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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
------ ------
Exact name of registrants as specified in their
Commission charters, state of incorporation, address of principal I.R.S. Employer
File Number executive offices, and telephone number Identification Number
1-15929 Progress Energy, Inc. 56-2155481
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
1-3382 Carolina Power & Light Company 56-0165465
d/b/a Progress Energy Carolinas, Inc.
410 South Wilmington Street
Raleigh, North Carolina 27601-1748
Telephone: (919) 546-6111
State of Incorporation: North Carolina
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
Progress Energy, Inc.:
Common Stock (Without Par Value) New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Progress Energy, Inc.: None
Carolina Power & Light Company: $100 par value Preferred Stock, Cumulative
$100 par value Serial Preferred Stock, Cumulative
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]
Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as
defined in Rule 12b-2 of the Act).
Yes X . No .
---------- ----------
Indicate by check mark whether Carolina Power & Light Company is an accelerated
filer (as defined in Rule 12b-2 of the Act).
Yes . No X .
------------ ----------
As of June 30, 2002, the aggregate market value of the voting and non-voting
common equity of Progress Energy, Inc. held by non-affiliates was
$11,466,869,123. As of June 30, 2002, the aggregate market value of the common
equity of Carolina Power & Light Company held by non-affiliates was $0. All of
the common stock of Carolina Power & Light Company is owned by Progress Energy,
Inc.
1
As of February 28, 2003, each registrant had the following shares of common
stock outstanding:
Registrant Description Shares
---------- ----------- ------
Progress Energy, Inc. Common Stock (Without Par Value) 239,172,863
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Progress Energy and CP&L definitive proxy statements dated March
31, 2003 are incorporated into PART III, ITEMS 10, 11, 12 and 13 hereof.
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.
2
TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
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
ITEM 14. CONTROLS AND PROCEDURES
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
PROGRESS ENERGY, INC. RISK FACTORS
CAROLINA POWER & LIGHT COMPANY RISK FACTORS
3
GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-K are defined below:
TERM DEFINITION
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement
APEC Albemarle Pamlico Economic Development Corporation
Bain Capital Bain Capital, Inc. and affiliates
Bcf Billion cubic feet
BellSouth Carolinas PCS BellSouth Carolinas, PCS L.P.
Btu British thermal units
Caronet Caronet, Inc.
CERCLA or Superfund Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended
Code Internal Revenue Service Code
Colona Colona Synfuel Limited Partnership, L.L.L.P.
the Company Progress Energy, Inc. and subsidiaries
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
DOE United States Department of Energy
dt Dekatherm
DWM North Carolina Department of Environment and Natural
Resources, Division of Waste Management
EBITDA Earning before interest, taxes, and depreciation and
amortization
ENCNG Eastern North Carolina Natural Gas Company, formerly
referred to as EasternNC
EITF Emerging Issues Task Force
EITF Issue 02-03 EITF Issue 02-03, "Accounting for Contracts Involved
in Energy Trading and Risk Management Activities"
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
FDEP Florida Department of Environment and Protection
Financial Statements Progress Energy Financial Statements, for the year
ended December 31, 2002 contained under ITEM 8 herein
FIN No. 45 FASB Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an
Interpretation of FASB Statements No. 5, 57 and 107
and Rescission of FASB Interpretation No. 34"
FIN No. 46 FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of
ARB No. 51"
Florida Power Florida Power Corporation
Florida Progress or FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Funding Corp. Florida Progress Funding Corporation
Georgia Power Georgia Power Company
Harris Plant Shearon Harris Nuclear Plant
Interpath Interpath Communications, Inc.
IBEW International Brotherhood of Electrical Workers
IRS Internal Revenue Service
ISO Independent System Operator
KWh Kilowatt-hour
kV Kilovolt
kVA Kilovolt-ampere
LIBOR London Inter Bank Offering Rate
LSEs Load-serving entities
MDC Maximum Dependable Capability
4
MGP Manufactured Gas Plant
Monroe Power Monroe Power Company
MW Megawatt
MWh Megawatt-hour
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 Postretirement benefits other than pensions
the Plan Revenue Sharing Incentive Plan
PLR Private Letter Ruling
Pollution control bonds Pollution control revenue refunding bonds
Power Agency North Carolina Eastern Municipal Power Agency
PCH Progress Capital Holdings, Inc.
Progress Energy Progress Energy, Inc.
Progress Fuels Progress Fuels Corporation, formerly Electric Fuels
Corporation
Progress Rail Progress Rail Services Corporation
Progress Telecom Progress Telecommunications Corporation
Progress Ventures Business segment of Progress Energy
primarily made up of merchant energy generation,
coal and synthetic fuel operations and energy
marketing and trading, formerly referred to as
Energy Ventures
Preferred Securities FPC-obligated mandatorily redeemable preferred
securities of FPC Capital I
PRP Potentially responsible party, as defined in CERCLA
PSSP Performance Share Sub-Plan
PUHCA Public Utility Holding Company Act of 1935, as
amended
PURPA Public Utilities Regulatory Policies Act of 1978
PVI Legal entity of Progress Ventures, Inc. (formerly
referred to as CPL Energy Ventures, Inc.)
PWR Pressurized water reactor
QF Qualifying facilities
RSA Restricted Stock Awards program
RTO Regional Transmission Organization
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
SFAS No. 4 Statement of Financial Accounting Standards No. 4,
"Reporting Gains and Losses from Extinguishment of
Debt (an amendment of Accounting Principles Board
(APB) Opinion No. 30)"
SFAS No. 5 Statement of Financial Accounting Standards No. 5,
"Accounting for Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of
Regulation"
SFAS No. 87 Statement of Financial Accounting Standards No. 87,
"Employers' Accounting for Pensions"
SFAS No. 106 Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits
Other Than Pensions"
SFAS No. 121 Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of"
SFAS No. 123 Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation"
SFAS No. 133 Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative and Hedging Activities"
SFAS No. 138 Statement of Financial Accounting Standards No. 138,
"Accounting for Certain Derivative Instruments and
Certain Hedging Activities - an Amendment of FASB
Statement No. 133"
SFAS No. 142 Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangible Assets"
SFAS No. 143 Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations"
5
SFAS No. 144 Statement of Financial Accounting Standards No. 144,
"Accounting for the Impairment or Disposal of Long-
Lived Assets"
SFAS No. 145 Statement of Financial Accounting Standards No. 145,
"Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13 and Technical
Corrections"
SFAS No. 148 Statement of Financial Accounting Standards No. 148,
"Accounting for Stock-Based Compensation - Transition
and Disclosure - An Amendment of FASB Statement
No. 123"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-
000, Remedying Undue Discrimination through Open
Access Transmission and Standard Market Design
SO2 Sulfur dioxide
SRS Strategic Resource Solutions Corp.
Transco Transcontinental Gas Pipeline Corporation
the Trust FPC Capital I
6
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
In addition, examples of forward-looking statements discussed in this Form 10-K,
include a) PART II, ITEM 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" including, but not limited to, statements
under the following headings: 1) "Liquidity and Capital Resources" about
operating cash flows, estimated capital requirements through the year 2005 and
future financing plans, 2) "Future Outlook" about Progress Energy's future
earnings potential, and 3) "Other Matters" about the effects of new
environmental regulations, nuclear decommissioning costs and the effect of
electric utility industry restructuring, and b) statements made in the "Risk
Factors" sections.
Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy nor CP&L undertakes any obligation to
update any forward-looking statement or statements to reflect events or
circumstances after the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; the impact of recent events in the
energy markets that have increased the level of public and regulatory scrutiny
in the energy industry and in the capital markets; deregulation or restructuring
in the electric industry that may result in increased competition and
unrecovered (stranded) costs; the uncertainty regarding the timing, creation and
structure of regional transmission organizations; weather conditions that
directly influence the demand for electricity and natural gas; recurring
seasonal fluctuations in demand for electricity and natural gas; fluctuations in
the price of energy commodities and purchased power; economic fluctuations and
the corresponding impact on the Company's commercial and industrial customers;
the ability of the Company's subsidiaries to pay upstream dividends or
distributions to it; the impact on the facilities and the businesses of the
Company from a terrorist attack; the inherent risks associated with the
operation of nuclear facilities, including environmental, health, regulatory and
financial risks; the ability to successfully access capital markets on favorable
terms; the impact that increases in leverage may have on the Company; the
ability of the Company to maintain its current credit ratings; the impact of
derivative contracts used in the normal course of business by the Company; the
Company's continued ability to use Section 29 tax credits related to its coal
and synthetic fuels businesses; the continued depressed state of the
telecommunications industry and the Company's ability to realize future returns
from Progress Telecommunications Corporation and Caronet, Inc.; the Company's
ability to successfully integrate newly acquired assets, properties or
businesses into its operations as quickly or as profitably as expected; the
Company's ability to successfully complete the sale of North Carolina Natural
Gas and apply the proceeds therefrom to reduce outstanding indebtedness; the
Company's ability to manage the risks involved with the construction and
operation of its nonregulated plants, including construction delays, dependence
on third parties and related counter-party risks, and a lack of operating
history; the Company's ability to manage the risks associated with its energy
marketing and trading operations; and unanticipated changes in operating
expenses and capital expenditures. Many of these risks similarly impact the
Company's subsidiaries.
These and other risk factors are detailed from time to time in the Company's SEC
reports. Many, but not all of the factors that may impact actual results are
discussed in the "Risk Factors" sections of this report. You should carefully
read the "Risk Factors" sections of this report. All such factors are difficult
to predict, contain uncertainties that may materially affect actual results, and
may be beyond the control of Progress Energy and CP&L. New factors emerge from
time to time, and it is not possible for management to predict all such factors,
nor can it assess the effect of each such factor on Progress Energy and CP&L.
7
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 incorporated on August 19, 1999. The Company was initially
formed as CP&L Energy, Inc. (CP&L Energy), which became the holding company for
Carolina Power & Light Company (CP&L) on June 19, 2000. All shares of common
stock of CP&L were exchanged for an equal number of shares of CP&L Energy common
stock.
On July 1, 2000, CP&L distributed its ownership interest in the stock of North
Carolina Natural Gas Corporation (NCNG), Strategic Resource Solutions Corp.
(SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc. (PVI) 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 or financial
position since that date.
Subsequent to the acquisition of Florida Progress Corporation (FPC or Florida
Progress) (see "Significant Transactions" below), the Company changed its name
from CP&L Energy to Progress Energy, Inc. on December 4, 2000.
Through its wholly owned regulated subsidiaries, CP&L, Florida Power Corporation
(Florida Power) and NCNG, Progress Energy is primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida; and the transportation, distribution
and sale of natural gas in portions of North Carolina. Through the Progress
Ventures business segment, Progress Energy is involved in nonregulated
generation operations; natural gas exploration and production; coal fuel
extraction, manufacturing and delivery; and energy marketing and trading
activities. Through the Rail Services business segment, Progress Energy engages
in various rail and railcar related services. Through other business units,
Progress Energy engages in other nonregulated business areas including
telecommunications and holding company operations.
Effective January 1, 2003, CP&L, Florida Power and PVI began doing business
under the names Progress Energy Carolinas, Inc., Progress Energy Florida, Inc.
and Progress Energy Ventures, Inc., respectively. The legal names of these
entities have not changed and there is no restructuring of any kind related to
the name change. The current corporate and business unit structure remains
unchanged.
Progress Energy is an integrated energy company located principally in the
southeast region of the United States. The Company has more than 21,900
megawatts (MW) of electric generation capacity and serves approximately 3.0
million electric and natural gas customers in portions of North Carolina, South
Carolina and Florida. CP&L's and Florida Power's utility operations are
complementary: CP&L has a summer peaking demand, while Florida Power has a
winter peaking demand. In addition, CP&L's greater proportion of commercial and
industrial customers combined with Florida Power's greater proportion of
residential customers creates a more balanced customer base. The Company is
dedicated to expanding the region's electric generation capacity and delivering
reliable, competitively priced energy.
Progress Energy revenues for the year ended December 31, 2002 were $7.9 billion,
and assets at year-end were $21.4 billion. Its principal executive offices are
located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone
number (919) 546-6111. The Progress Energy home page on the Internet is located
at http://www.progress-energy.com, the contents of which are not and shall not
be deemed a part of this document or any other U.S. Securities and Exchange
Commission (SEC) filing. The Company makes available free of charge on its
website its annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed or furnished to the SEC.
The operations of Progress Energy and its subsidiaries are divided into five
major segments: two electric utilities (CP&L and Florida Power), Progress
Ventures, Rail Services and Other. Progress Energy's legal structure is not
currently aligned with the functional management and financial reporting of its
segments. Whether, and when, the legal and functional structures will converge
depends upon legislative and regulatory action, which cannot currently be
anticipated. The Other segment primarily includes telecommunication services,
miscellaneous nonregulated activities, holding company operations and
elimination entries. For information regarding the revenues, income and assets
attributable to the Company's business segments, see PART II, ITEM 8, Note 4 to
the Progress Energy consolidated financial statements.
8
SIGNIFICANT TRANSACTIONS
Generation Acquisition
On February 15, 2002, PVI completed the acquisition of two electric generating
projects totaling nearly 1,100 MW in capacity in Georgia and related tolling and
power sale agreements from LG&E Energy Corp. for a total cash purchase price of
approximately $350 million including direct transaction costs. The two projects
consist of 1) the Walton project in Monroe, Georgia, a 460 MW natural gas-fired
plant placed in service in June 2001 and 2) the Washington project in Washington
County, Georgia, a planned 600 MW natural gas-fired plant expected to be
operational by June 2003. The transaction included a power purchase agreement
with LG&E Marketing, Inc. for both projects through December 31, 2004. In
addition, there is a project management and completion agreement whereby LG&E
Energy Corp. has agreed to manage the completion of the Washington site
construction for PVI in exchange for cash consideration of $181 million. The
estimated costs to complete the Washington project as of December 31, 2002 are
approximately $57.8 million. See PART II, ITEM 8, Note 2A to the Progress Energy
consolidated financial statements for additional discussion of this transaction.
Westchester Gas Company Acquisition
On April 26, 2002, Progress Fuels Corporation (Progress Fuels), a wholly owned
subsidiary of Progress Energy, completed the acquisition of Westchester Gas
Company, which included approximately 215 natural gas-producing wells, 52 miles
of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate
purchase price of approximately $153 million consisted of cash consideration of
approximately $22 million and the issuance of 2.5 million shares of Progress
Energy common stock valued at approximately $129 million. The purchase price
included approximately $2 million of direct transaction costs. The properties
are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border. This transaction added approximately 140 billion cubic feet of gas
reserves to the growing energy portfolio of Progress Fuels). See PART II, ITEM
8, Note 2B to the Progress Energy consolidated financial statements for
additional discussion of this transaction.
Acquisition of Natural Gas Wells
During the first quarter of 2003, Progress Fuels entered into three independent
transactions to acquire approximately 162 natural gas-producing wells with
proven reserves of approximately 195 billion cubic feet (Bcf) from Republic
Energy, Inc. and two other privately-owned companies, all headquartered in
Texas. The total gross purchase price for the transactions was approximately
$133 million.
Wholesale Energy Contract Acquisition
On March 20, 2003, PVI entered into a definitive agreement with Williams Energy
Marketing and Trading, a subsidiary of Williams, to acquire a long-term
full-requirements power supply agreement with Jackson Electric Membership Corp.,
located in Jefferson, Georgia. The agreement calls for a $188 million payment to
Williams in exchange for assignment of the Jackson supply agreement. The power
supply agreement runs through 2015 and includes the use of 640 MW of Georgia
system generation comprised of nuclear, coal, gas and pumped-storage hydro
resources. Progress Energy expects to supplement the acquired resources with its
own intermediate and peaking assets in Georgia to serve Jackson's forecasted
1,100 MW peak demand in 2005 growing to a 1,700 MW demand by 2015. The sale is
expected to close in the second quarter of 2003, subject to customary closing
conditions.
NCNG Divestiture
On October 16, 2002, the Company approved the sale of NCNG to Piedmont Natural
Gas Company, Inc. As a result of this action, the operating results of NCNG were
reclassified to discontinued operations for all reportable periods. Progress
Energy expects to sell NCNG in the summer of 2003, for net proceeds of
approximately $400 million. The asset group, including goodwill, has been
recorded at fair value less cost to sell, resulting in an estimated loss on
disposal of approximately $29.4 million, which has been recorded until the
disposition is complete and the actual loss can be determined. See PART II, ITEM
8, Note 3A to the Progress Energy consolidated financial statements.
Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a resolution to
sell the assets of Railcar Ltd., a leasing subsidiary included in the Rail
Services segment. An estimated impairment on assets held for sale of $58.8
million has been recognized for the write-down of the assets to be sold to fair
value less the costs to sell. See PART II, ITEM 8, Note 3 to the Progress Energy
consolidated financial statements.
On March 12, 2003, the Company signed a letter of intent to sell Railcar Ltd. to
The Andersons, Inc. The proceeds of the sale will be used by the Company to pay
off Railcar Ltd. lease obligations. The transaction is still subject to various
closing conditions including financing, due diligence and the completion of a
definitive purchase agreement.
Florida Progress Acquisition
On November 30, 2000, the Company completed its acquisition of FPC, a
diversified, exempt electric utility holding company, for an aggregate purchase
price of approximately $5.4 billion. The Company paid cash consideration of
approximately $3.5 billion and issued 46.5 million common shares valued at
approximately $1.9 billion. In addition, the Company issued 98.6 million
contingent value obligations (CVOs) valued at approximately $49.3 million. See
PART II, ITEM 8, Note 2C to the Progress Energy consolidated financial
statements for additional discussion of the FPC acquisition.
9
The FPC acquisition was accounted for using the purchase method of accounting
and, accordingly, the results of operations for FPC have been included in the
Company's consolidated financial statements since the date of acquisition.
Sale of MEMCO Barge Line, Inc.
On July 23, 2001, Progress Energy announced the disposition of the Inland Marine
Transportation segment of FPC, which was operated by MEMCO Barge Line, Inc.
Inland Marine provided transportation of coal, agricultural and other dry-bulk
commodities as well as fleet management services. On November 1, 2001, the
Company completed the sale of the Inland Marine Transportation segment to AEP
Resources, Inc., a wholly owned subsidiary of American Electric Power. See PART
II, ITEM 8, and Note 3C to the Progress Energy consolidated financial statements
for additional discussion of this transaction.
COMPETITION
GENERAL
In recent years, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. Several states have also decided to restructure aspects
of retail electric service. The issue of retail restructuring and competition is
being reviewed by a number of states and bills have been introduced in past
sessions of Congress that sought to introduce such restructuring in all states.
Several electric industry restructuring bills introduced during the 106th
Congress died upon adjournment in 2000. During the 107th Congress, attention
turned more toward a comprehensive energy policy as opposed to restructuring of
the electric industry. However, the 107th Congress failed to pass either a
comprehensive energy policy or industry restructuring bills. Restructuring could
eventually become part of any legislation and/or specific electric industry
restructuring legislation could be introduced and considered by the 108th
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.
In early 2000, the FERC issued Order No. 2000 on Regional Transmission
Organizations (RTOs), which set minimum characteristics and eight functions for
transmission entities, including independent system operators and transmission
companies, that are required to become FERC-approved RTOs. The rule stated that
public utilities that own, operate or control interstate transmission facilities
had to have filed, by October 15, 2000, either a proposal to participate in an
RTO or an alternative filing describing efforts and plans to participate in an
RTO. The order provided guidance and specified minimum characteristics and
functions required of an RTO and also stated that all RTOs should be operational
by December 15, 2001. During 2001, the deadline for RTOs to be operational was
extended. See PART I, ITEM 1, "Competition" of Electric-CP&L and
Electric-Florida Power for a discussion of the development activities for the
GridSouth RTO and GridFlorida RTO, respectively. See PART II, ITEM 7, "Other
Matters," for additional discussion of current developments.
On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000 Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design (SMD NOPR). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC-regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities be required to meet minimum criteria for generating reserves. On
January 15, 2003, the FERC announced the issuance of a White Paper on SMD NOPR
to be released in April 2003. The FERC has also indicated that it expects to
issue final rules during the summer of 2003. See PART I, ITEM 1, "Competition"
of Electric-CP&L and Electric-Florida Power for further discussion.
10
To date, many states have adopted legislation that would give retail customers
the right to choose their electricity provider (retail choice) and most other
states have, in some form, considered the issue. There is currently no proposed
legislation in North Carolina, South Carolina, or Florida that would introduce
retail choice.
The developments described above have created changing markets for energy. As a
strategy for competing in these changing markets, the Company is becoming a
total energy provider in the region by providing a full array of energy-related
services to its current customers and expanding its market reach. The Company
took a major step towards implementing this strategy through its acquisition of
FPC.
See PART I, ITEM 1, "Competition," under Electric-CP&L, Electric-Florida Power
and Other for further discussion of competitive developments within these
segments.
PUHCA
As a result of the acquisition of FPC, Progress Energy is now a registered
holding company subject to regulation by the SEC under PUHCA. Therefore,
Progress Energy and its subsidiaries are subject to the regulatory provisions of
PUHCA, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, and services performed by
Progress Energy Service Company, LLC.
While various proposals have been introduced in Congress regarding PUHCA, the
prospects for legislative reform or repeal are uncertain at this time.
ENVIRONMENTAL
GENERAL
In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and local authorities. The
Company considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and operations
and believes it has all necessary permits to conduct such operations.
Environmental laws and regulations constantly evolve and the ultimate costs of
compliance cannot always be accurately estimated. The capital costs associated
with compliance with pollution control laws and regulations at the Company's
existing fossil facilities that the Company expects to incur from 2003 through
2005 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) is conducting an enforcement
initiative related to a number of coal-fired utility power plants in an effort
to determine whether modifications at those facilities were subject to New
Source Review requirements or New Source Performance Standards under the Clean
Air Act. Both CP&L and Florida Power were asked to provide information to the
EPA as part of this initiative and cooperated in providing the requested
information. The EPA initiated enforcement actions against other unaffiliated
utilities as part of this initiative, some of which have resulted in settlement
agreements calling for expenditures, ranging from $1.0 billion to $1.4 billion.
