------
(Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 21, 2001
- - - - - - ------------------------
(W.D. Frederick, Jr.)
/s/ Richard Korpan Director March 21, 2001
- - - - - - -------------------
(Richard Korpan)
110
<PAGE>
/s/ Estell C. Lee Director March 21, 2001
- - - - - - ------------------
(Estell C. Lee)
/s/ William O. McCoy Director March 21, 2001
- - - - - - ---------------------
(William O. McCoy)
/s/ E. Marie McKee Director March 21, 2001
- - - - - - -------------------
(E. Marie McKee)
/s/ John H. Mullin, III Director March 21, 2001
- - - - - - ------------------------
(John H. Mullin, III)
/s/ Richard A. Nunis Director March 21, 2001
- - - - - - ---------------------
(Richard A. Nunis)
/s/ J. Tylee Wilson Director March 21, 2001
- - - - - - --------------------
(J. Tylee Wilson)
/s/ Jean Giles Wittner Director March 21, 2001
- - - - - - -----------------------
(Jean Giles Wittner)
111
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Progress
Number Exhibit Energy, Inc. CP&L
------------ ----
<S> <C> <C> <C>
*2(a) Agreement and Plan of Merger By and Among Carolina Power & Light X
Company, North Carolina Natural Gas Corporation and Carolina
Acquisition Corporation, dated as of November 10, 1998 (filed as
Exhibit No. 2(b) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1998, File No. 1-3382.)
*2(b) Agreement and Plan of Merger by and among Carolina Power & Light X
Company, North Carolina Natural Gas Corporation and Carolina
Acquisition Corporation, Dated as of November 10, 1998, as
Amended and Restated as of April 22, 1999 (filed as Exhibit 2 to
Quarterly Report on Form 10-Q for the quarterly period ended
March 31, 1999, File No. 1-3382).
*2(c) Agreement and Plan of Exchange, dated as of August 22, 1999, by X X
and among Carolina Power & Light Company, Florida Progress
Corporation and CP&L Holdings, Inc. (filed as Exhibit 2.1 to
Current Report on Form 8-K dated August 22, 1999, File No.
1-3382).
*2(d) Amended and Restated Agreement and Plan of Exchange, by and X X
among Carolina Power & Light Company, Florida Progress
Corporation and CP&L Energy, Inc., dated as of August 22, 1999,
amended and restated as of March 3, 2000 (filed as Annex A to
Joint Preliminary Proxy Statement of Carolina Power & Light
Company and Florida Progress Corporation dated March 6, 2000,
File No. 1-3382).
*3a(1) Restated Charter of Carolina Power & Light Company, as X
amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
*3a(2) Restated Charter of Carolina Power & Light Company as X
amended on May 10, 1996 (filed as Exhibit No. 3(i) to Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1997, File No. 1-3382).
*3a(3) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on June 15, 2000 (filed as
Exhibit No. 3a(1) to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 2000, File No. 1-15929 and No.
1-3382).
*3b(1) By-Laws of Carolina Power & Light Company, as amended May 10, X
1995 (filed as Exhibit No. 3(ii) to Quarterly Report on Form
10-Q for the quarterly period ended June 30, 1995, File No.
1-3382).
</TABLE>
112
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
*3b(2) By-Laws of Carolina Power & Light Company, as amended on X
September 18, 1996 (filed as Exhibit 3(ii) to Quarterly Report
on Form 10-Q for the quarterly period ended June 30, 1997, File
No.1-3382).
*3b(3) By-Laws of Carolina Power & Light Company, as amended on March X
17, 1999 (filed as Exhibit No. 3b(3) to Annual Report on Form
10-K for the fiscal year ended December 31, 1998, File No.
1-3382).
*3b(4) By-Laws of CP&L Energy, Inc., as amended and restated X
June 15, 2000 (filed as Exhibit No. 3b(1) to Quarterly Report of
Form 10-Q for the quarterly period ended June 30, 2000, File No.
1-15929 and No. 1-3382).
*3b(5) By-Laws of Carolina Power & Light Company, as amended on July