A utility that was not subject to a civil enforcement action settled its New
Source Review issues with the EPA for $300 million. These settlement agreements
have generally called for expenditures to be made over extended time periods,
and some of the companies may seek recovery of the related cost through rate
adjustments. The Company cannot predict the outcome of this matter.
11
In 1998, the EPA published a final rule addressing the issue of regional
transport of ozone. This rule is commonly known as the NOx SIP Call. The EPA's
rule requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in order to
attain a pre-set state NOx emission level by May 31, 2004. CP&L is currently
installing controls necessary to comply with the rule. Capital expenditures
needed to meet these measures in North Carolina and South Carolina could reach
approximately $370 million, which has not been adjusted for inflation. The
Company has spent approximately $194 million to date related to these
expenditures. Increased operation and maintenance costs relating to the NOx SIP
Call are not expected to be material to the Company's results of operations.
Further controls are anticipated as electricity demand increases. The Company
cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain sources to
make reductions in nitrogen oxide emissions by May 1, 2003. The final rule also
includes a set of regulations that affect nitrogen oxide emissions from sources
included in the petitions. The North Carolina coal-fired electric generating
plants are included in these petitions. Acceptable state plans under the NOx SIP
Call can be approved in lieu of the final rules the EPA approved as part of the
Section 126 petitions. CP&L, other utilities, trade organizations and other
states participated in litigation challenging the EPA's action. On May 15, 2001,
the District of Columbia Circuit Court of Appeals ruled in favor of the EPA,
which will require North Carolina to make reductions in nitrogen oxide emissions
by May 1, 2003. However, the Court in its May 15th decision rejected the EPA's
methodology for estimating the future growth factors the EPA used in calculating
the emissions limits for utilities. In August 2001, the Court granted a request
by CP&L and other utilities to delay the implementation of the Section 126 Rule
for electric generating units pending resolution by the EPA of the growth factor
issue. The Court's order tolls the three-year compliance period (originally set
to end on May 1, 2003) for electric generating units as of May 15, 2001. On
April 30, 2002, the EPA published a final rule harmonizing the dates for the
Section 126 rule and the NOx SIP Call. In addition, the EPA determined in this
rule that the future growth factor estimation methodology was appropriate. The
new compliance date for all affected sources is now May 31, 2004, rather than
May 1, 2003. The EPA has approved North Carolina's NOx SIP Call rule and has
indicated it will rescind the Section 126 rule in a future rule making. The
Company expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants. The legislation also freezes the
utilities' base rates for five years unless there are significant cost changes
due to governmental action, significant expenditures due to force majeure and
other extraordinary events beyond the control of the utilities, or unless the
utilities persistently earn a return substantially in excess of the rate of
return established and found reasonable by the NCUC in the utilities' last
general rate case. See PART II, ITEM 8, and Note 24E to the Progress Energy
consolidated financial statements for additional discussion of this transaction.
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 federal and state laws.
The lead or sole regulatory agency that is responsible for a particular former
coal tar site depends largely upon the state in which the site is located. There
are several manufactured gas plant (MGP) sites to which both electric utilities
and the gas utility have some connection. In this regard, both electric
utilities and the gas utility, with other potentially responsible parties, are
participating in investigating and, if necessary, remediating former coal tar
sites with several regulatory agencies, including, but not limited to, the EPA,
the Florida Department of Environmental Protection (FDEP) and the North Carolina
Department of Environment and Natural Resources, Division of Waste Management
(DWM). Although the Company may incur costs at these sites about which it has
been notified, based upon 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, Progress Ventures and Progress Rail
are periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than MGP
sites, that may require investigation and/or remediation. Although the Company's
subsidiaries may incur costs at the sites about which they have been notified,
based upon the current status of these sites, the Company does not expect those
costs to be material to the consolidated financial position or results of
operations of the Company.
12
OTHER ENVIRONMENTAL MATTERS
On November 1, 2001, Progress Energy completed the sale of the Inland Marine
Transportation business to AEP Resources, Inc. In connection with the sale,
Progress Energy entered into environmental indemnification provisions covering
both unknown and known sites. Progress Energy recorded an accrual to cover
estimated probable future environmental expenditures. The balance of this
accrual is $9.9 million at December 31, 2002. Progress Energy believes that it
is reasonably possible that additional costs, which cannot be currently
estimated, may be incurred related to the environmental indemnification
provision beyond the amounts accrued. Progress Energy cannot predict the outcome
of this matter.
Both electric utilities, the gas utility and Progress Ventures have filed claims
with the Company's general liability insurance carriers to recover costs arising
out of actual or potential environmental liabilities. Some claims have been
settled and others are still pending. While management cannot predict the
outcome of these matters, the outcome is not expected to have a material effect
on the Company's consolidated financial position or results of operations.
EMPLOYEES
As of February 28, 2003, Progress Energy and its subsidiaries employed
approximately 15,300 full-time employees. Of this total, approximately 2,100
employees at Florida Power are represented by the International Brotherhood of
Electrical Workers (IBEW). Florida Power and the IBEW reached agreement in early
December 2002 on a new three-year labor contract. The previous contract expired
December 1, 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, 2003, CP&L employed approximately 5,300 full-time employees.
ELECTRIC - CP&L
GENERAL
CP&L is a public service corporation formed under the laws of North Carolina in
1926, and is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North and South Carolina. As of December 31,
2002, CP&L had a total summer generating capacity (including jointly-owned
capacity) of approximately 12,327 MW.
CP&L distributes and sells electricity in 57 of the 100 counties in North
Carolina and 14 counties in northeastern South Carolina. The territory served is
an area of approximately 34,000 square miles, including a substantial portion of
the coastal plain of North Carolina extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont section of North
Carolina, an area in northeastern South Carolina and an area in western North
Carolina in and around the city of Asheville. The estimated total population of
the territory served is more than 4.0 million. At December 31, 2002, CP&L was
providing electric services, retail and wholesale, to approximately 1.3 million
customers. Major wholesale power sales customers include North Carolina Eastern
Municipal Power Agency (Power Agency) and North Carolina Electric Membership
Corporation. CP&L is subject to the rules and regulations of the FERC, the North
Carolina Utilities Commission (NCUC) and the Public Service Commission of South
Carolina (SCPSC).
13
BILLED ELECTRIC REVENUES
CP&L's electric revenues billed by customer class, for the last three years, is
shown as a percentage of total CP&L electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2002 2001 2000
------------- ---- ---- ----
Residential 35% 34% 33%
Commercial 24% 23% 22%
Industrial 18% 21% 23%
Wholesale (a) 19% 19% 18%
Other retail 4% 3% 4%
(a) These revenues are managed by the Progress Ventures segment on behalf
of CP&L.
Major industries in CP&L's service area include textiles, chemicals, metals,
paper, food, rubber and plastics, wood products and electronic machinery and
equipment.
FUEL AND PURCHASED POWER
Sources of Generation
CP&L's total system generation (including jointly owned capacity) by primary
energy source, along with purchased power, for the last three years is set forth
below:
ENERGY MIX PERCENTAGES
2002 2001 2000
---- ---- ----
Coal 46% 49% 48%
Nuclear 42% 41% 43%
Hydro 1% 0% 1%
Oil/Gas 3% 2% 1%
Purchased power 8% 8% 7%
CP&L is generally permitted to pass the cost of recoverable fuel and purchased
power to its customers through fuel adjustment clauses. The future prices for
and availability of various fuels discussed in this report cannot be predicted
with complete certainty. However, CP&L believes that its fuel supply contracts,
as described below, will be adequate to meet its fuel supply needs.
CP&L's average fuel costs per million British thermal units (Btu) for the last
three years were as follows:
AVERAGE FUEL COST
(per million Btu)
2002 2001 2000
---- ---- ----
Coal (a) $ 1.93 $ 1.78 $ 1.70
Nuclear 0.43 0.44 0.45
Hydro - - -
Oil (a) 5.48 6.38 5.51
Gas (a) 5.31 4.69 5.41
Weighted average 1.38 1.26 1.21
(a) Changes in the unit price for oil and gas are due to market
conditions. Changes in the unit price for coal are primarily due to
transportation costs. Since these costs are primarily recovered
through recovery clauses established by regulators, fluctuations do
not materially affect net income.
14
Coal
CP&L anticipates a requirement of approximately 11.8 million to 12.2 million
tons of coal in 2003. Almost all of the coal is expected to be supplied from the
Appalachian coal fields in the United States. Most of the coal is delivered by
rail.
For 2003, CP&L has short-term, intermediate and long-term agreements from
various sources for approximately 95% of its burn requirements of its coal
units. These contracts have price adjustment provisions and expiration dates
ranging from 2003 to 2008. All of the coal that CP&L has purchased under
intermediate and long-term agreements is considered to be low sulfur coal by
industry standards.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a concentrate and
the conversion of this uranium oxide 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 has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement needs. CP&L reserves a small portion
of its uranium and conversion requirements for spot procurements. CP&L typically
contracts for all of its enrichment services and fabrication needs with contract
durations ranging from five to ten years. 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 or the
services necessary for its conversion, enrichment and fabrication into nuclear
fuel. For a discussion of CP&L's plans with respect to spent fuel storage, see
PART I, ITEM 1, "Nuclear Matters," for CP&L Electric.
Hydroelectric
Hydroelectric power is electric energy generated by the force of falling water.
CP&L has three hydroelectric generating plants licensed by the FERC: Walters,
Tillery and Blewett. CP&L also owns the Marshall Plant which has a license
exemption. The total maximum dependable capacity for these units is 218 MW.
Record low rainfall in the summer months of 2002 had a corresponding effect on
energy production from these facilities. CP&L is seeking to relicense its
Tillery and Blewett Plants. These plants' licenses currently expire in April
2008. The Walters plant license will expire in 2034.
Oil & Gas
Oil is purchased under contracts and in the spot market from several suppliers.
The cost of CP&L's oil and gas is determined by market prices as reported in
certain industry publications. Management believes that CP&L has access to an
adequate supply of oil for the reasonably foreseeable future. CP&L believes that
the threat of or a war against Iraq could negatively impact the price of oil.
CP&L's natural gas supply and transportation is purchased under firm supply and
transportation contracts as well as spot market purchases from numerous
suppliers. CP&L believes that existing contracts for oil are sufficient to cover
its requirements if natural gas is unavailable during the winter period for
CP&L's combustion turbine peaker fleet.
Purchased Power
CP&L purchased 4,769,194 MWh in 2002, 4,996,645 MWh in 2001 and 4,467,802 MWh in
2000 of its system energy requirements (including jointly-owned capacity) and
had available 1,737 MW in 2002, 1,756 MW in 2001 and 1,036 MW in 2000 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
15
by recent developments, including developments related to deregulation of the
electric industry in California and other states. CP&L expects that both the
North Carolina and South Carolina General Assemblies will continue to monitor
the experiences of states that have implemented electric restructuring
legislation.
Regional Transmission Organizations
In October 2000, as a result of Order 2000, CP&L, along with Duke Energy
Corporation and South Carolina Electric & Gas Company, filed an application with
the FERC for approval of a GridSouth RTO. On July 12, 2001, the FERC issued an
order provisionally approving GridSouth.
See PART II, ITEM 7, "Other Matters," for additional discussion of current
developments of GridSouth RTO.
Standard Market Design
On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000 Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design (SMD NOPR). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC-regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. CP&L filed comments on November 15, 2002 and supplemental comments on
January 10, 2003. On January 15, 2003, the FERC announced the issuance of a
White Paper on SMD NOPR to be released in April 2003. CP&L plans to file
comments on the White Paper. The FERC has also indicated that it expects to
issue final rules during the summer of 2003.
Franchises
CP&L has nonexclusive franchises with varying expiration dates in most of the
municipalities in which it distributes electric energy in North Carolina and
South Carolina. Of these 239 franchises, 194 have expiration dates ranging from
2008 to 2061 and 45 of these have no specific expiration dates. All but 13 of
the 194 franchises with expiration dates have a term of 60 years. The exceptions
include three franchises with terms of ten years, one with a term of twenty
years, six with terms of thirty years, two with terms of forty years and one
with a term of fifty years. However, CP&L also serves within a number of
municipalities and in all of its unincorporated areas without franchise
agreements.
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, the FERC previously
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 the FERC in mid-1996. Several wholesale and
retail customers filed protests challenging numerous aspects of CP&L's tariff
and requesting that an evidentiary proceeding be held. In July 1997, CP&L filed
an offer of settlement in this case which was certified by an administrative law
judge in September 1997. In February 2000, the FERC issued a basket order for
several utilities including CP&L to file a compliance filing stating whether
there were any remaining undisputed issues surrounding CP&L's open access
transmission tariff. On May 1, 2000, CP&L made the compliance filing setting
forth the remaining undisputed issues and a plan for settling those issues. On
August 25, 2000, CP&L filed modifications to its open access transmission tariff
as a result of settlement negotiations with the remaining intervenors. In
November 2000, the FERC approved the open access transmission tariff of CP&L
with the settlement modifications.
16
In February 2000, CP&L filed a joint open access tariff to reflect the merger
with FPC. The FERC approved the joint tariff in July 2000 effective with
completion of the merger, which occurred on November 30, 2000. In April 2001,
CP&L and FPC each filed separate transmission tariffs as a result of the FERC
Order 614. The FERC approved the CP&L transmission tariff in June 2001. In April
2001, CP&L filed changes to the Energy Imbalance provision of the transmission
tariff. In October 2001, the FERC approved changes to the Energy Imbalance
provision of the transmission tariff. The FERC ordered CP&L to develop a
mechanism to credit Energy Imbalance penalty revenues to non-offending
transmission customers. In November 2001, CP&L put in place a mechanism to
credit revenues to non-offending transmission customers.
During 2001, legislation was introduced in South Carolina that would impose a
moratorium on the certification and construction of merchant plants until 2003
and prohibit the transfer or sale of a merchant plant certificate. Hearings were
held on these bills but no action has been taken. In addition, the Department of
Health and Environmental Control of South Carolina has halted the issuance of
any air permits for merchant plants applying for such permits. The SCPSC
contracted with a consulting firm to conduct a study on the impact of merchant
plants in South Carolina which was completed in the summer of 2002. The study
concluded that the proper approach to merchant plants should be driven by the
State's position with regard to what role the market should play in determining
the need for electric generation as opposed to the traditional methodology of
relying upon the State's utilities to determine the need for additional
generation. No actions have been taken as a result of the study and no new
construction of merchant plants has begun. CP&L cannot predict the outcome of
this matter.
REGULATORY MATTERS
General
CP&L is subject to regulation in North Carolina by the NCUC and in South
Carolina by the SCPSC with respect to, among other things, rates and service for
electric energy sold at retail, retail service territory and issuances of
securities. In addition, CP&L is subject to regulation by the FERC with respect
to transmission and sales of wholesale power, accounting and certain other
matters. The underlying concept of utility ratemaking is to set rates at a level
that allows the utility to collect revenues equal to its cost of providing
service including a reasonable rate of return on its equity. Increased
competition as a result of industry restructuring may affect the ratemaking
process.
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 CP&L's most recent rate cases in 1988,
the NCUC and the SCPSC each authorized a return on equity of 12.75% for CP&L.
Legislation enacted in North Carolina in 2002 freezes CP&L's base retail rates
for five years unless there are significant cost changes due to governmental
action, significant expenditures due to force majeure or other extraordinary
events beyond the control of CP&L.
See PART II, ITEM 8, Note 15C to the Progress Energy consolidated financial
statements and Note 9B to the CP&L consolidated financial statements for
additional discussion of CP&L's retail rate developments during 2002.
Wholesale Rate Matters
CP&L is subject to regulation by the FERC with respect to rates for transmission
and sale of electric energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the event of certain
emergency situations), the licensing and operation of hydroelectric projects
and, to the extent 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.
17
Fuel Cost Recovery
CP&L's operating costs not covered by the utility's base rates include fuel and
purchased power. Each state commission allows electric utilities to recover
certain of these costs through various cost recovery clauses, to the extent the
respective commission determines in an annual hearing that such costs are
prudent. Costs recovered by CP&L, by state, are as follows:
o North Carolina - fuel costs and the fuel portion of purchased power
o South Carolina - fuel costs, certain purchased power costs and
emission allowance expense
Each state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
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, shut down a nuclear unit,
or some combination of these, depending upon its assessment of the severity of
the situation, until compliance is achieved. NRC operating licenses currently
expire in December 2014 and September 2016 for Brunswick Units 2 and 1,
respectively, in July 2010 for Robinson Unit No. 2 and in October 2026 for the
Harris Plant. An application to extend the Robinson license 20 years was
submitted in June 2002 and a similar application is expected to be made for
Brunswick in December 2004. An extension will also be sought for the Harris
Plant. On February 20, 2003, CP&L notified the NRC of its intent to submit a
license renewal application for the Harris Plant in 2006. 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.
In addition, the Independent Spent Fuel Storage Installation at the Robinson
plant will request to have its license extended 20 years with an exemption
request for an additional 20-year extension during the first quarter of 2004.
Its current license is due to expire in August 2006. The Company expects to
receive this extension.
CP&L is currently evaluating and implementing power uprate projects at its
nuclear facilities to increase electrical generation output. A power uprate was
completed at the Harris Plant during 2001 and at the Robinson Nuclear Plant in
2002. Power uprates are also in progress at the Brunswick Plant. Brunswick Unit
1 increased its capacity by 52 MW in 2002 and additional increases will be
implemented in phases over the next several years. The total increased
generation from these projects is estimated to be approximately 250 MW.
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.
Pressurized Water Reactors
On March 18, 2002, the NRC sent a bulletin to companies that hold licenses for
pressurized water reactors (PWRs) requiring information on the structural
integrity of the reactor vessel head and a basis for concluding that the vessel
head will continue to perform its function as a coolant pressure boundary. The
Company filed responses as required. Inspections of the vessel heads at the
Company's PWR plants have been performed during previous outages. At the
Robinson Plant, an inspection was completed in April 2001 and no penetration
nozzle cracking was identified and there was no degradation of the reactor
vessel head. At the Harris Plant, sufficient inspections were completed during
the last refueling outage in the fourth quarter of 2001 to conclude there is no
degradation of the reactor vessel head. The Company's Brunswick Plant has a
different design and is not affected by the issue.
On August 9, 2002, the NRC issued an additional bulletin dealing with head
leakage due to cracks near the control rod nozzles. The NRC has asked licensees
to commit to high inspection standards to ensure the more susceptible plants
have no cracks. The Robinson Plant is in this category and had a refueling
outage in October 2002. The Company completed a series of examinations in
October 2002 of the entire reactor pressure vessel head and found no indications
18
of control rod drive mechanism cracking and no corrosion of the head itself.
During the outage, a boric acid leakage walkdown of the reactor coolant pressure
boundary was also completed and no corrosion was found. The Harris Plant is
ranked in the lowest susceptibility classification and the Company does not plan
further inspections until its next regularly scheduled outage in spring of 2003.
In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated penetration nozzles at PWRs.
The Company has responded to the Order, stating that the Company intends to
comply with the provisions of the Order. No adverse impact is anticipated.
Security
On February 25, 2002, the NRC issued an order requiring interim compensatory
measures with regard to security at nuclear plants. This order formalized many
of the security enhancements made at the Company's nuclear plants since
September 2001. This order includes additional restrictions on access, increased
security presence and closer coordination with the Company's partners in
intelligence, military, law enforcement and emergency response at the federal,
state and local levels. The Company completed the requirements by the
established deadlines. The NRC inspections for compliance are underway.
In addition, in January 2003, the NRC issued a final order with regard to access
control. This order requires the Company to enhance its current access control
program by January 7, 2004. The Company expects that it will be in full
compliance with the order by the established deadline.
As the NRC, other governmental entities and the industry continue to consider
security issues, it is possible that more extensive security plans could be
required.
Spent Fuel and Other High-Level Radioactive Waste
The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework
for development by the federal government of interim storage and permanent
disposal facilities for high-level radioactive waste materials. The Nuclear
Waste Act promotes increased usage of interim storage of spent nuclear fuel at
existing nuclear plants. 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 or prior to
the expiration of these licenses, dry storage may be necessary.
See PART II, ITEM 8, Note 24 to the Progress Energy consolidated financial
statements and Note 18 to the CP&L consolidated financial statements for a
discussion of CP&L's contract with the U.S. Department of Energy (DOE) for spent
nuclear waste.
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 the FERC. See PART II, ITEM 8, Note 1H to the Progress
Energy consolidated financial statements and Note 1G to the CP&L consolidated
financial statements for a discussion of CP&L's nuclear decommissioning costs.
Enrichment Facilities Decontamination
CP&L filed an action against the United States in the U.S. Court of Claims on
March 21, 1997, 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. The government is collecting this assessment on an annual basis,
which is 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. A number of other
utilities filed similar actions against the government.
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
19
Appeals for the Federal Circuit on December 26, 2000. The Federal Circuit stayed
consideration of the case pending a decision by the Supreme Court on a petition
for writ of certiorari that was filed by Commonwealth Edison et. al. in their
case against the government. The Supreme Court refused to accept the case in
favor of the Government. Based on a joint motion, CP&L's appeal in the U.S.
Court of Appeals has been dismissed with prejudice.
ENVIRONMENTAL MATTERS
There are 12 former MGP sites and 14 other active waste sites associated with
CP&L that have required or are anticipated to require investigation and/or
remediation costs. CP&L received insurance proceeds to address costs associated
with environmental liabilities related to its involvement with MGP sites. All
eligible expenses related to these waste costs are charged against a specific
fund containing these proceeds. As of December 31, 2002, approximately $8.0
million remains in this centralized fund with a related accrual of $8.0 million
recorded for the associated expenses of environmental issues. As CP&L's share of
costs for investigating and remediating these sites becomes known, the fund is
assessed to determine if additional accruals will be required. CP&L does not
believe that it can provide an estimate of the reasonably possible total
remediation costs beyond what remains in the environmental insurance recovery
fund. This is due to the fact that the sites are at different stages:
investigation has not begun at 15 sites, investigation has begun but remediation
cannot be estimated at seven sites and four sites have begun remediation. CP&L
measures its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites. The
process often involves assessing and developing cost-sharing arrangements with
other potentially responsible parties (PRPs). Once the centralized fund is
depleted, CP&L will accrue costs for the sites to the extent its liability is
probable and the costs can be reasonably estimated. Presently, CP&L cannot
currently determine the total costs that may be incurred in connection with the
remediation of all sites. According to current information, these future costs
at the CP&L sites are not expected to be material to the Company's financial
condition or results of operations.
ELECTRIC - FLORIDA POWER
GENERAL
Florida Power was incorporated in Florida in 1899, and is an operating public
utility engaged in the generation, purchase, transmission, distribution and sale
of electricity. At December 31, 2002, Florida Power had a total summer
generating capacity (including jointly-owned capacity) of approximately 8,024
MW.
Florida Power provided electric service during 2002 to an average of 1.5 million
customers in west central Florida. Its service area covers approximately 20,000
square miles and includes the densely populated areas around Orlando, as well as
the cities of St. Petersburg and Clearwater. Florida Power is interconnected
with 20 municipal and nine rural electric cooperative systems. Major wholesale
power sales customers include Seminole Electric Cooperative, Inc., Florida
Municipal Power Agency, Florida Power & Light Company and Tampa Electric
Company. Florida Power is subject to the rules and regulations of the FERC and
the Florida Public Service Commission (FPSC).
BILLED ELECTRIC REVENUES
Florida Power's electric revenues billed by customer class for the last three
years, is shown as a percentage of total Florida Power electric revenues in the
table below:
BILLED ELECTRIC REVENUES
Revenue Class 2002 2001 2000(a)
------------- ---- ---- -------
Residential 55% 54% 53%
Commercial 24% 24% 24%
Industrial 7% 7% 8%
Others 6% 6% 5%
Wholesale (b) 8% 9% 10%
(a) These figures reflect Florida Power's billed electric revenues for the
full year ended December 31, 2000, which is generally representative
of the period Progress Energy owned Florida Power.
(b) These revenues are managed by the Progress Ventures segment on behalf
of Florida Power.
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Important industries in Florida Power's territory include phosphate rock mining
and processing, electronics design and manufacturing, and citrus and other food
processing. Other important commercial activities are tourism, health care,
construction and agriculture.
FUEL AND PURCHASED POWER
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 the last three years is presented in the
following table:
ENERGY MIX PERCENTAGES
Fuel Type 2002 2001 2000 (a)
--------- ---- ---- --------
Coal (b) 33% 33% 34%
Oil 16% 16% 15%
Nuclear 15% 15% 15%
Gas 15% 14% 14%
Purchased power 21% 22% 22%
(a) These figures reflect Florida Power's energy mix percentages for the
full year ended December 31, 2000, which is generally representative
of the period Progress Energy owned Florida Power.
(b) Amounts include synthetic fuel from unrelated third parties and
petroleum coke.
Florida Power is generally permitted to pass the cost of recoverable fuel and
purchased power to its customers through fuel adjustment clauses. The future
prices for and availability of various fuels discussed in this report cannot be
predicted with complete certainty. However, Florida Power believes that its fuel
supply contracts, as described below, will be adequate to meet its fuel supply
needs.
Florida Power's average fuel costs per million Btu for the last three years were
as follows:
AVERAGE FUEL COST
(per million Btu)
2002 2001 2000(a)
------ ------ -------
Coal (b) $ 2.43 $ 2.16 $ 1.89
Oil 3.77 3.81 4.15
Nuclear 0.46 0.47 0.47
Gas 4.06 4.52 4.32
Weighted average 2.60 2.59 2.46
(a) These figures reflect Florida Power's average fuel cost for the year
ended December 31, 2000, which is representative of the period
Progress Energy owned Florida Power.
(b) Amounts include synthetic fuel from unrelated third parties and
petroleum coke.
Changes in the unit price for coal, oil and gas are due to market conditions.
Since these costs are primarily recovered through recovery clauses established
by regulators, fluctuations do not materially affect net income.
Coal
Florida Power anticipates a combined requirement of approximately 5.7 million to
6.1 million tons of coal and synthetic fuel in 2003. 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. All of this fuel is supplied by Progress Fuels, a subsidiary
of Progress Energy, pursuant to contracts between Florida Power and Progress
Fuels.
For 2003, Progress Fuels has medium-term and long-term contracts with various
sources for approximately 100% of the burn requirements of Florida Power's coal
units. These contracts have price adjustment provisions and have expiration
dates ranging from 2003 to 2005. All the coal to be purchased for Florida Power
is considered to be low sulfur coal by industry standards.
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Oil and Gas
Oil is purchased under term contracts and in the spot market from several
suppliers. The majority of the cost of Florida Power's oil and gas is determined
by market prices as reported in certain industry publications. Management
believes that Florida Power has access to an adequate supply of oil for the
reasonably foreseeable future. Florida Power believes that the threat of or a
war against Iraq could negatively impact the price of oil. Florida Power's
natural gas supply and transportation is purchased under firm supply and
transportation contracts and in the spot market from numerous suppliers. Florida
Power also uses interruptible transportation contracts on certain occasions when
available. Florida Power believes that existing contracts for oil are sufficient
to cover its requirements if natural gas is unavailable during certain time
periods.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a concentrate and
the conversion of this uranium oxide concentrate into uranium hexafluoride.
Stages III and IV entail the enrichment of the uranium hexafluoride and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
Florida Power has sufficient uranium, conversion, enrichment and fabrication
contracts to meet its near-term nuclear fuel requirements needs. Florida Power
expects to contract for all of its future long-term uranium, conversion and
enrichment service needs with contract durations ranging from five to ten years.
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 or the services necessary for its
conversion, enrichment and fabrication into nuclear fuel.
Purchased Power
Florida Power, along with other Florida utilities, buys and sells power in the
wholesale market on a short-term and long-term basis. As of December 31, 2002,
Florida Power had a variety of purchase power agreements for the purchase of
approximately 1,304 MW of firm power. These agreements include (1) long-term
contracts for the purchase of about 473 MW of purchased power with other
investor-owned utilities, including a contract with The Southern Company for
approximately 413 MW, and (2) approximately 831 MW of capacity under contract
with 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 and
other states.
On December 11, 2001, the Florida 2020 Study Commission issued its final report
to the Florida Legislature regarding possible changes to the regulation of
electric utilities in Florida. The Florida legislature did not take any action
on the final report during the 2001 or 2002 session.
In response to a legislative directive, the FPSC and the FDEP submitted by
February 2003 a joint report on renewable electric generating technologies for
Florida. The report assessed the feasibility and potential magnitude of
renewable electric capacity for Florida, and summarized the mechanisms other
states have adopted to encourage renewable energy. The report did not contain
any policy recommendations. The Company cannot anticipate when, or if,
restructuring legislation will be enacted or if the Company would be able to
support it in its final form.
Regional Transmission Organizations
As a result of Order 2000, Florida Power, along with Florida Power & Light
Company and Tampa Electric Company (the Applicants) filed with the FERC in
October 2000 an application for approval of a GridFlorida RTO. The GridFlorida
proposal is pending before both the FERC and the FPSC. The FERC provisionally
approved the structure and governance of GridFlorida. In December 2001, the FPSC
found the Applicants were prudent in proactively forming GridFlorida but ordered
the Applicants to modify the proposal in several material respects, including a
change in structure to a not-for-profit Independent System Operator (ISO). The
Commission's most recent order in September 2002 ordered further state
proceedings. The issues to be addressed as modifications include, but are not
limited to 1) pricing/rate structure; 2) elimination of the pancaking of
revenues; 3) cost recovery of incremental costs; 4) demarcation dates for new
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facilities and long-term transmission contracts; and 6) market design. The
Florida Office of Public Counsel appealed the September 2002 order to the
Florida Supreme Court and on October 28, 2002, the FPSC abated its proceedings
pending the outcome of the appeal. It is unknown what the outcome of this appeal
will be at this time. It is unknown when the FERC or the FPSC will take final
action with regard to the status of GridFlorida or what the impact of further
proceedings will have on the Company's earnings, revenues or pricing.
See PART II, ITEM 7, "Other Matters," for a discussion of current developments
of GridFlorida RTO.
Standard Market Design
On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000 Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design (SMD NOPR). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC-regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. Florida Power filed comments on November 15, 2002 and supplemental comments
on January 10, 2003. On January 15, 2003, the FERC announced the issuance of a
White Paper on SMD NOPR to be released in April 2003. Florida Power plans to
file comments on the White Paper. The FERC has also indicated that it expects to
issue final rules during the summer of 2003.
Merchant Plants
There has been no change in the statutory framework for siting new generation
since the Florida Supreme Court's decision in Tampa Electric Company v. Garcia,
767 So.2d 428 (Fla. 2000) in April 2000. The Court reversed a decision of the
FPSC and held that under Florida's Power Plant Siting Act, an applicant for any
new generation over 75 MW that includes a steam generating facility must be a
load-serving utility or the output of the proposed plant must be under firm
contract to a load-serving utility. Thus, site certification for merchant
generation for large, non-peaking capacity cannot be independently undertaken.
At the present time there are no pending legislative proposals for change.
Franchise Agreements
Florida Power holds franchises with varying expiration dates in 104 of the
municipalities in which it distributes electric energy. Florida Power also
serves within a number of municipalities and in all its unincorporated areas
without franchise agreements. 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.
Approximately 36% of Florida Power's total utility revenues for 2002 were from
the incorporated areas of the 104 municipalities that had franchise ordinances
during the year. Since 2000, Florida Power has renewed 27 expiring franchises
and reached agreement on a franchise with a city that did not previously have a
franchise. Franchises with eight municipalities have expired without renewal.
All but 26 of the existing franchises cover a 30-year period from the date
enacted. The exceptions are 22 franchises, each with a term of 10 years and
expiring between 2005 and 2012; two franchises each with a term of 15 years and
expiring in 2017; one 30-year franchise that was extended in 2000 for five years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 104 franchises, 39 expire between January 1, 2003 and December 31, 2012 and
65 expire between January 1, 2013 and December 31, 2031.
Ongoing negotiations are taking place with the municipalities to reach agreement
on franchise terms and to enact new franchise ordinances. See PART II, ITEM 8,
Note 24 to the Progress Energy consolidated financial statements for a
discussion of Florida Power's franchise litigation.
Stranded Costs
An important issue encompassed by industry restructuring is the recovery of
"stranded costs." Stranded costs primarily include the generation assets of
23
utilities whose value in a competitive marketplace would be less than their
current book value, as well as above-market purchased power commitments to QFs.
Thus far, all states that have passed restructuring legislation have provided
for the opportunity to recover a substantial portion of stranded costs.
Assessing the amount of stranded costs for a utility requires various
assumptions about future market conditions, including the future price of
electricity. For Florida Power, the single largest stranded cost exposure is its
commitment to QFs. Florida Power has taken a proactive approach to this industry
issue. 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
Public Utility Regulatory Policies Act of 1978 (PURPA).
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 the FERC with respect to transmission and
sales of wholesale power, accounting and certain other matters. The underlying
concept of utility ratemaking is to set rates at a level that allows the utility
to collect revenues equal to its cost of providing service plus a reasonable
rate of return on its equity. Increased competition as a result of industry
restructuring may affect the ratemaking process.
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.
On March 27, 2002, the parties in Florida Power's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The Agreement
is generally effective from May 1, 2002 through December 31, 2005. The Agreement
eliminates the authorized Return on Equity (ROE) range normally used by the FPSC
for the purpose of addressing earning levels; provided, however, that if Florida
Power's base rate earnings fall below a 10% return on equity, Florida Power may
petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail rates by 9.25%;
resulting in a reduction of retail revenues from the sale of electricity by an
annual amount of $125 million. The Agreement also provides that Florida Power
will operate under a Revenue Sharing Incentive Plan (the Plan) through 2005, and
thereafter until terminated by the FPSC, that establishes annual revenue caps
and sharing thresholds. The Plan provides that retail base rate revenues between
the sharing thresholds and the caps will be divided into two shares - a 1/3
share to be retained by Florida Power's shareholders, and a 2/3 share to be
refunded to Florida Power's retail customers; provided, however, that for the
year 2002 only, the refund to customers will be limited to 67.1% of the 2/3
customer share. The retail base rate revenue sharing threshold amount for 2002
was $1.296 billion and will increase $37 million each year thereafter. The Plan
also provides that all retail base rate revenues above the retail base rate
revenue caps established for each year will be refunded 100% to retail customers
on an annual basis. For 2002, the refund to customers will be limited to 67.1%
of the retail base rate revenues that exceed the 2002 cap. The retail base
revenue cap for 2002 was $1.356 billion and will increase $37 million each year
thereafter. As of December 31, 2002, $4.7 million was accrued and will be
refunded to customers in March 2003. On February 24, 2003, the parties to the
Agreement filed a motion seeking an order from the FPSC to enforce the
Agreement. In this motion, the parties dispute Florida Power's calculation of
retail revenue subject to refund and contend that the refund should be
approximately $23 million. Florida Power cannot predict the outcome of this
matter.
The Agreement also provides that beginning with the in-service date of Florida
Power's Hines Unit 2 and continuing through December 31, 2005, Florida Power
will be allowed to recover through the fuel cost recovery clause a return on
average investment and depreciation expense for Hines Unit 2, to the extent such
costs do not exceed the Unit's cumulative fuel savings over the recovery period.
Hines Unit 2 is a 516 MW combined-cycle unit under construction and currently
scheduled for completion in late 2003.
Additionally, the Agreement provides that Florida Power would effect a
mid-course correction of its fuel cost recovery clause to reduce the fuel factor
by $50 million for 2002. The fuel cost recovery clause will operate as it
normally does, including, but not limited to, any additional mid-course
adjustments that may become necessary and the calculation of true-ups to actual
fuel clause expenses.
Florida Power will suspend accruals on its reserves for nuclear decommissioning
and fossil dismantlement through December 31, 2005. Additionally, for each
calendar year during the term of the Agreement, Florida Power will record a
$62.5 million depreciation expense reduction, and may, at its option, record up
to an equal annual amount as an offsetting accelerated depreciation expense. In
24
addition, Florida Power is authorized, at its discretion, to accelerate the
amortization of certain regulatory assets over the term of the Agreement. There
was no accelerated depreciation or amortization expense recorded for the year
ended December 31, 2002.
Under the terms of the Agreement, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan and
expects to achieve a 20% improvement in its annual System Average Interruption
Duration Index by no later than 2004. If this improvement level is not achieved
for calendar years 2004 or 2005, Florida Power will provide a refund of $3
million for each year the level is not achieved to 10% of its total retail
customers served by its worst performing distribution feeder lines.
Per the Agreement, Florida Power was required to refund to customers $35 million
of revenues collected during the interim period of March 13, 2001 through April
30, 2002. This one-time retroactive revenue refund was recorded in the first
quarter of 2002 and was returned to retail customers over an eight-month period
ended December 31, 2002.
Fuel and Other Cost Recovery
Florida Power's operating costs not covered by the utility's base rates include
fuel, purchased power and energy conservation expenses and specific
environmental costs. The state commission allows electric utilities to recover
certain of these costs through various cost recovery clauses, to the extent the
respective commission determines in an annual hearing that such costs are
prudent. In addition, in December 2002, the FPSC approved an Environmental Cost
Recovery Clause which will permit the Company to recover the costs of specified
environmental projects to the extent these expenses are found to be prudent in
an annual hearing and not otherwise included in base rates. Costs will be
recovered through this recovery clause in the same manner as the other existing
clause mechanisms.
The state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
Florida Power has one nuclear generating plant, Crystal River Unit No. 3 (CR3),
which is subject to regulation by the NRC. The NRC's jurisdiction encompasses
broad supervisory and regulatory powers over the construction and operation of
nuclear reactors, including matters of health and safety, antitrust
considerations and environmental impact. Florida Power has a license to operate
the nuclear plant through December 3, 2016. Florida Power currently has a 91.8%
ownership interest in CR3. On February 20, 2003, Florida Power notified the NRC
of its intent to submit an application to extend the plant license in the first
quarter of 2009.
In late 2002, CR3 received a license amendment authorizing a small power level
increase. The power level increase of approximately 8 MW was implemented in
February 2003.
On March 18, 2002, the NRC sent a bulletin to companies that hold licenses for
PWRs requiring information on the structural integrity of the reactor vessel
head and a basis for concluding that the vessel head will continue to perform
its function as a coolant pressure boundary. The Company filed responses as
required. Inspections of the vessel heads at the Company's PWR plant have been
performed during previous outages. In October 2001, at CR3, one nozzle was found
to have a crack and was repaired; however, no degradation of the reactor vessel
head was identified. Current plans are to replace the vessel head at CR3 during
its next regularly scheduled refueling outage in the fall of 2003.
On August 9, 2002, the NRC issued an additional bulletin dealing with head
leakage due to cracks near the control rod nozzles. The NRC has asked licensees
to commit to high inspection standards to ensure the more susceptible plants
have no cracks. For CR3, the Company has responded to the NRC that previous
inspections are sufficient until the reactor head is replaced in the fall of
2003.
In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated penetration nozzles at PWRs.
The Company has responded to the Order, stating that the Company intends to
comply with the provisions of the Order. No adverse impact is anticipated.
Enrichment Facilities Decontamination
Florida Power filed an action against the United States in the U.S. Court of
Claims on November 1, 1996 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. The government is collecting this assessment on an annual basis,
which is levied upon all domestic utilities that had enrichment services
25
contracts with the government. Collection of the special assessments began in
1992 and is scheduled to continue for a 15-year period. A number of other
utilities have filed similar actions against the government.
The Claims Court issued a decision granting the government's summary judgment
motion. That decision was appealed to the U.S. Court of Appeals for the Federal
Circuit, which stayed its consideration of the case pending a decision by the
U.S. Supreme Court on a petition for writ of certiorari that was filed by
Commonwealth Edison et al. in their case against the government. This Supreme
Court refused to accept that case for review, effectively resolving the case in
favor of the government. Based on a joint motion, Florida Power's appeal has
been dismissed with prejudice.
ENVIRONMENTAL MATTERS
There are two former MGP sites and 11 other active waste sites or categories of
sites associated with Florida Power that have required or are anticipated to
require investigation and/or remediation costs. As of December 31, 2002 and
2001, Florida Power has accrued approximately $10.9 million and $8.5 million,
respectively, for probable and reasonably estimable costs at these sites.
Florida Power does not believe that it can provide an estimate of the reasonably
possible total remediation costs beyond what it has currently accrued. In 2002,
Florida Power filed a petition for recovery of approximately $4.0 million in
environmental costs through the Environmental Cost Recovery Clause with the
FPSC. Florida Power was successful with this filing and will recover costs
through rates for investigation and remediation associated with transmission and
distribution substations and transformers. As more activity occurs at these
sites, Florida Power will assess the need to adjust the accruals. These accruals
have been recorded on an undiscounted basis. Florida Power measures its
liability for these sites based on available evidence including its experience
in investigating and remediating environmentally impaired sites. This process
often includes assessing and developing cost-sharing arrangements with other
potentially responsible parties.
PROGRESS VENTURES
GENERAL
The Progress Ventures business segment was created in 2000 to manage Progress
Energy's wholesale energy marketing and trading, non-regulated generation and
fuel properties, as well as an ocean barge partnership. The operations of the
Progress Ventures business segment can be broken down into three key areas: 1)
fuel extraction, manufacturing and delivery; 2) merchant generation ownership;
and 3) energy marketing and trading.
FUEL EXTRACTION, MANUFACTURING AND DELIVERY
The Progress Ventures business segment owns an array of assets that produce,
transport and deliver fuel and provide related services for the open market. The
Progress Ventures business segment has subsidiaries that produce natural gas and
oil products, mine coal and others that produce synthetic coal-based fuel, an
alternative fuel product made from waste coal and coal byproducts. This product
has been classified as a synthetic fuel within the meaning of Section 29 of the
Internal Revenue Code. Sales of synthetic fuel therefore qualify for tax
credits. See PART II, ITEM 7, "Other Matters" for a discussion of the synthetic
fuel tax credits.
The current combined assets of Progress Ventures which are involved in fuel
extraction, manufacturing and delivery include:
o Three coal-mining complexes, expected to produce about 3 million tons
per year;
o Seven synthetic fuel plants capable of producing up to 18 million tons
per year;
o Natural gas properties in Colorado, Texas and Louisiana producing
about 21 net billion cubic feet per year;
o Six terminals on the Ohio River and its tributaries, part of the
trucking, rail and barge network for coal delivery;
o Majority-ownership in a barge partnership that moves coal products
from the mouth of the Mississippi River to the Crystal River facility
in Florida.
Progress Fuels, a business unit of the Progress Ventures segment, acquired
approximately 162 natural gas-producing wells with proven reserves of
approximately 195 billion cubic feet from Republic Energy, Inc. and two other
privately-owned companies during the first quarter of 2003.
26
NONREGULATED GENERATION OWNERSHIP
Nonregulated generation represents power plants whose capacity and energy are
sold on the wholesale market outside the realm of retail regulation. A
cornerstone of Progress Ventures' business plan is to own a portfolio of
approximately 3,100 MW of merchant generation capacity by 2003. Much of this
portfolio is being built by Progress Ventures. The Company has contracts
representing 63%, 69% and 25% of planned production capacity for 2003 through
2005, respectively.
On March 20, 2003, PVI entered into a definitive agreement with Williams Energy
Marketing and Trading, a subsidiary of Williams, to acquire a long-term
full-requirements power supply agreement with Jackson Electric Membership Corp.,
located in Jefferson, Georgia. The agreement calls for a $188 million payment to
Williams in exchange for assignment of the Jackson supply agreement. The power
supply agreement runs through 2015 and includes the use of 640 MW of Georgia
system generation comprised of nuclear, coal, gas and pumped-storage hydro
resources. Progress Energy expects to supplement the acquired resources with its
own intermediate and peaking assets in Georgia to serve Jackson's forecasted
1,100 MW peak demand in 2005 growing to a 1,700 MW demand by 2015. The sale is
expected to close in the second quarter of 2003, subject to customary closing
conditions.
Progress Ventures had approximately 1,554 MW of nonregulated generation in
commercial operation as of December 31, 2002. Construction of generating assets
at three locations will increase this to approximately 3,100 MW by the end of
2003. See PART I, ITEM 2, "Properties," for additional information on these
planned additions.
ENERGY MARKETING AND TRADING
Within this business function, the energy produced by the merchant plants as
well as some energy produced by the utilities is sold under term contracts and
in the spot market. This area is divided into two departments: Regulated
Wholesale Marketing and Trading and Competitive Marketing and Trading. Regulated
Wholesale Marketing and Trading manages approximately 5,000 MW of wholesale
power contracts that primarily include those for CP&L and Florida Power.
Competitive Marketing and Trading markets the nonregulated plants not under
contract into the nonregulated market and engages in limited financial trading
activities.
In addition to power contracts, this business area also purchases fuel for both
utility and merchant generation, and trades other sources of energy, such as
natural gas and oil. Progress Ventures also uses financial instruments to manage
the risks associated with fluctuating commodity prices and increase the value of
the Company's power generation assets.
COMPETITION
Progress Ventures does not operate in the same environment as regulated
utilities. It operates specifically in the wholesale market, which means
competition is its primary driver. Progress Ventures' synthetic fuel operations,
coal operations and merchant generation plants compete in the eastern United
States utility and industrial coal markets. Factors contributing to the success
in these markets include a competitive cost structure and strategic locations.
See PART II, ITEM 7, "Other Matters," for a discussion of risks associated with
synthetic fuel tax credits. There are, however, numerous competitors in each of
these markets, although no one competitor is dominant in any industry.
ENVIRONMENTAL MATTERS
Progress Ventures' environmental matters primarily relate to air and water
quality matters. However, certain historical waste sites exist which are being
addressed voluntarily. Environmental costs cannot be determined. The Company
does not expect future costs to be material to Progress Ventures.
RAIL SERVICES
The largest component of the Rail Services business segment is led by Progress
Rail Services Corporation (Progress Rail). Progress Rail is one of the largest
integrated and diversified suppliers of railroad and transit system products and
services in North America and is headquartered in Albertville, Alabama. Rail
Services' principal business functions include the Mechanical Group, Rail and
Trackwork Group, and Recycling Group.
The Mechanical Group is primarily focused on railroad rolling stock that
includes freight cars, transit cars and locomotives, the repair and maintenance
of these units, and the manufacturing or reconditioning of major components for
these units. The Rail and Trackwork Group focuses on rail and other track
components, the infrastructure which supports the operation of rolling stock, as
well as the equipment used in maintaining the railroad infrastructure and
right-of-way. The Recycling Group supports the Mechanical and Rail and Trackwork
Groups through its reclamation of reconditionable material. In addition, the
Recycling Group is a major supplier of recyclable scrap metal to North American
steel mills and foundries through its processing locations as well as its scrap
brokerage operations.
Rail Services' key railroad industry customers are Class 1 railroads, regional
and shortline railroads, major North American transit systems, major railcar and
locomotive builders, and major railcar lessors. The U.S. operations are located
in 26 states and include further geographic coverage through mobile crews on a
selected basis. This coverage allows for Rail Services' customer base to be
dispersed throughout the U.S., Canada and Mexico.
27
During 2003, the Company intends to sell the assets of Railcar Ltd., a leasing
subsidiary, included in the Rail Services segment, and has therefore reported
these assets as assets held for sale. On March 12, 2003, the Company signed a
letter of intent to sell Railcar Ltd. to The Andersons, Inc. The proceeds of the
sale will be used to pay off Railcar Ltd. lease obligations. The transaction is
still subject to various closing conditions including financing, due diligence
and the completion of a definitive purchase agreement.
ENVIRONMENTAL MATTERS
Progress Rail is voluntarily addressing certain historical waste sites. The
Company does not anticipate future costs to be material to Progress Rail.
OTHER
GENERAL
The Other segment primarily includes the operations of Progress Telecom and
Caronet, Inc. (Caronet). The operations of Caronet are managed by Progress
Telecom. NCNG has been excluded from the Other segment because of its
classification as a discontinued operation. This segment also includes other
nonregulated operations of CP&L and FPC.
PROGRESS TELECOM AND CARONET
Progress Telecom has data fiber network transport capabilities that stretch from
New York to Miami, Florida, with gateways to Latin America and conducts
primarily a carrier's carrier business. Progress Telecom markets wholesale
fiber-optic-based capacity service in the Eastern United States to long-distance
carriers, internet service providers and other telecommunications companies.
Progress Telecom also markets wireless structure attachments to wireless
communication companies and governmental entities. Caronet serves the
telecommunications industry by providing fiber-optic telecommunications
services. As of December 31, 2002, Progress Telecom and Caronet owned and
managed approximately 8,400 route miles and more than 130,000 fiber miles of
fiber-optic cable.
Progress Telecom and Caronet compete with other providers of fiber-optic
telecommunications services, including local exchange carriers and competitive
access providers, in the Eastern United States.
Lease revenue for dedicated transport and data services is generally billed in
advance on a fixed rate basis and recognized over the period the services are
provided. Revenues relating to design and construction of wireless
infrastructure are recognized upon completion of services (i.e., as the revenue
is earned) for each completed phase of design and construction.
For additional information regarding asset and investment impairments, see PART
II, ITEM 8, Note 7 to the Progress Energy consolidated financial statements, and
Note 5 to the CP&L consolidated financial statements.
NCNG
General
NCNG transports, distributes and sells natural gas to over 108,400 residential
customers, over 14,300 commercial and agricultural customers and 472 industrial
and electric utility customers located in 110 towns and cities, primarily in
eastern and south central North Carolina. NCNG also sells and transports natural
gas to four municipal gas distribution systems that serve over 55,600 end users.
Natural gas operations are subject to the rules and regulations of the NCUC.
In 2002, the Company approved the sale of NCNG and the Company's equity
investment in Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont
Natural Gas Company, Inc. As a result of this action, the operating results of
NCNG were reclassified to discontinued operations for all reportable periods.
28
Natural Gas Supply
NCNG has long-term firm gas supply contracts with major producers and national
natural gas marketers. During 2002, NCNG purchased 11.9 million dekatherms (dt)
of natural gas under its firm sales contracts with Transcontinental Gas Pipeline
Corporation (Transco). NCNG also purchased 31.1 million dt in the spot market or
under long-term contracts with producers or natural gas marketers. Additionally,
NCNG transported 27.5 million dt of customer-owned gas in 2002. The outlook for
natural gas supplies in NCNG's service area remains favorable, and many sources
of gas are available on a firm basis.
Competition
The natural gas industry continues to evolve into a more competitive
environment. NCNG has competed successfully with other forms of energy such as
electricity, residual fuel oil, distillate fuel oil, propane and, to a lesser
extent, coal. The principal competitive considerations have been price and
accessibility. With the exception of four municipalities that operate municipal
gas distribution systems within its service territory, NCNG is the sole
distributor of natural gas in our franchised service territory.
Currently, NCNG's residential and commercial customers receive services under a
bundled rate, which includes charges for both the cost of gas and its delivery
to the customer. Unbundling of the services to commercial and residential
customers could increase competition for commodity sales services, but not for
the distribution of natural gas. Since NCNG does not earn any margin or income
from the commodity sale of natural gas, separating the cost of gas from the cost
of its delivery will not impact the operations. NCNG does not expect the NCUC to
require further unbundling in the near future. NCNG has adopted a policy that
requires that it have a balanced gas supply portfolio that provides security of
supply at the lowest reasonable cost, as determined by the NCUC in all of the
prior annual prudency reviews.
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 72 municipalities in which NCNG
distributes natural gas. The expiration dates of those franchises that have
specific expiration provisions range from 2004 to 2020. Franchise agreements
with the towns of Kinston and Wilmington will expire in 2004; new agreements
will be presented to the towns in advance of the expiration date. The franchises
are substantially uniform in nature. They contain no restrictions of a
materially burdensome nature and are adequate for NCNG's business. In addition,
NCNG serves 36 communities from which no franchises are required.
Regulatory Matters
The NCUC regulates NCNG's rates, service area, adequacy of service, safety
standards, acquisition, extension and abandonment of facilities, accounting and
sales of securities. NCNG operates only in North Carolina and is not subject to
federal regulation as a "natural gas company" under the Natural Gas Act.
Retail Rates
On October 27, 1995, the NCUC issued an order that provides for a rate of return
of 10.09%, but did not state separately the rate of return on common equity or
the capital structure used to calculate revenue requirements. The order
established several new rate schedules, including an economic development rate
to assist in attracting new industry to NCNG's service area and a rate to
provide standby, on-peak gas supply service to industrial and other customers
whose gas service would otherwise be interrupted.
In conjunction with CP&L's acquisition of NCNG on July 15, 1999, NCNG signed a
joint stipulation agreement with the NCUC in which NCNG agreed to cap margin
rates for gas sales and transportation services, with limited exceptions,
through November 1, 2003. The Company believes that this agreement will not have
a material adverse effect on the results of operations, financial condition or
cash flows. In February 2002, NCNG filed a general rate case with the NCUC
requesting an annual rate increase of $47.6 million. On May 3, 2002, NCNG
withdrew the application, based upon the NCUC Public Staff's and other parties'
interpretation of the order approving the merger of CP&L and NCNG that such a
case was not permitted until 2003. On May 16, 2002, NCNG filed a request to
increase its margin rates and rebalance its rates with the NCUC, requesting an
annual rate increase of $4.1 million to recover costs associated with specific
system improvements. On September 23, 2002, the NCUC issued its order approving
29
the $4.1 million rate increase. The rate increase was effective October 1, 2002.
NCNG plans to file another general rate case with the NCUC in spring of 2003.
NCNG anticipates that new rates, if approved, will go into effect in November
2003, after the terms of the joint stipulation agreement expire.
Environmental Matters
There are five former MGP sites associated with NCNG that have or are
anticipated to have investigation or remediation costs associated with them. As
of December 31, 2002, NCNG has accrued approximately $2.8 million for probable
and reasonably estimable remediation costs at these sites. These accruals have
been recorded on an undiscounted basis. NCNG measures its liability for these
sites based on available evidence including its experience in investigation and
remediation of contaminated sites, which also involves assessing and developing
cost-sharing arrangements with other potentially responsible parties. NCNG does
not believe it can provide an estimate of the reasonably possible total
remediation costs beyond the accrual because two of the five sites associated
with NCNG have not begun investigation activities. Therefore, NCNG cannot
currently determine the total costs that may be incurred in connection with the
investigation and/or remediation of all sites. Based upon current information,
the Company does not expect the future costs at the NCNG sites to be material to
the Company's financial condition or results of operations. On October 16, 2002,
the Company announced plans to sell NCNG to Piedmont Natural Gas Company, Inc.
See PART II, ITEM 8, Note 3A to the Progress Energy consolidated financial
statements. The Company will retain the environmental liability associated with
the five former MGP sites.
OTHER
Expansion Projects
In October 1999, CP&L and the Albemarle Pamlico Economic Development Corporation
(APEC) announced its intention to build an 850-mile, $197.5 million, natural gas
transmission and distribution system to 14 unserved counties in eastern North
Carolina. In furtherance of this project, Progress Energy and APEC formed ENCNG.
Progress Energy and APEC are joint owners of ENCNG, which is a public utility
subject to the rules and regulations of the NCUC. ENCNG contracted with CP&L to
construct, operate and maintain both the transmission and distribution systems.
ENCNG contracted with APEC to provide various services as well, including but
not limited to, managing all municipal and county franchise issues, marketing
and economic development and ensuring that the new facilities are built in the
most advantageous locations to promote development of the economic base in the
region. In conjunction with this project, ENCNG filed a request with the NCUC
for $186 million of a $200 million state bond package established for natural
gas infrastructure to pay for the portion of the project that likely could not
be recovered from future gas customers through rates. On June 15, 2000, the NCUC
issued an order awarding ENCNG an exclusive franchise to all 14 counties and, in
a further order issued on July 12, 2000, granted $38.7 million in state bond
funding for phase one of the project. Phase one, which will cost a total of
$50.5 million, extends gas service to six of the 14 counties. By order issued
June 7, 2001 the NCUC approved construction of phases two through seven of the
project which addresses the remaining eight counties and awarded ENCNG an
additional $149.6 million to finance the construction of the facilities
associated with these phases. ENCNG has substantially completed phase one of the
project and has begun construction of phase two and a portion of phase seven of
the project and expects to complete that work in the spring of 2003. ENCNG
expects to begin construction of a portion of phase three of the project in the
spring of 2003 and to begin construction of phases four and five before the end
of 2003 and phase six in early 2004. ENCNG expects to begin construction of the
remaining portions of phases three and seven in 2004 and to complete all
construction work in early 2005. ENCNG has also begun marketing natural gas
service to prospective customers in phases one and two and has begun providing
natural gas service to more than 225 customers in the phase one area.
Progress Energy agreed to fund a portion of the project, which is currently
estimated to be approximately $22 million. On October 16, 2002, Progress Energy
announced plans to sell its interest in ENCNG to Piedmont Natural Gas Company,
Inc. Upon closing of the sale, Progress Energy would have no further obligation
to fund a portion of the project and any funding obligations then outstanding
would transfer to Piedmont Natural Gas Company, Inc. See PART II, ITEM 8, Note
3A to the Progress Energy Financial Statements. CP&L's contract to construct,
operate and maintain ENCNG's transmission and distribution system would also be
assigned to Piedmont upon closing of the sale.
30
ELECTRIC UTILITY OPERATING STATISTICS - PROGRESS ENERGY
Years Ended December 31
2002 2001 2000 (d) 1999 1998
------------ ---------- ----------- ----------- -----------
Energy supply (millions of kWh)
Generated - Steam 49,734 48,732 31,132 28,260 27,576
Nuclear 30,126 27,301 23,857 22,451 22,014
Hydro 491 245 441 520 790
Combustion Turbines/Combined Cycle 8,522 6,644 1,337 435 386
Purchased 14,305 14,469 5,724 5,132 5,675
------------ ---------- ----------- ----------- -----------
Total energy supply (Company share) 103,178 97,391 62,491 56,798 56,441
Jointly-owned share (a) 5,258 4,886 4,505 4,353 4,349
------------ ---------- ----------- ----------- -----------
Total system energy supply 108,436 102,277 66,996 61,151 60,790
============ ========== =========== =========== ===========
Average fuel cost (per million Btu)
Fossil $ 2.62 $ 2.46 $ 1.96 $ 1.75 $ 1.71
Nuclear fuel $ 0.44 $ 0.45 $ 0.45 $ 0.46 $ 0.46
All fuels $ 1.84 $ 1.77 $ 1.30 $ 1.16 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 33,993 31,976 15,365 13,348 13,207
Commercial 23,887 23,033 12,221 11,068 10,646
Industrial 16,924 17,204 14,762 14,568 14,899
Other Retail 4,287 4,149 1,626 1,359 1,357
Wholesale 19,204 17,715 15,012 14,526 14,461
Unbilled 276 (1,045) 1,098 (110) (94)
------------ ---------- ----------- ----------- -----------
Total energy sales 98,571 93,032 60,084 54,759 54,476
Company uses and losses 3,604 3,478 2,286 2,039 1,964
------------ ---------- ----------- ----------- -----------
Total energy requirements 102,175 96,510 62,370 56,798 56,440
============ ========== =========== =========== ===========
Electric revenues (in thousands)
Retail $ 5,515,306 $ 5,461,469 $ 2,799,422 $ 2,530,562 $ 2,536,693
Wholesale 880,583 922,719 664,847 556,079 548,137
Miscellaneous revenue 204,800 172,373 81,425 59,517 65,099
------------ ---------- ----------- ----------- -----------
Total electric revenues $ 6,600,689 $ 6,556,561 $ 3,545,694 $ 3,146,158 $ 3,149,929
============ ========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System (b) 20,365 19,166 18,874 10,948 10,529
Company 19,746 18,564 18,272 10,344 9,875
Total regulated capability at year-end (thousands of kW)
Fossil plants 16,006 15,826 (e) 14,747 6,736 6,571
Nuclear plants 4,127 (f) 4,008 4,008 3,174 3,174
Hydro plants 218 218 218 218 218
Purchased 2,929 2,890 2,278 1,088 1,538
------------ ---------- ----------- ----------- -----------
Total system capability 23,280 22,942 21,251 11,216 11,501
Less jointly-owned portion (c) 682 668 662 593 593
------------ ---------- ----------- ----------- -----------
Total Company capability - regulated 22,598 22,274 20,589 10,623 10,908
============ ========== =========== =========== ===========
(a) Amounts represent co-owner's share of the energy supplied from the six
generating facilities that are jointly owned.
(b) For 2002, 2001 and 2000, this represents the combined summer non-coincident
system net peaks for CP&L and Florida. Power.
(c) For CP&L, this represents Power Agency's retained share of jointly-owned
facilities per the Power Coordination Agreement between CP&L and Power
Agency.
(d) Amounts include information for Florida Power since November 30, 2000, the
date of acquisition.
(e) Amount includes Rowan units that were transferred to PVI in February 2002.
(f) Amount includes power upgrades for Harris, Brunswick 1 and Robinson. The
Maximum Dependable Capability (MDC) for Harris was restated January 2002;
the MDCs for Brunswick 1 and Robinson were restated January 2003.
31
OPERATING STATISTICS - CAROLINA POWER & LIGHT COMPANY
Years Ended December 31
2002 2001 2000 1999 1998
----------- ----------- ----------- ----------- -----------
Energy supply (millions of kWh)
Generated - Steam 28,547 27,913 29,520 28,260 27,576
Nuclear 23,425 21,321 23,275 22,451 22,014
Hydro 491 245 441 520 790
Combustion Turbines/Combined Cycle 1,934 802 733 435 386
Purchased 5,213 5,296 4,878 5,132 5,675
----------- ----------- ----------- ----------- -----------
Total energy supply (Company share) 59,610 55,577 58,847 56,798 56,441
Power Agency share (a) 4,659 4,348 4,505 4,353 4,349
----------- ----------- ----------- ----------- -----------
Total system energy supply 64,269 59,925 63,352 61,151 60,790
=========== =========== =========== =========== ===========
Average fuel cost (per million Btu)
Fossil $ 2.16 $ 1.91 $ 1.83 $ 1.75 $ 1.71
Nuclear fuel $ 0.43 $ 0.44 $ 0.45 $ 0.46 $ 0.46
All fuels $ 1.38 $ 1.26 $ 1.21 $ 1.16 $ 1.14
Energy sales (millions of kWh)
Retail
Residential 15,239 14,372 14,091 13,348 13,207
Commercial 12,468 11,972 11,432 11,068 10,646
Industrial 13,089 13,332 14,446 14,568 14,899
Other Retail 1,437 1,423 1,423 1,359 1,357
Wholesale 15,024 12,996 14,582 14,526 14,461
Unbilled 270 (534) 679 (110) (94)
----------- ----------- ----------- ----------- -----------
Total energy sales 57,527 53,561 56,653 54,759 54,476
Company uses and losses 2,081 2,017 2,194 2,039 1,964
----------- ----------- ----------- ----------- -----------
Total energy requirements 59,608 55,578 58,847 56,798 56,440
=========== =========== =========== =========== ===========
Electric revenues (in thousands)
Retail $ 2,795,788 $ 2,665,857 $ 2,608,727 $ 2,530,562 $ 2,536,693
Wholesale 650,884 634,009 577,279 556,079 548,137
Miscellaneous revenue 92,285 43,854 122,209 59,518 65,099
----------- ----------- ----------- ----------- -----------
Total electric revenues $ 3,538,957 $ 3,343,720 $ 3,308,215 $ 3,146,159 $ 3,149,929
=========== =========== =========== =========== ===========
Peak demand of firm load (thousands of kW)
System 11,977 11,376 11,157 10,948 10,529
Company 11,358 10,774 10,555 10,344 9,875
Total capability at year-end (thousands of kW)
Fossil plants 8,816 8,648 (c) 7,569 6,891 6,571
Nuclear plants 3,293 (d) 3,174 3,174 3,174 3,174
Hydro plants 218 218 218 218 218
Purchased 1,617 1,586 978 1,088 1,538
----------- ----------- ---------- ----------- -----------
Total system capability 13,944 13,626 11,939 11,371 11,501
Less Power Agency-owned portion (b) 613 599 593 593 593
----------- ----------- ---------- ----------- -----------
Total Company capability 13,331 13,027 11,346 10,778 10,908
=========== =========== ========== =========== ===========
(a) Amounts represent Power Agency's share of the energy supplied from the four
generating facilities that are jointly owned.
(b) Amounts represent Power Agency's retained share of jointly-owned facilities
per the Power Coordination Agreement between CP&L and Power Agency.
(c) Amount includes Rowan units that were transferred to PVI in February 2002.
(d) Amount includes power upgrades for Harris, Brunswick 1 and Robinson. The
MDC for Harris was restated January 2002; the MDCs for Brunswick 1 and
Robinson were restated January 2003.
32
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, 2002, CP&L's eighteen generating plants represent a flexible
mix of fossil, nuclear, hydroelectric, combustion turbines and combined cycle
resources, with a total summer generating capacity (including Power Agency's
share) of 12,327 MW. At December 31, 2002, CP&L had the following generating
facilities:
- ---------------------------------------------------------------------------------------------------------------
CP&L Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- ---------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Asheville Skyland, NC 2 1964-1971 Coal 100 392
Cape Fear Moncure, NC 2 1956-1958 Coal 100 316
Lee Goldsboro, NC 3 1952-1962 Coal 100 407
Mayo Roxboro, NC 1 1983 Coal 83.83 745 (b)
Robinson Hartsville, SC 1 1960 Coal 100 174
Roxboro Roxboro, NC 4 1966-1980 Coal 96.32 (f) 2,462 (b)
Sutton Wilmington, NC 3 1954-1972 Coal 100 613
Weatherspoon Lumberton, NC 3 1949-1952 Coal 100 176
-------- ------------
Total 19 5,285
COMBINED CYCLE
Cape Fear Moncure, NC 2 1969 Oil 100 84
Richmond Hamlet, NC 1 2002 Gas/Oil 100 472
-------- ------------
Total 3 556
COMBUSTION TURBINES
Asheville Skyland, NC 2 1999-2000 Gas/Oil 100 330
Blewett Lilesville, NC 4 1971 Oil 100 52
Darlington Hartsville, SC 13 1974-1997 Gas/Oil 100 812
Lee Goldsboro, NC 4 1968-1971 Oil 100 91
Morehead City Morehead City, NC 1 1968 Oil 100 15
Richmond Hamlet, NC 5 2001-2002 Gas/Oil 100 775
Robinson Hartsville, SC 1 1968 Gas/Oil 100 15
Roxboro Roxboro, NC 1 1968 Oil 100 15
Sutton Wilmington, NC 3 1968-1969 Oil 100 64
Wayne County Goldsboro, NC 4 2000 Gas/Oil 100 668
Weatherspoon Lumberton, NC 4 1970-1971 Oil 100 138
-------- ------------
Total 42 2,975
NUCLEAR
Brunswick Southport, NC 2 1975-1977 Uranium 81.67 1,683 (b)(c)
Harris New Hill, NC 1 1987 Uranium 83.83 900 (b)(d)
Robinson Hartsville, SC 1 1971 Uranium 100 710 (e)
-------- ------------
Total 4 3,293
HYDRO
Blewett Lilesville, NC 6 1912 Water 100 22
Marshall Marshall, NC 2 1910 Water 100 5
Tillery Mount Gilead, NC 4 1928-1960 Water 100 86
Walters Waterville, NC 3 1930 Water 100 105
-------- ------------
Total 15 218
TOTAL 83 12,327
- ---------------------------------------------------------------------------------------------------------------
(a) Amounts represent CP&L's net summer peak rating, gross of co-ownership
interest in plant capacity.
(b) Facilities are jointly owned by CP&L and Power Agency. The capacities shown
include Power Agency's share.
(c) During 2002, a power uprate increased the summer net capability of Unit 1
to 872 MW. The MDC was restated in January 2003.
(d) During 2001, a power uprate increased the summer net capability of this
facility to 900 MW. The MDC was restated in January 2002.
(e) During 2002, a power uprate increased the summer net capability of this
facility to 710 MW. The MDC was restated January 2003.
(f) CP&L and Power Agency are co-owners of Unit 4 at the Roxboro Plant. CP&L's
ownership interest in this 700 MW turbine is 87.06%.
33
As of December 31, 2002, including both the total generating capacity of 12,327
MW and the total firm contracts for purchased power of approximately 1,617 MW,
CP&L had total capacity resources of approximately 13,944 MW.
The Power Agency has acquired undivided ownership interests of 18.33% in
Brunswick Unit Nos. 1 and 2, 12.94%, in Roxboro Unit No. 4 and 16.17% in the
Harris Plant and Mayo Unit No. 1. Otherwise, CP&L has good and marketable title
to its principal plants and important units, subject to the lien of its mortgage
and deed of trust, with minor exceptions, restrictions, and reservations in
conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. CP&L also owns certain easements
over private property on which transmission and distribution lines are located.
As of December 31, 2002, CP&L had approximately 6,000 pole miles of transmission
lines including about 300 miles of 500 kilovolt (kV) lines and about 3,000 miles
of 230 kV lines. CP&L had distribution lines of approximately 45,000 pole miles
of overhead lines and about 16,000 miles of underground lines. Distribution and
transmission substations in service had a transformer capacity of approximately
47,000,000 kilovolt-ampere (kVA) in 823 transformers. Distribution line
transformers numbered 495,501 with an aggregate capacity of about 20,000,000
kVA.
ELECTRIC - FLORIDA POWER
As of December 31, 2002, Florida Power's 14 generating plants represent a
flexible mix of fossil, nuclear, combustion turbine and combined cycle resources
with a total summer generating capacity (including jointly-owned capacity) of
8,024 MW. At December 31, 2002, Florida Power had the following generating
facilities:
- -----------------------------------------------------------------------------------------------------------
Florida Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- -----------------------------------------------------------------------------------------------------------
STEAM TURBINES
Anclote Holiday, FL 2 1974-1978 Gas/Oil 100 993
Bartow St. Petersburg, FL 3 1958-1963 Gas/Oil 100 444
Crystal River Crystal River, FL 4 1966-1984 Coal 100 2,302
Suwannee River Live Oak, FL 3 1953-1956 Gas/Oil 100 143
------- ---------------
Total 12 3,882
COMBINED CYCLE
Hines Bartow, FL 1 1999 Gas/Oil 100 482
Tiger Bay Fort Meade, FL 1 1997 Gas 100 207
------- ---------------
Total 2 689
COMBUSTION TURBINES
Avon Park Avon Park, FL 2 1968 Gas/Oil 100 52
Bartow St. Petersburg, FL 4 1958-1972 Gas/Oil 100 187
Bayboro St. Petersburg, FL 4 1973 Oil 100 184
DeBary DeBary, FL 10 1975-1992 Gas/Oil 100 667
Higgins Oldsmar, FL 4 1969-1970 Gas 100 122
Intercession City Intercession City, 14 1974-2000 Gas/Oil 100 (c) 1,041 (b)
FL
Rio Pinar Rio Pinar, FL 1 1970 Oil 100 13
Suwannee River Live Oak, FL 3 1980 Gas/Oil 100 164
Turner Enterprise, FL 4 1970-1974 Oil 100 154
University of Gainesville, FL 1 1994 Gas 100 35
Florida
Cogeneration
------- ---------------
Total 47 2,619
NUCLEAR
Crystal River Crystal River, FL 1 1977 Uranium 91.78 834 (b)
------- ---------------
Total 1 834
TOTAL 62 8,024
- -----------------------------------------------------------------------------------------------------------
(a) Amounts represent Florida Power's net summer peak rating, gross of
co-ownership interest in plant capacity.
(b) Facilities are jointly owned. The capacities shown include joint owners'
share.
(c) 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 (P11). 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. Additionally, during
2002, power uprates on units P12, P13 and P14 increased the summer net
capability of this facility to 1,041 MW.
As of December 31, 2002, including both the total generating capacity of 8,024
MW and the total firm contracts for purchased power of 1,304 MW, Florida Power
had total capacity resources of approximately 9,328 MW. Hines Unit 2 is a 516 MW
combined-cycle unit under construction and currently scheduled for completion in
late 2003.
34
Several entities have acquired undivided ownership interests in CR3 in the
aggregate amount of 8.22%. The joint ownership participants are: City of Alachua
- - 0.08%, City of Bushnell - 0.04%, City of Gainesville - 1.41%, Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New Smyrna Beach - 0.56%, City of Ocala - 1.33%, Orlando Utilities
Commission - 1.60% and Seminole Electric Cooperative, Inc. - 1.70%. Florida
Power and Georgia Power are co-owners of a 143 MW advance combustion turbine
located at Florida Power's Intercession City site (P11). 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.
Otherwise, Florida Power 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. Florida Power also owns certain easements over private property on
which transmission and distribution lines are located.
As of December 31, 2002, Florida Power distributed electricity through 370
substations with an installed transformer capacity of approximately 45,000,000
kVA. Of this capacity, about 31,000,000 kVA is located in transmission
substations and about 14,000,000 kVA in distribution substations. Florida Power
has the second largest transmission network in Florida. Florida Power has
approximately 5,000 circuit miles of transmission lines, of which about 2,600
circuit miles are operated at 500, 230 or 115 kV, and the balance at 69 kV.
Florida Power has approximately 28,000 circuit miles of distribution lines,
which operate at various voltages ranging from 2.4 to 25 kV.
PROGRESS VENTURES
The Progress Ventures business segment controls, either directly or through
business units, coal reserves located in eastern Kentucky and southwestern
Virginia. Progress Ventures owns properties that contain estimated coal reserves
of approximately 12 million tons and controls, through mineral leases,
additional estimated coal reserves of approximately 18 million tons. The
reserves controlled include substantial quantities of high quality, low sulfur
coal that is appropriate for use at Florida Power's existing generating units.
Progress Ventures' total production of coal during 2002 was approximately 2.6
million tons.
In connection with its coal operations, Progress Ventures' business units own
and operate an underground mining complex located in southeastern Kentucky and
southwestern Virginia. Other subsidiaries own and operate surface and
underground mines, coal processing and loadout facilities, a river terminal
facility in eastern Kentucky, a railcar-to-barge loading facility in West
Virginia and two bulk commodity terminals on the Kanawha River near Charleston,
West Virginia. Progress Ventures and its subsidiaries employ both company and
contract miners in their mining activities.
The Progress Ventures business segment, through its business units, owns all of
the interests in five entities and a minority interest in one entity that owns
facilities that produce synthetic fuel. These entities own a total of nine
facilities in seven different locations in West Virginia, Virginia and Kentucky.
A business unit of Progress Ventures has oil and gas leases on about 20,000
acres in Garfield and Mesa counties in Colorado, containing proven natural gas
net reserves of 98 billion cubic feet. This subsidiary currently operates 96 gas
wells on the properties. Another subsidiary of Progress Ventures has oil and gas
leases on about 35,000 acres concentrated within a 25-mile radius along the
Texas and Louisiana border, containing proven natural gas reserves of 125
billion cubic feet. This subsidiary currently operates 234 gas wells on the
properties. Progress Ventures' natural gas production in 2002 was 11.8 billion
cubic feet. The Company is exploring opportunities to divest of its Mesa
properties in 2003.
Another business unit of Progress Ventures owns and operates a manufacturing
facility at the Florida Power Energy Complex in Crystal River, Florida. The
manufacturing process utilizes the fly ash generated by the burning of coal as
the major raw material in the production of lightweight aggregate used in
construction building blocks.
35
As of December 31, 2002, PVI had the following nonregulated generation plants in
service or planned for construction.
- ----------------------------------------------------------------------------------------------------------
Construction Commercial Operation Configuration/Number
Project Start Date Date of Units MW (a)
- ----------------------------------------------------------------------------------------------------------
Monroe Units 1 and 2 4Q 1998/1Q 2000 4Q 1999/2Q 2001 Simple-Cycle, 2 315
-----------------
Total 315
Rowan Phase I (b) 1Q 2000 2Q 2001 Simple-Cycle, 3 459
Walton (c) 2Q 2000 2Q 2001 Simple-Cycle, 3 460
DeSoto Units 1 and 2 2Q 2001 2Q 2002 Simple-Cycle, 2 320
-----------------
Total 1,239
Effingham 1Q 2001 3Q 2003 (d) Combined-Cycle, 1 480
Rowan Phase II (b) 4Q 2001 2Q 2003 (d) Combined-Cycle, 1 466
Washington (c) 2Q 2002 2Q 2003 (d) Simple-Cycle, 4 600
-----------------
Total 1,546
TOTAL 3,100
- ----------------------------------------------------------------------------------------------------------
(a) Amounts represent PVI's summer rating.
(b) This project was transferred from CP&L to PVI in February 2002.
(c) This project was purchased from LG&E Energy Corp. in February 2002.
(d) Date represents the expected commercial operation date.
RAIL SERVICES
Progress Rail is one of the largest integrated processors of railroad materials
in the United States, and is a leading supplier of new and reconditioned freight
car parts; rail, rail welding and track work components; railcar repair
facilities; railcar and locomotive leasing; maintenance-of-way equipment and
scrap metal recycling. It has facilities in 26 states, Mexico and Canada.
Progress Rail owns and/or operates approximately 5,300 railcars and 100
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.
OTHER
PROGRESS TELECOM AND CARONET
Progress Telecom and Caronet provide wholesale telecommunications services
throughout the Southeastern United States. Progress Telecom and Caronet
incorporate more than 130,000 fiber miles in its network including over 160
Points-of-Presence, or physical locations where a presence for network access
exists.
NCNG
NCNG owns and operates a liquefied natural gas storage plant which provides
97,200 dt per day to NCNG's peak-day delivery capability.
NCNG owns approximately 1,329 miles of transmission pipelines of two to 30
inches in diameter which connect its distribution systems with the Texas-to-New
York transmission system of Transco and the southern end of Columbia's
transmission system. Transco delivers gas to NCNG at various points conveniently
located with respect to its distribution area. Columbia delivers gas to one
delivery point near the North Carolina - Virginia border. NCNG distributes
natural gas through its 3,096 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.
36
ITEM 3 LEGAL PROCEEDINGS
Legal and regulatory proceedings are included in the discussion of the Company's
business in PART I, ITEM 1 under "Environmental," "Regulatory Matters" and
"Nuclear Matters" and incorporated by reference herein.
1. The People of the State of California v. Strategic Resource Solutions ,
Inc., San Francisco Superior Court, SCN 187328 Court No. 2072965
Strategic Resource Solutions Corp. (SRS) was charged in a criminal
complaint filed on October 9, 2002 by the San Francisco District Attorney's
office. Working with the San Francisco District Attorney's office, SRS has
pled guilty to two charges, taking responsibility for the misconduct of one
of its former employees. This proceeding concluded on October 15, 2002.
SRS agreed to pay a fine of $500,000. Although SRS did not receive any
funds, because of the involvement of a former employee, SRS has accepted
corporate criminal responsibility and agreed to pay an additional $500,000
as a restitution. SRS was also placed on probation and will continue
cooperating with the District Attorney's investigation and prosecution of
other defendants.
This proceeding no longer meets the disclosure standards for this item,
thus the Company will no longer report on it.
2. Strategic Resource Solutions Corp. ("SRS") v. San Francisco Unified School
District, et al., Sacramento Superior Court, Case No. 02AS033114
In November of 2001, SRS filed a claim against the San Francisco Unified
School District ("the District") and other defendants claiming that SRS is
entitled to approximately $10 million in unpaid contract payments and delay
and impact damages related to the District's $30 million contract with SRS.
On March 4, 2002, the District filed a counterclaim, seeking compensatory
damages and liquidated damages in excess of $120 million, for various
claims, including breach of contract and demand on a performance bond. SRS
has asserted defenses to the District's claims.
On March 13, 2003, the City Attorney's office announced the filing of new
claims by the City Attorney and the District against SRS, Progress Energy,
Inc., Progress Energy Solutions, Inc., and certain individuals, alleging
fraud, false claims, violations of California statutes, and seeking
compensatory damages, punitive damages, liquidated damages, treble damages,
penalties, attorneys' fees and injunctive relief. The City Attorney's
announcement states that the City and the District seek "more than $300
million in damages and penalties."
The Company has reviewed the District's earlier pleadings against SRS, and
believes that those claims are not meritorious. The Company has not
reviewed the new pleadings in detail, but the Company believes that the new
claims are not meritorious and the Company will vigorously defend and
litigate all of these claims. The Company cannot predict the outcome of
this matter, but the Company believes that it and its subsidiaries have
good defenses to all claims asserted by both the District and the City.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NONE
37
EXECUTIVE OFFICERS OF THE REGISTRANTS
Name Age Recent Business Experience
William Cavanaugh III 64 Chairman and Chief Executive Officer, Progress Energy, Inc., August 1999
to present, also President, Progress Energy, Inc., August 1999 to
October 2002; Chairman, President and Chief Executive Officer, Carolina
Power & Light Company, May 1999 to present; President and Chief
Executive Officer, Carolina Power & Light Company, October 1996 to May
1999; Chairman, Progress Energy Service Company, LLC, August 2000 to
present; Chairman, Florida Power Corporation, November 30, 2000 to
present; Chairman, President and CEO, Florida Progress Corporation,
November 2000 to present; Chairman, Progress Ventures, Inc., March 2000
to present; Chairman, North Carolina Natural Gas Corporation, 1999 to
present; Chairman, Progress Capital Holdings, Inc., November 30, 2000 to
present; Chairman, Progress Fuels Corporation, November 30, 2000 to
present; Chairman, Progress Telecommunications Corporation, November 30,
2000 to present; Chairman, Strategic Resource Solutions Corp, November
1997 to December 31, 2002. Member of the Board of Directors of the
Company since 1993.
Robert B. McGehee 60 President and Chief Operating Officer, Progress Energy, Inc., October
2002 to present; Executive Vice President, Progress Energy, Inc.,
December 2000 to September 2002; Executive Vice President, Carolina
Power & Light Company and Florida Progress Corporation, December 2000 to
present; President and Chief Executive Officer, Progress Energy Service
Company, LLC, December 2000 to September 2002; Executive Vice
President, General Counsel and Chief Administrative Officer, Carolina
Power & Light Company, March 1999 to September, 2000; Senior Vice
President and General Counsel, Carolina Power & Light Company, May 1997
to March 1999. Prior to joining the Company, was a practicing attorney
with Wise Carter Child & Caraway, a law firm in Jackson, Mississippi.
He primarily handled corporation, contract, nuclear regulatory and
employment matters.
William S. Orser 58 Group President, Carolina Power & Light Company and Florida Power
Corporation, November 2000 to present; Executive Vice President,
Carolina Power & Light Company, Energy Supply, June 1998 to November
2000; Executive Vice President and Chief Nuclear Officer, Carolina Power
& Light Company, December 1996 to June 1998.
William D. Johnson 49 President, CEO and Corporate Secretary, Progress Energy Service Company,
LLC, October 2002 to present (served as Executive Vice President and
Corporate Secretary, 2000 to October 2002); Executive Vice President,
and Corporate Secretary, Progress Energy, Inc., August 1999 to present
(and General Counsel February 2001 to present); Executive Vice President
and Corporate Secretary, Florida Progress Corporation, Carolina Power &
Light Company and Florida Power Corporation, November 2000 to present;
General Counsel, Florida Progress Corporation, Carolina Power & Light
Company, Progress Energy Service Company, LLC and Florida Power
Corporation, November 2000 to October 2002; Senior Vice President and
Corporate Secretary, Carolina Power & Light Company, Legal and Risk
Management, March 1999 to November 2000; Vice President-Legal Department
and Corporate Secretary, Carolina Power & Light Company, 1997 to 1999.
38
Peter M. Scott III 53 Executive Vice President and Chief Financial Officer, Progress Energy,
Inc., May 2000 to present; Executive Vice President and CFO, Florida
Power Corporation and Florida Progress Corporation, November 2000 to
present; Executive Vice President and CFO, Progress Energy Service
Company, LLC, August 2000 to present; Executive Vice President and CFO,
Carolina Power & Light Company, May 2000 to present; Executive Vice
President and CFO, North Carolina Natural Gas Corporation, December 2000
to present. Before joining the Company, Mr. Scott was President of
Scott, Madden & Associates, Inc., a management consulting firm he
founded in 1983. The firm advises companies on key strategic
initiatives for growing shareholder value.
Robert H. Bazemore, Jr. 48 Chief Accounting Officer and Controller, Progress Energy, Inc., June
2000 to present; Controller, Florida Power Corporation and Florida
Progress Corporation, November 2000 to present; Chief Accounting
Officer, Florida Progress Corporation, November 30, 2000 to present;
Vice President and Controller, Progress Energy Service Company, LLC,
August 2000 to present; Chief Accounting Officer and Controller,
Carolina Power & Light Company, May 2000 to present; Chief Accounting
Officer, North Carolina Natural Gas Corporation, December 2000 to
present; Controller, North Carolina Natural Gas Corporation, November
2000 to December 2001; Director, Carolina Power & Light Company,
Operations & Environmental Support Department, December 1998 to May
2000; Manager, Carolina Power & Light Company, Financial & Regulatory
Accounting, September 1995 to December 1998.
*Brenda F. Castonguay 50 Senior Vice President, Progress Energy Service Company, LLC, July 2002
to present; Vice President, Progress Energy Service Company, LLC,
November 2000 to July 2002; Vice President, Human Resources, Carolina
Power & Light Company, April 1996 to July 2002.
Donald K. Davis 57 Executive Vice President, Carolina Power & Light Company, May 2000 to
present; President and Chief Executive Officer, North Carolina Natural
Gas Corporation, July 2000 to present; President and Chief Executive
Officer, Strategic Resource Solutions Corp., June 2000 to December 2002;
Executive Vice President, Florida Power Corporation, February 2001 to
present. Before joining the Company, Mr. Davis was Chairman, President
and Chief Executive Officer of Yankee Atomic Electric Company, and
served as Chairman, President and Chief Executive Officer of Connecticut
Atomic Power Company from 1997 to May 2000.
Fred N. Day, IV 59 Executive Vice President, Carolina Power & Light Company and Florida
Power Corporation, November 2000 to present; Senior Vice President,
Carolina Power & Light Company, Energy Delivery, July 1997 to November
2000; Vice President, Carolina Power & Light Company, Western Region,
1995 to July 1997.
*H. William Habermeyer, Jr. 60 President and Chief Executive Officer, Florida Power Corporation,
November 2000 to present; Vice President, Carolina Power & Light Company,
Western Region, July 1997 to November 2000.
39
*Bonnie V. Hancock 41 President, Progress Fuels Corporation, September 2002 to present, Senior
Vice President, Progress Energy Service Company, LLC, November 2000 to
September 2002; Vice President, Carolina Power & Light Company,
Strategic Planning, February 1999 to November 2000; Vice President and
Controller, Carolina Power & Light Company, February 1997 to February
1999.
C.S. Hinnant 58 Senior Vice President and Chief Nuclear Officer, Carolina Power & Light
Company, June 1998 to present; Senior Vice President, Florida Power
Corporation, December 2000 to present; Vice President, Carolina Power &
Light Company, Brunswick Nuclear Plant, April 1997 to June 1998.
Tom D. Kilgore 55 Group President, Carolina Power & Light Company, November 2000 to
present; President and CEO, Progress Ventures, Inc., March 2000 to
present; President and CEO, Progress Fuels Corporation, March 2000 to
September 2002; Senior Vice President, Carolina Power & Light Company,
Power Operations, August 1998 to November 2000; President and Chief
Executive Officer, Oglethorpe Power Corporation, July 1991 to August
1998. This company provides power generation to 39 of Georgia's 42
customer-owned Electric Membership Corporations.
*John R. McArthur 47 Senior Vice President, Progress Energy Service Company, LLC, December
2002 to present; Vice President, Progress Energy Service Company, LLC,
December 2001 to December 2002; Senior Advisor to Governor Mike Easley,
January 2001 to November 2001; Manager, Government State Relations,
General Electric, October 1997 to December 2000.
E. Michael Williams 54 Senior Vice President, Florida Power Corporation, November 2000 to
present; Senior Vice President, Carolina Power & Light Company, 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 from March 1994 to June 2000.
*Indicates individual is an executive officer of Progress Energy, Inc., but not Carolina Power & Light Company.
40
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 Stock Exchange. The
high and low intra-day stock sales prices for Progress Energy for each quarter
for the past two years, and the dividends declared per share are as follows:
2002 High Low Dividends Declared
- ---- ---- --- ------------------
First Quarter $50.86 $43.01 $0.545
Second Quarter 52.70 47.91 0.545
Third Quarter 51.97 36.54 0.545
Fourth Quarter 44.82 32.84 0.560
2001 High Low Dividends Declared
- ---- ---- --- ------------------
First Quarter $49.25 $38.78 $0.530
Second Quarter 45.00 40.36 0.530
Third Quarter 45.79 39.25 0.530
Fourth Quarter 45.60 40.50 0.545
The December 31 closing price of the Company's Common Stock was $43.35 for 2002
and $45.03 for 2001.
As of February 28, 2003, the Company had 72,380 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.
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's subsidiaries.
RESTRICTED STOCK AWARDS:
(a) Securities Delivered. On December 11, 2002, 23,700 restricted shares of the
Company's Common Shares were granted to certain key employees pursuant to
the terms of the Company's 2002 Equity Incentive Plan (Equity Incentive
Plan), which was approved by the Company's shareholders on May 8, 2002.
Section 9 of the Equity Incentive Plan provides for the granting of
Restricted Stock by the Organization and Compensation Committee of the
Company's Board of Directors (the Committee) to key employees of the
Company, including its Affiliates or any successor, and to outside
directors of the Company. The Common Shares delivered pursuant to the
Equity Incentive Plan were acquired in market transactions directly for the
accounts of the recipients and do not represent newly issued shares of the
Company.
(b) Underwriters and Other Purchasers. No underwriters were used in connection
with the delivery of Common Shares described above. The Common Shares were
delivered to certain key employees of the Company. The Equity Incentive
Plan defines "key employee" as an officer or other employee of the Company
who is selected for participation in the Equity Incentive Plan.
(c) Consideration. The Common Shares were delivered to provide an incentive to
the employee recipients to exert their utmost efforts on the Company's
behalf and thus enhance the Company's performance while aligning the
employee's interest with those of the Company's shareholders.
(d) Exemption from Registration Claimed. The Common Shares described in this
Item were delivered on the basis of an exemption from registration under
Section 4(2) of the Securities Act of 1933. Receipt of the Common Shares
required no investment decision on the part of the recipients. All award
decisions were made by the Committee, which consists entirely of
non-employee directors.
41
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.
Years Ended December 31
2002 (a) 2001 (a) 2000 (a)(b) 1999 (a) 1998
------------- ------------ ------------- -------------- -----------
(dollars in thousands, except per share data)
Operating results
Operating revenues $ 7,945,120 $ 8,085,380 $ 3,768,922 $ 3,264,957 $ 3,211,552
Income from continuing
operations $ 552,169 $ 540,396 $ 477,922 $ 383,299 $ 396,271
Net Income $ 528,386 $ 541,610 $ 478,361 $ 379,288 $ 396,271
Per share data
Basic earnings
Income from continuing
operations $ 2.54 $ 2.64 $ 3.04 $ 2.58 $ 2.75
Net income $ 2.43 $ 2.65 $ 3.04 $ 2.56 $ 2.75
Diluted
Income from continuing
operations $ 2.53 $ 2.63 $ 3.03 $ 2.58 $ 2.75
Net income $ 2.42 $ 2.64 $ 3.03 $ 2.55 $ 2.75
Dividends declared per common
share $ 2.195 $ 2.135 $ 2.075 $ 2.015 $ 1.955
Assets $ 21,352,704 $ 20,890,701 $ 20,222,792 $ 9,493,866 $ 8,401,406
Capitalization
Common stock equity $ 6,677,009 $ 6,003,533 $ 5,424,201 $ 3,412,647 $ 2,949,305
Preferred stock - redemption
not required 92,831 92,831 92,831 59,376 59,376
Long-term debt, net 9,747,293 8,618,960 4,903,803 2,161,761 2,126,414
Current portion of long-term debt 275,397 688,052 184,037 197,250 53,172
Short-term obligations 694,850 942,314 4,958,971 1,035,040 488,000
------------ ------------ -------------- -------------- -----------
Total capitalization and total debt $ 17,487,380 $ 16,345,690 $ 15,563,843 $ 6,866,074 $ 5,676,267
============ ============ ============== ============== ===========
(a) Operating results and balance sheet data have been restated for
discontinued operations.
(b) Operating results and balance sheet data includes information for FPC since
November 30, 2000, the date of acquisition.
42
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.
Years Ended December 31
2002 2001 2000 (a)(b) 1999 (b) 1998
----------- ------------ -------------- ------------- -----------
(dollars in thousands)
Operating results
Operating revenues $ 3,553,820 $ 3,360,161 $ 3,528,446 $ 3,364,927 $ 3,211,552
Net income $ 430,932 $ 364,231 $ 461,028 $ 382,255 $ 399,238
Earnings for common stock $ 427,968 $ 361,267 $ 458,062 $ 379,288 $ 396,271
Assets $ 8,974,684 $ 9,258,685 $ 9,239,486 $ 9,494,019 $ 8,401,406
Capitalization
Common stock equity $ 3,089,115 $ 3,095,456 $ 2,852,038 $ 3,412,647 $ 2,949,305
Preferred stock - redemption
not required 59,334 59,334 59,334 59,376 59,376
Long-term debt, net 3,048,466 2,698,318 3,133,687 2,161,761 2,126,414
Current portion of long-term debt - 600,000 - 197,250 53,172
Short-term obligations (c) 437,750 308,448 486,297 1,035,040 488,000
----------- ------------ -------------- -------------- -----------
Total capitalization and total debt $ 6,634,665 $ 6,761,556 $ 6,531,356 $ 6,866,074 $ 5,676,267
=========== ============ ============== ============== ===========
(a) Operating results and balance sheet data do not include information for
NCNG, SRS, Monroe Power or PVI 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 include NCNG results for the period July 15, 1999 to July
1, 2000. Balance sheet data includes NCNG for December 31, 1999.
(c) Includes notes payable to affiliated companies of $47.9 million at December
31, 2001.
43
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
the "Risk Factors" section and "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for
a discussion of the factors that may impact any such forward-looking statements
made herein.
RESULTS OF OPERATIONS
For 2002 as compared to 2001 and 2001 as compared to 2000
In this section, earnings and the factors affecting earnings are discussed. The
discussion begins with a general overview, then separately discusses earnings by
business segment.
Overview
Progress Energy, Inc. (Progress Energy or the Company) is a registered holding
company under the Public Utility Holding Company Act of 1935 (PUHCA), as
amended. Progress Energy and its subsidiaries are subject to the regulatory
provisions of PUHCA. Progress Energy was formed as a result of the
reorganization of Carolina Power & Light Company (CP&L) into a holding company
structure on June 19, 2000. All shares of common stock of CP&L were exchanged
for an equal number of shares of CP&L Energy, Inc., the newly created holding
company. On December 4, 2000, CP&L Energy, Inc. changed its name to Progress
Energy, Inc.
The Company acquired Florida Progress Corporation (FPC) on November 30, 2000.
The acquisition was accounted for using the purchase method of accounting. As a
result, the consolidated financial statements only reflect FPC's operations
subsequent to November 30, 2000.
Through its wholly owned regulated subsidiaries, CP&L and Florida Power
Corporation (Florida Power), Progress Energy is primarily engaged in the
generation, transmission, distribution and sale of electricity in portions of
North Carolina, South Carolina and Florida. Through the Progress Ventures
business segment, Progress Energy is involved in nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing and delivery; and energy marketing and trading activities. Through
the Rail Services business segment, Progress Energy engages in various rail and
railcar related services. Through the Other business segment, Progress Energy
engages in other nonregulated business areas including telecommunications and
holding company operations.
Effective January 1, 2003, CP&L, Florida Power and Progress Ventures, Inc. (PVI)
began doing business under the names Progress Energy Carolinas, Inc., Progress
Energy Florida, Inc., and Progress Energy Ventures, Inc., respectively. The
legal names of these entities have not changed and there is no restructuring of
any kind related to the name change. The current corporate and business unit
structure remains unchanged.
In 2002, the operations of North Carolina Natural Gas Corporation (NCNG),
previously reported in the Other segment, were reclassified to discontinued
operations and therefore were not included in the results from continuing
operations during the periods reported. See Note 3A to the Progress Energy
consolidated financial statements for discussion of the planned divestiture.
Progress Energy is an integrated energy company located principally in the
southeast region of the United States. The Company has more than 21,900
megawatts of generation capacity and serves approximately 3.0 million electric
and natural gas customers in portions of North Carolina, South Carolina and
Florida. CP&L's and Florida Power's utility operations are complementary, as
CP&L has a summer peaking demand, while Florida Power has a winter peaking
demand. In addition, CP&L's greater proportion of commercial and industrial
customers combined with Florida Power's greater proportion of residential
customers creates a more balanced customer base. The Company is dedicated to
delivering reliable, competitively priced energy.
In 2002, Progress Energy's net income was $528.4 million, a 2.4% decrease from
$541.6 million in 2001. Income from continuing operations was $552.2 million and
$540.4 million for 2002 and 2001, respectively. The decrease in net income in
2002 is primarily due to:
o $288.7 million of after-tax impairments and other charges (Progress Telecom,
Caronet and Interpath Communications, Inc.), estimated impairment on assets
held for sale (Railcar Ltd.), and discontinued operations (NCNG) in 2002;
o the rate case settlement of Florida Power (one-time retroactive rate
reduction of $21.0 million after tax combined with a 9.25% prospective rate
reduction);
44
o increased operating expenses of $16.7 million after tax at CP&L related to
the ice storm in December 2002, and
o increased benefit costs and a lower pension credit, primarily at the
electric utilities.
Partially offsetting these items were:
o continued retail customer growth and usage (including weather impacts) at
the electric utilities;
o lower depreciation expense related to the Florida rate case settlement;
o $152.8 million of after-tax impairments and other charges attributable to
Strategic Resource Solutions Corp. (SRS) and Interpath Communications, Inc.
(Interpath) in 2001;
o impact of the change in market value of contingent value obligations of
$28.1 million;
o lower interest charges primarily at CP&L, and
o the elimination of goodwill amortization in 2002.
Basic earnings per share from net income decreased from $2.65 per share in 2001
to $2.43 per share in 2002 due to the factors outlined above and also from an
increase in the number of shares outstanding resulting from the common stock
issuances in 2001 and 2002. See Note 14 to the Progress Energy consolidated
financial statements for more information on the Company's common stock.
Net income in 2001 rose $63.2 million or 13.2% when compared to the 2000 net
income of $478.4 million. The increase in net income in 2001 is due primarily to
a full year of FPC's operations being included in the 2001 results, as FPC
contributed net income of $398.3 million for the year ended December 31, 2001.
Other factors contributing to the increase in net income in 2001 included
increases in tax credits from Progress Energy's share of synthetic fuel
facilities, continued customer growth at the electric utilities and decreases in
depreciation expense related to CP&L's accelerated cost recovery program.
Partially offsetting these increases were impairment and other after-tax charges
totaling $152.8 million, primarily attributable to SRS and the Company's
investment in Interpath, as well as increases in interest expense, goodwill
amortization related to the FPC acquisition and the impact of unfavorable
weather. Basic earnings per share decreased from $3.04 per share in 2000 to
$2.65 per share in 2001 due to the factors outlined above and also from an
increase in the number of shares outstanding resulting from the FPC acquisition
and an additional common stock issuance in August 2001.
Electric Segments
The electric segments are primarily engaged in the generation, transmission,
distribution and sale of electricity in portions of North Carolina and South
Carolina by CP&L Electric, and since November 30, 2000, in portions of Florida
by Florida Power Electric. CP&L Electric serves an area of approximately 34,000
square miles, with a population of more than 4.0 million. As of December 31,
2002, CP&L Electric provided electricity to approximately 1.3 million customers.
Florida Power Electric serves an area of approximately 20,000 square miles, with
a population of more than 5.0 million. As of December 31, 2002, Florida Power
Electric provided electricity to approximately 1.5 million customers.
The operating results of both electric utilities are primarily influenced by
customer demand for electricity, the ability to control costs and regulatory
return on equity. Annual demand for electricity is based on the number of
customers and their annual usage, with usage largely impacted by weather. In
addition, the current economic conditions in the service territories may impact
the annual demand for electricity.
CP&L Electric
CP&L Electric contributed net income of $513.1 million, $468.3 million and
$373.8 million in 2002, 2001 and 2000, respectively. Included in these amounts
are wholesale energy marketing activities and immaterial trading activities,
which are managed by Progress Ventures on behalf of CP&L Electric, that
contributed net income of $60.0 million, $62.7 million, and $84.0 million in
2002, 2001 and 2000, respectively.
45
Revenues
CP&L's electric revenues for the years ended December 31, 2002, 2001 and 2000
and the percentage change by year and by customer class are as follows (in
millions):
---------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000
---------------------------------------------------------------------------------------------------
Residential $1,241 7.7% $1,152 3.5% $1,113
Commercial 832 6.0 785 5.9 741
Industrial 645 (1.4) 654 (3.7) 679
Governmental 78 4.0 75 (1.3) 76
------------- ------------- -------------
Total Retail Revenues 2,796 4.9 2,666 2.2 2,609
Wholesale 651 2.7 634 9.9 577
Unbilled 15 - (32) - 51
Miscellaneous 77 1.3 76 7.0 71
------------- ------------- -------------
Total Electric Revenues $3,539 5.8% $3,344 1.1% $3,308
---------------------------------------------------------------------------------------------------
CP&L's electric energy sales for 2002, 2001 and 2000 and the percentage change
by year and by customer class are as follows (in thousands of mWh):
---------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000
---------------------------------------------------------------------------------------------------
Residential 15,239 6.0% 14,372 2.0% 14,091
Commercial 12,468 4.1 11,972 4.7 11,432
Industrial 13,089 (1.8) 13,332 (7.7) 14,446
Governmental 1,437 1.0 1,423 - 1,423
------------- -------------- -------------
Total Retail Energy Sales 42,233 2.8 41,099 (0.7) 41,392
Wholesale 15,024 15.6 12,996 (10.9) 14,582
Unbilled 270 - (534) - 679
------------- -------------- -------------
Total mWh sales 57,527 7.4% 53,561 (5.5%) 56,653
---------------------------------------------------------------------------------------------------
CP&L's electric revenues increased $195.2 million from 2001 to 2002. During
2002, residential and commercial sales reflected continued growth in the number
of customers served by CP&L Electric, with approximately 26,000 new customers in
2002. Sales of energy and revenue increased in 2002 compared to 2001 for all
customer classes except industrial. Increases in retail sales of $129.9 million
and wholesale sales of $16.9 million were also driven by favorable weather
during 2002 when compared to 2001. Wholesale sales growth was partially offset
by price declines in the wholesale market.
Downturns in the economy during 2001 and continuing into 2002 impacted energy
usage throughout most of the industrial customer class. Total industrial revenue
declined during 2002 by $9.1 million and during 2001 by $25.0 million as the
number of industrial customers decreased due to a slowdown in the textile
industry, as well as a decrease in usage in the chemical industry.
Compared to 2000, 2001 residential and commercial revenues reflected continued
growth in the number of customers served by CP&L Electric partially offset by
milder weather in 2001. CP&L Electric added over 30,500 new customers in 2001.
Milder weather in 2001 accounted for a decrease in retail revenue of $63.0
million for the year compared to 2000. Total kWh sales to wholesale customers
decreased in 2001 from 2000 primarily due to mild weather. However, revenues
from wholesale customers increased in 2001 over 2000 due to the establishment of
new long-term contracts and the receipt of a termination payment on a long-term
contract in December 2001.
Expenses
CP&L Electric's fuel expense increased $114.1 million in 2002, when compared to
$647.3 million in 2001, primarily due to an 8.2% increase in generation with a
higher percentage of generation being produced by combustion turbines, which
have higher fuel costs. CP&L Electric's fuel expense increased $19.8 million in
2001 compared to $627.5 million in 2000 primarily due to increases in the price
of coal, partially offset by decreases in generation.
For 2002, purchased power decreased $6.1 million, when compared to $353.6
million in 2001, mainly due to decreases in price and volume purchased. For
2001, purchased power increased $28.2 million when compared to $325.4 million in
2000 mainly due to favorable market conditions in the first quarter of 2001.
46
Fuel expenses are recovered primarily through cost recovery clauses and, as
such, have no material impact on operating results.
CP&L Electric's total operations and maintenance expenses increased $91.0
million in 2002 when compared to $701.7 million in 2001 primarily due to storm
costs of $27.2 million (see below), a lower pension credit of $6.0 million, the
establishment of an inventory reserve of $10.5 million for materials that have
no future benefit, increased salaries and benefits and other increases in
maintenance and outage support. CP&L Electric's operations and maintenance
expenses decreased $24.6 million in 2001 when compared to $726.3 million in
2000, primarily due to the absence of restoration costs associated with the
severe winter storm and record-breaking snowfall in January 2000, as well as
cost control efforts. These amounts were partially offset by increases in
planned nuclear outage costs and transmission expenses in 2001.
A major ice storm struck central North Carolina on December 4, 2002. As a result
of the storm, up to 464,000 (35%) customers in CP&L Electric's service area were
without power. Restoration included more than 3,500 line, service and tree
personnel from 19 states. The outages resulted in $27.2 million of increased
operations and maintenance costs and $27.8 million of increased capital costs.
Depreciation and amortization expense increased $1.9 million in 2002 when
compared to $521.9 million in 2001 and decreased $176.7 million in 2001 when
compared to $698.6 million in 2000. CP&L Electric's accelerated cost recovery
program for nuclear generating assets allows flexibility in recording
accelerated depreciation expense. CP&L Electric recorded $52.8 million of
accelerated depreciation expense in 2002 and $75.0 million in 2001. The
year-over-year favorability was offset by additional depreciation recognized in
2002, as compared to 2001, on new assets that were placed in service during
2002. In 2000, as approved by regulators, CP&L Electric recorded $275.0 million
of depreciation expense under the accelerated cost recovery program. See Note 1G
to the Progress Energy consolidated financial statements for additional
information about this program.
Net interest expense decreased $29.9 million in 2002, when compared to $241.4
million in 2001, due primarily to reduced debt and lower interest rates. Net
interest expense increased $19.6 million in 2001, when compared to $221.9
million in 2000, primarily due to higher debt balances used to fund construction
programs.
In accordance with an SEC order under PUHCA, effective in 2002, tax benefits not
related to acquisition interest expense that were previously held unallocated at
the holding company must be allocated to the profitable subsidiaries. As a
result, $34.1 million of the tax benefit that was previously held at the holding
company, included in the Other segment, was allocated to CP&L Electric in 2002.
The allocation has no impact on the Company's consolidated tax expense or net
income. Other fluctuations in income taxes are primarily due to changes in
pre-tax income.
Florida Power Electric
The results shown in the Progress Energy consolidated financial statements for
the Florida Power Electric segment include operating results since the date of
acquisition, November 30, 2000. Therefore, 2002 and 2001 include full years of
operations, while 2000 includes only one month. As a result, the 2000 results of
operations are not comparable to 2001.
Florida Power Electric contributed income of $322.6 million and $309.6 million
for the years ended December 31, 2002 and 2001, respectively, and $21.8 million
for the month of December 2000. Included in these amounts are wholesale energy
marketing activities and immaterial trading activities, which are managed by
Progress Ventures on behalf of Florida Power Electric, that contributed net
income of $13.0 million and $24.0 million for the years ended December 31, 2002
and 2001, respectively, and $1.7 million for the month of December 2000.
Florida Power Electric's earnings in 2002 were affected by the outcome of the
Florida Power rate case settlement, which included a one-time retroactive
revenue refund of $35.0 million ($21.0 million after tax), a decrease in retail
rates of 9.25% (effective May 1, 2002), which resulted in an additional $79.5
million decline in revenues, and an estimated revenue sharing refund of $4.7
million. These revenue declines were partially offset by $78.2 million of lower
depreciation and amortization pursuant to the rate case and increased service
revenue rates. See Note 15B to the Progress Energy consolidated financial
statements for further discussion of the rate case settlement.
47
A comparison of the results of operations of Florida Power Electric for the past
three years follows.
Revenues
Florida Power's electric revenues for the years ended December 31, 2002, 2001
and 2000 and the percentage change by year and by customer class, as well as the
impact of the rate case settlement on revenue, are as follows (in millions):
------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000 (a)
------------------------------------------------------------------------------------------------
Residential $1,645 0.1% $1,643 11.3% $1,476
Commercial 731 (3.1) 754 13.9 662
Industrial 211 (5.4) 223 5.2 212
Governmental 173 (1.7) 176 15.8 152
Revenue Sharing Refund (5) - - - -
Retroactive Retail Rate Refund (35) - - - -
---------- ------------ -----------
Total Retail Revenues 2,720 (2.7) 2,796 11.8 2,502
Wholesale 230 (20.1) 288 4.3 276
Unbilled (3) - (22) - 18
Miscellaneous 115 (23.8) 151 98.7 76
---------- ------------ -----------
Total Electric Revenues $3,062 (4.7)% $3,213 11.9% $2,872
------------------------------------------------------------------------------------------------
(a) Florida Power electric revenues are included in the Company's
results of operations since November 30, 2000, the date of
acquisition. Florida Power Electric's full year of revenue is
included for comparative purposes only.
Florida Power's electric energy sales for the years ended December 31, 2002,
2001 and 2000 and the percentage change by year and by customer class are as
follows (in thousands of mWh):
------------------------------------------------------------------------------------------------
Customer Class 2002 % Change 2001 % Change 2000 (b)
------------------------------------------------------------------------------------------------
Residential 18,754 6.5% 17,604 2.9% 17,116
Commercial 11,420 3.2 11,061 2.3 10,813
Industrial 3,835 (1.0) 3,872 (8.9) 4,249
Governmental 2,850 4.5 2,726 2.7 2,654
---------- ------------ -----------
Total Retail Energy Sales 36,859 4.5 35,263 1.2 34,832
Wholesale 4,180 (11.4) 4,719 (9.4) 5,209
Unbilled 5 - (511) - 344
---------- ------------ -----------
Total mWh sales 41,044 4.0% 39,471 (2.3%) 40,385
------------------------------------------------------------------------------------------------
(b) Florida Power electric energy sales are included in the Company's
results of operations since November 30, 2000, the date of
acquisition. Florida Power Electric's full year of sales is
included for comparative purposes only.
Florida Power electric revenues decreased $151.1 million from 2001 to 2002. The
revenue declines were driven by the $119.2 million impact of the rate case,
mentioned previously. Additionally, wholesale revenues declined $58.1 million,
driven primarily by a contract that was not renewed. Year-over-year comparisons
were also unfavorably impacted by the recognition of $63.0 million of revenue
deferred from 2000 to 2001. Partially offsetting the unfavorable revenue impacts
was growth in the residential (approximately 29,000 additional customers) and
commercial (approximately 4,000 additional customers) customer classes.
Additional offsets included weather conditions, primarily a warmer than normal
summer in 2002, and an increase in other service revenue, resulting primarily
from increased rates allowed under the rate case settlement, along with higher
transmission wheeling revenues.
Residential and commercial sales increased in 2001 and reflect continued growth
in the number of customers served by Florida Power Electric, partially offset by
milder weather and a downturn in the economy. Florida Power Electric added over
35,000 new customers in 2001. Industrial sales declined in 2001 due to weakness
in the manufacturing sector and phosphate industry, which were affected by the
economic downturn. Sales to wholesale customers decreased for 2001, primarily
due to the mild weather.
Expenses
Fuel used in generation and purchased power was $1.37 billion for the year ended
December 31, 2002, a decrease of $58.8 million from 2001. The decrease is
primarily due to a lower recovery of fuel expense that resulted from a
mid-course correction of Florida Power Electric's fuel cost recovery clause, as
part of the rate settlement, and lower purchased power costs, partially offset
by an increase in coal prices and volume from high system requirements. Fuel and
purchased power expenses are recovered primarily through cost recovery clauses
and, as such, have no material impact on operating results. Fuel used in
generation and purchased power was $1.43 billion for the year ended December 31,
2001 and $94.8 million for the one month of 2000.
48
Operations and maintenance expense increased $85.1 million in 2002 when compared
to $487.1 million in 2001, due primarily to a reduced pension credit of $30.8
million, increased costs related to the Commitment to Excellence program of
$11.3 million, and an increase in other salary and benefit costs of $21.5
million related partially to increased medical costs. The Commitment to
Excellence program was initiated in 2002 to improve service and reliability.
Operations and maintenance expense was $152.7 million for the one month of 2000
and included merger-related charges.
Depreciation and amortization expense decreased $158.1 million in 2002 when
compared to $453.0 million in 2001. In addition to the depreciation and
amortization reduction of approximately $79.0 million related to the rate case,
depreciation declined an additional $97.0 million related to accelerated
amortization on the Tiger Bay regulatory asset, which was created as a result of
the early termination of certain long-term cogeneration contracts. See Note 15B
to the Progress Energy consolidated financial statements for further detail on
the rate case. Florida Power Electric amortizes the regulatory asset according
to a plan approved by the Florida Public Service Commission in 1997 and plans to
fully amortize the asset by the end of 2003. In 2001, $97.0 million of
accelerated amortization was recorded on the Tiger Bay regulatory asset, of
which $63.0 million was associated with deferred revenue from 2000 and had no
impact on 2001 earnings. Depreciation and amortization expense was $28.9 million
for the one month of 2000.
In 2002, $19.9 million of the tax benefit that was previously held at the
Company's holding company (see earlier discussion in the CP&L Electric segment),
was allocated to Florida Power Electric. Other fluctuations in income taxes are
primarily due to changes in pretax income.
Diversified Businesses
The Company's diversified businesses consist primarily of the Progress Ventures
segment, the Rail Services segment, and Progress Telecom, Caronet, SRS and
holding company operations, which are in the Other segment and are explained in
more detail below.
Progress Ventures
Progress Ventures contributed segment income of $271.1 million and $288.7
million for 2002 and 2001, respectively. These amounts included wholesale energy
marketing and immaterial trading net income of $73.0 million and $86.7 million
in 2002 and 2001, respectively, that Progress Ventures managed on behalf of the
utilities. Due to the creation of Progress Ventures in 2000 and the acquisition
of Progress Fuels' subsidiaries through the FPC acquisition, the results of
operations for the Progress Ventures segment are not comparable between 2001 and
2000.
The Progress Ventures segment operations include nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing and delivery; and energy marketing and limited trading activities
on behalf of the utility operating companies as well as for its nonregulated
plants. Progress Ventures' results for 2002 were impacted unfavorably by the
weak energy market and lower synthetic fuel sales, offset partially by
additional earnings from placing in service additional nonregulated generation
plants and the purchase of Westchester Gas Company.
Progress Ventures' nonregulated generation operations generated net income of
$34.7 million and $4.3 million in 2002 and 2001, respectively. In 2001, the
operations included one merchant plant with a 315-megawatt capacity. In 2002, a
plant was transferred from the CP&L Electric regulated segment to Progress
Ventures, one operational plant was purchased from LG&E Energy Corporation
(LG&E. See Note 2A to the Progress Energy consolidated financial statements),
and one additional plant was placed into service upon completion of
construction. At the end of 2002, plants with 1,554 megawatts of capacity were
operational. This increase in capacity drove the increase in net income. The
earnings potential of the increased capacity was partially offset by the general
softness in the energy market in 2002. The Company has contracts representing
63%, 69%, and 25% of planned production capacity for 2003 through 2005,
respectively. The 2005 decline results from the expiration of four contracts.
The Company is actively pursuing opportunities with the current customers and
other potential customers.
Progress Ventures' subsidiary, MPC Generating, LLC, had two tolling agreements
for output on one of its units with Dynegy, Inc. through June 2008. The
contracts with Dynegy were terminated in December 2002. The Company expects to
recognize a gain in connection with the termination in the first quarter of 2003
if certain related contingencies are resolved, but does not currently have a
customer for the output of the 160 megawatt unit.
49
In 2001, Progress Ventures' natural gas exploration and production operations
included the operations of Mesa Hydrocarbons, Inc. (Mesa), which owns natural
gas reserves and operates wells in Colorado and sells natural gas. In 2002, it
also included similar operations of Westchester Gas Company. See Note 2B to the
Progress Energy consolidated financial statements for discussion of the
Westchester Gas Company acquisition. These gas operations generated net income
of $9.6 million and $5.3 million in 2002 and 2001, respectively. Westchester Gas
Company produced 5.8 million cubic feet of gas in 2002, which represented 49% of
the combined production for the year. This increased production drove the
earnings increase from 2001 to 2002.
Progress Ventures' coal fuel extraction, manufacturing and delivery operations
generated net income of $166.4 million and $198.4 million in 2002 and 2001,
respectively. The Progress Ventures coal group produced and sold 11.2 million
and 13.3 million tons of synthetic fuel in 2002 and 2001. The production and
sale of the synthetic fuel from these facilities generate operating losses, but
qualify for tax credits under Section 29 of the Internal Revenue Code, which
more than offset the effects of such losses. See "Synthetic Fuels " under OTHER
MATTERS below for additional discussion of these tax credits. The sales resulted
in tax credits of $291.0 million and $349.3 million being recognized in 2002 and
2001, respectively. The Company is pursuing selling a portion of the synthetic
fuel operations.
Progress Ventures' energy marketing and trading operations generated net income
of $69.1 million and $86.7 million in 2002 and 2001, respectively. This group
focuses on marketing and selling wholesale power and limited financial trading.
Wholesale marketing generated $77.2 million and $90.2 million of the group's
earnings in 2002 and 2001, respectively. The earnings reductions from 2001 to
2002 are mainly attributable to reduced margins for wholesale electric sales.
This group also manages financial trades of power. Financial trades generated
net losses of $8.1 million and $3.5 million in 2002 and 2001, respectively,
including associated overhead costs. The primary driver of the increased loss in
2002 was the higher overhead associated with the plan to grow the marketing and
trading activities; however, the Company recently announced plans to reduce the
scope of its trading activities.
Rail Services
Rail Services' operations represent the activities of Progress Rail Services
Corporation (Progress Rail) and include railcar and locomotive repair,
trackwork, rail parts reconditioning and sales, scrap metal recycling, railcar
leasing and other rail related services. Rail Services' results for the year
ended December 31, 2001, included Rail Services' cumulative revenues and net
loss from the date of acquisition, November 30, 2000, because Rail Services had
been held for sale from the date of acquisition through the second quarter of
2001.
Rail Services contributed net losses of $41.7 million and $12.1 million for the
years ended December 31, 2002 and 2001, respectively. The net loss in 2002
includes a $40.1 million after-tax estimated impairment on assets held for sale
related to Railcar Ltd., a leasing subsidiary of Progress Rail. The Company
intends to sell the assets of Railcar Ltd. in 2003 and has reported these assets
as assets held for sale. See Note 3B to the Progress Energy consolidated
financial statements for discussion of this planned divestiture. Rail Services'
results for both years were affected by a downturn in the overall economy,
decreases in rail service procurement by major railroads and a downturn in the
domestic scrap market. Rail Services' 2002 results were favorably impacted by
aggressive cost cutting, new business opportunities and restructuring
initiatives.
An SEC order approving the merger of FPC requires the Company to divest of Rail
Services by November 30, 2003. The Company is actively pursuing alternatives,
but does not expect to find the right divestiture opportunity by that date.
Therefore, the Company plans to seek an extension from the SEC.
Other
Progress Energy's Other segment primarily includes the operations of SRS,
Progress Telecom and Caronet. The results of NCNG have been excluded from the
Other segment because of its classification as a discontinued operation. This
segment also includes other nonregulated operations of CP&L and FPC, as well as
holding company results and consolidation and elimination adjustments. The Other
segment had a net loss from continuing operations of $439.9 million and $427.4
million in 2002 and 2001, respectively, and net income from continuing
operations of $42.6 million in 2000. The increase in the net loss in 2002 was
primarily related to impairments and other charges in the telecommunications
group and the reallocation of favorable income tax benefits to other segments.
These charges are partially offset by the elimination of goodwill amortization
of $89.7 million and the favorable impact of the contingent value obligations,
which are discussed below. The decrease in earnings for 2001 when compared to
2000 is primarily due to after-tax charges of $148.1 million from the assessment
of the recoverability of the Interpath investment and certain assets in the SRS
subsidiary, increases in after-tax interest expense for holding company debt of
$159.0 million and goodwill amortization of $82.7 million resulting from the
acquisition of FPC. In addition, the Other segment net income in 2000 includes a
$121.1 million after-tax gain on sale of assets, as described more fully below.
50
SRS was engaged in software sales and energy services to help industrial,
commercial and institutional customers manage energy costs. In 2002, SRS
refocused the business on energy services in the southeastern United States and
consolidated remaining operations with other retail activities. SRS net losses,
excluding after-tax impairments and other charges discussed below, were $13.3
million, $7.2 million and $0.8 million for 2002, 2001 and 2000, respectively.
The earnings decline from 2001 to 2002 resulted from a $3.8 million loss on the
sale of the assets of several divisions and from increased legal fees. Due to
the historical losses at SRS and the decline of the market value for technology
companies, a valuation study was obtained to help assess the recoverability of
SRS's long-lived assets in 2001. Based on this assessment, an after-tax asset
impairment and other charges (primarily legal expenses) totaling $40.7 million
were recorded in 2001. See Note 7 to the Progress Energy consolidated financial
statements for further information on this impairment and other charges. In
addition, the Company recorded after-tax investment impairments of $4.9 million
for other-than-temporary declines in certain investments of SRS in 2001.
Progress Telecom and Caronet had combined net losses of $229.0 million and
$110.4 million for 2002 and 2001, respectively. In 2000, Caronet combined with
one month of Progress Telecom contributed net income of $79.9 million.
Progress Telecom and Caronet provide broadband capacity services, dark fiber and
wireless services in Florida and the eastern United States. Due to the decline
of the telecommunications industry and continued operating losses, the Company
obtained a valuation study in 2002 to assess the recoverability of Progress
Telecom's and Caronet's long-lived assets. Based on these valuation studies, the
Company recorded an after-tax impairment of $190.4 million and other related
after-tax charges, primarily inventory adjustments, of $18.1 million. See Note
7A to the Progress Energy consolidated financial statements for further
information on this impairment and other charges.
Effective June 28, 2000, Caronet contributed the net assets used in its
application service provider business to a newly formed company named Interpath
Communications, Inc. (Interpath). In May 2002, Interpath merged with a third
party, diluting Caronet's ownership interest from 35% to 19% and reduced the
voting interest from 15% to 7%. The Company obtained valuation studies in 2001
and again in 2002, after the merger of Interpath. As a result of these valuation
studies, the Company recorded impairments for other-than-temporary declines in
the fair value of its investment in Interpath of $16.3 million and $102.4
million in 2002 and 2001, respectively. See Note 7B to the Progress Energy
consolidated financial statements for further information on this impairment.
In 2000, Caronet sold its 10% limited partnership interest in BellSouth
Carolinas PCS, resulting in an after-tax gain of $121.1 million. See Note 3D to
the Progress Energy consolidated financial statements for further details on the
sale.
Excluding the impairments, other charges and the gain on the sale of the limited
partnership interest discussed above, Progress Telecom and Caronet had combined
remaining losses of $4.2 million, $8.0 million and $41.2 million for 2002, 2001
and 2000, respectively. Lower depreciation resulting from the write-down of
impaired assets contributed to the decrease in the remaining loss from 2002 to
2001. The reduction in the remaining loss in 2001, when compared to 2000,
results from the removal of the Interpath operations.
The Other segment also includes Progress Energy's holding company results. As
part of the acquisition of FPC, goodwill of approximately $3.6 billion was
recorded, and amortization of $89.7 million in 2001 and $7.0 million in 2000 was
included in the Other segment. In accordance with SFAS No. 142, "Goodwill and
Other Intangible Assets," effective January 1, 2002, the Company no longer
amortizes goodwill. At December 31, 2002, the Company had approximately $3.7
billion of unamortized goodwill. See Note 6 to the Progress Energy consolidated
financial statements for more details on goodwill.
Net pre-tax interest charges in the Other segment were $270.2 million, $253.1
million and $5.2 million, for 2002, 2001 and 2000, respectively. The increase in
2002, when compared to 2001, was primarily related to increased debt associated
with the purchase of generating plants. This was partially offset by lower
interest rates and $18.9 million of interest capitalization in 2002 related to
the building of the nonregulated generating plants. The increase in interest
from 2000 to 2001 was primarily related to the debt used to finance the
acquisition of FPC.
According to an SEC order under PUHCA, Progress Energy's tax benefit not related
to acquisition interest expense is to be allocated to profitable subsidiaries.
Therefore, the tax benefit that was previously held in the holding company,
included in the Other segment, was allocated to the profitable subsidiaries
effective with 2002. The allocation has no impact on consolidated tax expense or
earnings. However, in 2002, the allocation increased the Other segment's tax
expense $55.4 million with offsetting decreases in other segments (primarily
CP&L Electric and Florida Power Electric).
51
Progress Energy issued 98.6 million contingent value obligations (CVOs) in
connection with the FPC acquisition. Each CVO represents the right to receive
contingent payments based on the performance of four synthetic fuel facilities
owned by Progress Energy. The payments, if any, are based on the net after-tax
cash flows the facilities generate. At December 31, 2002, 2001 and 2000, the
CVOs had a fair market value of approximately $13.8 million, $41.9 million and
$40.4 million, respectively. Progress Energy recorded an unrealized gain of
$28.1 million for the year ended December 31, 2002, an unrealized loss of $1.5
million for the year ended December 31, 2001 and an unrealized gain of $8.9
million for the month ended December 31, 2000, to record the changes in fair
value of CVOs, which had average unit prices of $0.14, $0.43 and $0.41 at
December 31, 2002, 2001 and 2000, respectively.
Discontinued Operations
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. As a result of this action, the operating results of NCNG were reclassified
to discontinued operations for all reportable periods. Progress Energy expects
to sell NCNG for net proceeds of approximately $400 million, which results in an
estimated after-tax loss on the sale of the assets of $29.4 million, including
the impact of interest expense allocated to NCNG, as discussed in Note 3A to the
Progress Energy consolidated financial statements.
Application of Critical Accounting Policies and Estimates
The Company prepared its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. In doing so,
certain estimates were made that were critical in nature to the results of
operations. The following discusses those significant estimates that may have a
material impact on the financial results of the Company and are subject to the
greatest amount of subjectivity. Senior management has discussed the development
and selection of these critical accounting policies with the Audit Committee of
the Company's Board of Directors.
Utility Regulation
The Company's regulated utilities segments are subject to regulation that sets
the prices (rates) the Company is permitted to charge customers based on the
costs that regulatory agencies determine the Company is permitted to recover. At
times, regulators permit the future recovery through rates of costs that would
be currently charged to expense by a nonregulated company. This ratemaking
process results in deferral of expense recognition and the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in each state in which the Company operates, a
significant amount of regulatory assets has been recorded. The Company
continually reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future. Additionally, the state regulatory agencies often provide
flexibility in the manner and timing of the depreciation of property, nuclear
decommissioning costs and amortization of the regulatory assets. Note 15 to the
Progress Energy consolidated financial statements provides additional
information related to the impact of utility regulation on the Company.
Asset Impairments
The Company evaluates the carrying value of long-lived assets for impairment
whenever indicators exist. Examples of these indicators include current period
losses combined with a history of losses, or a projection of continuing losses,
or a significant decrease in the market price of a long-lived asset group. If an
indicator exists, the asset group held and used is tested for recoverability by
comparing the carrying value to the sum of undiscounted expected future cash
flows directly attributable to the asset group. If the asset group is not
recoverable through undiscounted cash flows or if the asset group is to be
disposed of, an impairment loss is recognized for the difference between the
carrying value and the fair value of the asset group. A high degree of judgment
is required in developing estimates related to these evaluations and various
factors are considered, including projected revenues and costs and market
conditions.
During 2002, the Company recorded pre-tax long-lived asset impairments of $305.0
million related to its telecommunications business. See Note 7A to the Progress
Energy consolidated financial statements for further information on this
impairment and other charges. The fair value of these assets was determined
using an external valuation study heavily weighted on a discounted cash flow
methodology and using market approaches as supporting information. However, if
the telecommunications market continues to deteriorate, the Company's
telecommunications-related assets may be further adversely affected.
The Company also continually reviews its investments to determine whether a
decline in fair value below the cost basis is other-than-temporary. During 2002
and 2001, the Company recorded pre-tax impairments to the cost method investment
in Interpath of $25.0 million and $156.7 million, respectively. The fair value
of this investment was determined using an external valuation study heavily
weighted on a discounted cash flow methodology and using market approaches as
supporting information. These cash flows include numerous assumptions including
the pace at which the telecommunications market will rebound. In the fourth
quarter of 2002, the Company sold its remaining interest in Interpath for a
nominal amount.
52
Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other
Intangible Assets," which requires that goodwill be tested for impairment at
least annually and more frequently when indicators of impairment exist. See Note
6 to the Progress Energy consolidated financial statements for further detail on
goodwill. Accounting standards require a two step goodwill impairment test. The
first step, used to identify potential impairment, compares the fair value of
the reporting unit with its carrying amount, including goodwill. The second
step, used to measure the amount of the impairment loss if step one indicates a
potential impairment, compares the implied fair value of the reporting unit
goodwill with the carrying amount of the goodwill.
The Company completed the initial transitional goodwill impairment test, which
indicated that the Company's goodwill was not impaired as of January 1, 2002. In
addition, the Company performed the annual goodwill impairment test for CP&L
Electric and Florida Power Electric during 2002, which indicated that the
Company's goodwill was not impaired. In connection with the pending sale of
NCNG, the Company reviewed the carrying value of NCNG, including goodwill, as
discussed in Note 3A to the Progress Energy consolidated financial statements.
During 2002, the Company completed the acquisition of two electric generating
projects, Walton County Power, LLC and Washington County Power, LLC. The
acquisitions resulted in goodwill of $64.1 million. The Company has completed
the purchase price allocation and will perform the annual goodwill impairment
test in the first quarter of 2003. During 2002, the Company also acquired
Westchester Gas Company. The purchase price has been preliminarily allocated to
fixed assets including oil and gas properties, based on the preliminary fair
values of the assets acquired. The purchase price allocation for this
acquisition will be finalized in the second quarter of 2003, and if any of the
purchase price is ultimately allocated to goodwill, an annual goodwill
impairment test will be performed at that time.
Synthetic Fuels Tax Credits
Progress Energy, through the Progress Ventures business unit, produces synthetic
fuel from coal fines. The production and sale of the synthetic fuel qualifies
for tax credits under Section 29 of the Internal Revenue Code (Section 29) if
certain requirements are satisfied, including a requirement that the synthetic
fuel differs significantly in chemical composition from the feedstock used to
produce such synthetic fuel. Any synthetic fuel tax credit amounts not utilized
are carried forward indefinitely and are included in deferred taxes on the
accompanying Consolidated Balance Sheet. See Note 20 to the Progress Energy
consolidated financial statements for further information on the synthetic fuel
tax credits. All of Progress Energy's synthetic fuel facilities have received
private letter rulings from the Internal Revenue Service (IRS) with respect to
their operations. These tax credits are subject to review by the IRS, and if
Progress Energy fails to prevail through the administrative or legal process,
there could be a significant tax liability owed for previously taken Section 29
credits, with a significant impact on earnings and cash flows.
Pension and Other Postretirement Benefits
The Company's reported costs of providing pension and other postretirement
benefits (described in Note 18 to the Progress Energy consolidated financial
statements), primarily health benefits, are dependent on numerous factors
resulting from actual plan experience and assumptions of future experience. For
example, such costs are impacted by employee demographics, changes made to plan
provisions, and key actuarial assumptions such as rates of return on plan
assets, discount rates used in determining benefit obligations and annual costs
and, for other postretirement benefits, medical trend rates.
Due to a decline in market interest rates for high-quality (AAA/AA) debt
securities, which are used as the benchmark for setting the discount rate, the
Company lowered the discount rate to 6.60% at December 31, 2002, which will
increase the 2003 benefit costs recognized. In addition, the continuing declines
in the equity markets have adversely affected the fair value of plan assets,
which will also increase the benefit costs recognized in 2003. Evaluations of
the effects of these factors has not been completed, but the Company estimates
that 2003 total cost for pension and other postretirement benefits will increase
by approximately $40 million over the amount recorded in 2002, due in large part
to these factors. The majority of that increase has been anticipated and
reflected in the Company's budgeting/forecasting process. Recoveries in the
level of interest rates and equity markets would, correspondingly, have positive
effects on future years' benefit cost recognition.
53
The Company has substantial pension plan assets, with a fair value of
approximately $1.4 billion at December 31, 2002. The Company's expected rate of
return on pension plan assets has been, and will continue to be for the
foreseeable future, 9.25%. Under the accounting standard for pension accounting,
the expected rate of return used in pension cost recognition is a long-term rate
of return; therefore, the Company would only adjust that return if its
fundamental assessment of the debt and equity markets changes or its investment
policy changes significantly. The Company continues to believe that its pension
plan's investment mix supports the long-term rate of 9.25% being used. The
Company did not increase the expected long-term rate of return in response to
the abnormally high market return levels of the latter 1990's and does not
believe it is appropriate to adjust the rate downward because of recent market
declines. A 0.25% change in the expected rate of return for 2002 would have
changed 2002 pension cost by approximately $4.5 million.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Progress Energy is a registered holding company and, as such, has no operations
of its own. The ability to meet its obligations is primarily dependent on the
earnings and cash flows of its two electric utilities and the ability of those
subsidiaries to pay dividends or repay funds to Progress Energy.
The cash requirements of Progress Energy arise primarily from the
capital-intensive nature of its electric utility operations as well as the
expansion of its diversified businesses, primarily those of the Progress
Ventures segment.
Progress Energy relies upon its operating cash flow, generated primarily by its
two regulated electric utility subsidiaries, commercial paper facilities and its
ability to access long-term capital markets for its liquidity needs. Since a
substantial majority of Progress Energy's operating costs are related to its two
regulated electric utilities, a significant portion of these costs are recovered
from customers through fuel and energy cost recovery clauses.
During 2003, the Company expects to realize approximately $400 million of net
cash proceeds from the sale of NCNG. The Company also expects to receive between
$100 million and $300 million of proceeds through the sale of common stock
issued through the Progress Energy Direct Stock Purchase and Dividend
Reinvestment Plan, and its 401(k) Savings and Stock Ownership Plan.
Progress Energy's cash from operations and common stock issuance proceeds in
2003 are expected to fund its capital expenditures. Progress Energy expects to
use the proceeds from the sale of NCNG to reduce indebtedness then outstanding.
To the extent necessary, incremental borrowings or commercial paper issuances
may also be used as a source of liquidity.
Progress Energy forecasts its liquidity resources to be sufficient to fund its
current business plans. Risk factors associated with commercial paper backup
credit facilities and credit ratings are discussed below as well as in the
Company's SEC filings.
The following discussion of Progress Energy's liquidity and capital resources is
on a consolidated basis.
Cash Flows from Operations
Cash from operations is the primary source used to meet operating requirements
and capital expenditures. Total cash from operations for 2002 was $1.6 billion,
up $175 million from 2001.
The increase in cash from operating activities for 2001 when compared with 2000
is largely the result of the November 30, 2000, acquisition of FPC. The 2000
results reflected one month's cash from operations of FPC.
Progress Energy's two electric utilities produced approximately 112% of
consolidated cash from operations in 2002. It is expected that the two electric
utilities will continue to produce a majority of the consolidated cash flows
from operations over the next several years as its nonregulated investments,
primarily generation assets, are placed into service and begin generating
operating cash flows. In addition, Progress Ventures' synthetic fuel operations
do not currently produce positive operating cash flow primarily due to the
difference in timing of when tax credits are recognized for financial reporting
purposes and when tax credits are realized for tax purposes.
Total cash from operations provided the funding for approximately 72% of the
Company's property additions, nuclear fuel expenditures and diversified business
property additions during 2002. The remaining funds were obtained through debt
and equity issuances by Progress Energy as discussed below. Progress Energy
expects its operating cash flow to exceed its projected capital expenditures
beginning in 2004.
54
Investing Activities
Cash used in investing activities was $2.2 billion in 2002, up approximately
$556 million when compared with 2001. The increase is due primarily to the
expansion of PVI's generation portfolio. In February 2002, PVI purchased two
generating projects from LG&E Energy Corp. for approximately $350 million.
Cash used in investing was $1.7 billion in 2001, up $663 million when compared
with 2000 after adjusting for the acquisition of Florida Progress. The increase
is due primarily to the expansion of PVI's generation portfolio and the absence
of proceeds from the sale in 2000 of the BellSouth Carolinas PCS limited
partnership interest.
Capital expenditures for Progress Energy's regulated electric operations were
$1.2 billion or approximately 55% of consolidated capital expenditures in 2002.
As shown in the table below, the Company anticipates that the proportion of
nonregulated capital spending to total capital expenditures will decrease
substantially in 2003 when compared with 2002. The decrease reflects the
expected completion of PVI's nonregulated generation portfolio by the summer of
2003. Progress Energy expects the majority of its capital expenditures to be
incurred at its regulated operations.
(Dollars in millions):
Actual Forecasted
----------- ------------------------------------------------
2002 2003 2004 2005
----------- ------------ -------------- -----------
Regulated capital expenditures $ 1,174 $ 1,100 $ 1,050 $ 1,040
Nuclear fuel expenditures 81 120 100 120
AFUDC - borrowed funds (8) (20) (20) (20)
Nonregulated capital expenditures 935 290 110 110
----------- ------------ -------------- -----------
Total $ 2,182 $ 1,490 $ 1,240 $ 1,250
=========== ============ ============== ===========
Regulated capital expenditures in the table above include total expenditures
from 2003 through 2005 of approximately $147 million expected to be incurred at
regulated fossil-fueled electric generating facilities to comply with Section
110 of the Clean Air Act, referred to as the NOx SIP Call.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants. CP&L expects its capital costs to meet
these emission targets will be approximately $813 million by 2013. For the years
2003 through 2005, the Company expects to incur approximately $258 million of
total capital costs associated with this legislation, which is included in the
table above. See Note 24 to the Progress Energy consolidated financial
statements and "Current Regulatory Environment" under OTHER MATTERS below for
more information on this legislation.
CP&L has determined that its external funding levels do not fully meet the
nuclear decommissioning financial assurance levels required by the U.S. Nuclear
Regulatory Commission. The funding levels have been adversely affected by the
recent declines in the equity markets. The total shortfall is approximately $95
million (2010 dollars) for Robinson Unit No. 2, $82 million (2016 dollars) for
Brunswick Unit No. 1 and $99 million (2014 dollars) for Brunswick Unit No. 2.
CP&L is currently evaluating the alternatives for meeting the financial
assurance requirements, which primarily include increasing annual deposits to
the external trust by an estimated $18.8 million annually or obtaining a parent
company guarantee. The funding status for these facilities would be positively
affected by a recovery in the equity markets and by the approval of license
extension applications. See Note 1H to the Progress Energy consolidated
financial statements for further discussion.
All projected capital and investment expenditures are subject to periodic review
and revision and may vary significantly depending on a number of factors
including, but not limited to, industry restructuring, regulatory constraints,
market volatility and economic trends.
Financing Activities
Cash provided by financing activities increased approximately $433.8 million
over 2001, primarily due to issuances of long-term debt and common stock equity
by Progress Energy.
Cash provided by financing activities decreased by $3.4 billion when comparing
2001 to 2000. This decrease was due to the November 30, 2000, acquisition of
FPC, which was funded from the sale of short-term commercial paper. This funding
was converted to long-term debt during 2001. Excluding the effect of the
acquisition financing, cash from financing activities increased slightly in 2001
when compared with 2000, primarily due to the expansion of Progress Energy's
nonregulated operations.
55
In February 2002, $50 million of Progress Capital Holdings, Inc. (PCH)
medium-term notes, 5.78% Series, matured. Progress Energy funded this maturity
through the issuance of commercial paper. As of December 31, 2002, PCH had $223
million of fixed rate medium-term notes. The final medium-term note is due in
May 2008. Progress Energy intends to fund these maturing notes through
internally generated funds and the issuance of commercial paper.
In April 2002, Progress Energy issued $350 million of senior unsecured notes due
2007 with a coupon of 6.05% and $450 million of senior unsecured notes due 2012
with a coupon of 6.85%. Proceeds from this issuance were used to pay down
commercial paper, which had been used in part to fund the expansion of PVI's
nonregulated generation portfolio, including the acquisition of generating
assets from LG&E.
In November 2002, Progress Energy issued 14.7 million shares of common stock.
Total net proceeds from the issuance were approximately $600 million and were
used to pay down commercial paper.
The Company issued 2.1 million shares representing approximately $86 million in
proceeds from its Dividend Reinvestment and Stock Purchase Plan, and its
employee benefit plans.
During 2002, both CP&L and Florida Power took advantage of historically low
interest rates and refinanced several issues of tax-exempt debt as well as
certain taxable issues.
In February 2002, CP&L issued $48.5 million principal amount of First Mortgage
Bonds, Pollution Control Series W, Wake County Pollution Control Revenue
Refunding Bonds, 5.375% Series 2002 due February 1, 2017. On March 1, 2002, CP&L
redeemed $48.5 million principal amount of Pollution Control Revenue Bonds, Wake
County due April 1, 2019, at 101.5% of the principal amount of such bonds.
In July 2002, Florida Power issued approximately $241 million of Pollution
Control Revenue Refunding Bonds, secured by First Mortgage Bonds. Proceeds from
this issuance were used to redeem $241 million of Pollution Control Revenue
Bonds in August. Also in July, $30 million of medium-term notes, 6.54% Series,
matured. Florida Power funded this maturity through the issuance of commercial
paper.
In July 2002, CP&L issued $500 million of senior unsecured notes due 2012 with a
coupon of 6.5%. Proceeds from this issuance were used to pay down commercial
paper, which had been used to redeem $500 million of CP&L Extendible Notes due
October 28, 2009, at 100% of the principal amount of such notes. These notes
were redeemed July 29, 2002.
In September 2002, CP&L redeemed $150 million of First Mortgage Bonds, 8.2%
Series, due July 1, 2022 at 103.55% of the principal amount of such bonds. CP&L
redeemed these notes through the issuance of commercial paper.
In March 2002, Progress Genco Ventures, LLC (Genco), a PVI subsidiary, obtained
a $440 million bank facility that is restricted for the use of expanding its
nonregulated generation portfolio, which is expected to be completed by the
summer of 2003. Borrowings under this facility will be nonrecourse to Progress
Energy; however, the Company entered into certain support and guarantee
agreements to ensure performance under generation construction and operating
agreements. In September 2002, $130 million of the bank facility was terminated,
reducing it to $310 million. This amount includes a $50 million working capital
facility. The reduction was due to PVI's decision to reduce the expansion of its
nonregulated generation portfolio. As of December 31, 2002, $225 million was
outstanding under this facility.
As a registered holding company under PUHCA, Progress Energy obtains approval
from the SEC for the issuance and sale of securities as well as the
establishment of intracompany extensions of credit. In January 2002, Progress
Energy requested an increase of $2.5 billion in its authority to issue long-term
securities, increasing the limit from $5.0 billion to $7.5 billion. The SEC
approved the request on March 15, 2002. As of December 31, 2002, Progress Energy
has regulatory authority to issue approximately $1 billion of long-term
securities.
56
At December 31, 2002, the Company and its subsidiaries had committed lines of
credit totaling $1.74 billion, for which there were no loans outstanding. These
lines of credit support the Company's commercial paper borrowings. The following
table summarizes the Company's credit facilities (in millions):
Company Description Total
--------------------------------------------------------------------------
Progress Energy 364-Day (expiring 11/11/03) $ 430.2
Progress Energy 3-Year (expiring 11/13/04) 450.0
CP&L 364-Day (expiring 7/30/03) 285.0
CP&L 3-Year (expiring 7/31/05) 285.0
Florida Power 364-Day (expiring 4/01/03) 90.5
Florida Power 5-Year (expiring 11/30/03) 200.0
---------------
Total credit facilities $ 1,740.7
===============
During 2002, in connection with renewals, the Progress Energy and Florida Power
364-day facilities were decreased by $120.0 million and $79.5 million,
respectively.
The Company's financial policy precludes issuing commercial paper in excess of
its supporting lines of credit. At December 31, 2002, the total amount of
commercial paper outstanding was $695 million, leaving approximately $1 billion
available for issuance. The Company is required to pay minimal annual commitment
fees to maintain its credit facilities.
In addition, these credit agreements and Genco's $310 million bank facility
contain various terms and conditions that could affect the Company's ability to
borrow under these facilities. These include maximum debt to total capital
ratios, interest coverage tests, a material adverse change clauses and
cross-default provisions.
All of the credit facilities and Genco's bank facility include a defined maximum
total debt to total capital ratio. Progress Energy's maximum consolidated debt
ratio reduces to 68% effective June 30, 2003. As of December 31, 2002, the
calculated ratio for these four companies, pursuant to the terms of the
agreements, was as follows:
Company Maximum Ratio Actual Ratio (b)
------------------------------------------------------------------
Progress Energy, Inc. 70% (a) 62.4%
Carolina Power & Light Company 65% 52.7%
Florida Power Corporation 65% 48.6%
Progress Genco Ventures, LLC 40% 24.8%
(a) Progress Energy's maximum debt ratio reduces to 68% effective June
30, 2003.
(b) Indebtedness as defined by the bank agreements includes certain
letters of credit and guarantees which are not recorded on the
Consolidated Balance Sheets.
In November 2002, Progress Energy's 364-day credit facility was amended to add a
financial covenant for interest coverage. This covenant requires Progress
Energy's EBITDA to interest expense to be at least 2.5 to 1. As of December 31,
2002, this ratio was 3.43 to 1. Genco's bank facility requires a minimum 1.25 to
1 debt service coverage ratio. As of December 31, 2002, Genco's debt service
coverage ratio was 7.65 to 1.
The credit facilities of Progress Energy, CP&L, Florida Power and Genco include
a provision under which lenders could refuse to advance funds in the event of a
material adverse change in the borrower's financial condition.
Each of these credit agreements contains cross-default provisions for defaults
of indebtedness in excess of $10 million. Under these provisions, if the
applicable borrower or certain subsidiaries fail to pay various debt obligations
in excess of $10 million the lenders could accelerate payment of any outstanding
borrowing and terminate their commitments to the credit facility. Progress
Energy's cross-default provision only applies to Progress Energy and its
significant subsidiaries (i.e. CP&L, Florida Progress, Florida Power, PCH, PVI
and Progress Fuels).
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, not its
subsidiaries. In the event that these indenture cross-default provisions are
triggered, the debt holders could accelerate payment of approximately $4.8
billion in long-term debt. Certain agreements underlying the Company's
indebtedness also limit its ability to incur additional liens or engage in
certain types of sale and leaseback transactions.
The Company has on file with the SEC a shelf registration statement under which
senior notes, junior debentures, common and preferred stock and other trust
preferred securities are available for issuance by the Company. As of December
31, 2002, the Company had approximately $1 billion available under this shelf
registration.
57
Progress Energy and Florida Power each have an uncommitted bank bid facility
authorizing each of them to borrow and re-borrow, and have loans outstanding at
any time, up to $300 million and $100 million, respectively. At December 31,
2002, there were no outstanding loans against these facilities.
CP&L currently has on file with the SEC a shelf registration statement under
which it can issue up to $500 million of various long-term securities. Florida
Power currently has filed registration statements under which it can issue an
aggregate of $50 million of various long-term debt securities. CP&L and Florida
Power expect to increase their shelf capacity in the second or third quarters of
2003.
The following table shows Progress Energy's capital structure as of December 31,
2002 and 2001:
2002 2001
--------------------- ------------------
Common Stock 38.2% 36.7%
Preferred Stock 0.5% 0.6%
Total Debt 61.3% 62.7%
The amount and timing of future sales of company securities will depend on
market conditions, operating cash flow, asset sales and the specific needs of
the Company. The Company may from time to time sell securities beyond the amount
needed to meet capital requirements in order to allow for the early redemption
of long-term debt, the redemption of preferred stock, the reduction of
short-term debt or for other general corporate purposes.
Credit Rating Matters
As of February 7, 2003, the major credit rating agencies rated the Company's
securities as follows:
Moody's Standard &
Investors Service Poor's
Progress Energy, Inc.
Corporate Credit Rating Not Applicable BBB+
Senior Unsecured Baa2 BBB
Commercial Paper P-2 A-2
Carolina Power & Light Company
Corporate Credit Rating Not Applicable BBB+
Commercial Paper P-2 A-2
Senior Secured Debt A3 BBB+
Senior Unsecured Debt Baa1 BBB+
Subordinate Debt Baa2 BBB
Preferred Stock Baa3 BBB-
Florida Power Corporation
Corporate Credit Rating Not Applicable BBB+
Commercial Paper P-1 A-2
Senior Secured Debt A1 BBB+
Senior Unsecured Debt A2 BBB+
Preferred Stock Baa1 BBB-
FPC Capital I
Preferred Stock* Baa1 BBB-
Progress Capital Holdings, Inc.
Senior Unsecured Debt* A3 BBB
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no
assurances can be given that these ratings will continue for any given period of
time. However, the Company monitors its financial condition as well as market
conditions that could ultimately affect its credit ratings.
The Company and its subsidiaries' debt indentures and credit agreements do not
contain any "ratings triggers" which would cause the acceleration of interest
and principal payments in the event of a ratings downgrade. However, in the
event of a downgrade the Company and/or its subsidiaries may be subject to
increased interest costs on the credit facilities backing up the commercial
paper programs. The Company and its subsidiaries have certain contracts which
have provisions that are triggered by a ratings downgrade. These contracts
include counterparty trade agreements, derivative contracts, certain Progress
Energy guarantees and various types of third party purchase agreements. None of
these contracts would require any action on the part of Progress Energy or its
subsidiaries unless the ratings downgrade results in a rating below investment
grade.
The power supply agreement with Jackson Electric Membership Corporation that PVI
expects to acquire from Williams Energy Marketing and Trading Company (See PART
I, ITEM 1, General, Wholesale Energy Contract Acquisition) includes a
performance guarantee that Progress Energy will assume. In the event that
Progress Energy's credit ratings fall below investment grade, Progress Energy
will be required to provide additional security for its guarantee in form and
amount acceptable to Jackson. See Progress Energy, Inc. Risk Factors for
additional discussion.
58
In March 2002, Standard & Poor's (S&P) affirmed Progress Energy's corporate
credit rating of BBB+ and the ratings of Florida Power and CP&L but revised the
outlook for all three entities to negative from stable. S&P stated that its
change in outlook reflected the increased business risk at PVI and
lower-than-projected credit protection measures. S&P stated that Progress
Energy's plan to divest of non-core assets and use the proceeds to pay down
acquisition-related debt is moving slower than S&P had expected. On September 4,
2002, S&P reaffirmed Progress Energy's credit ratings and maintained the
negative outlook. The Company expects S&P to make a decision within the next 30
to 60 days. The Company cannot predict the outcome of this matter.
On February 7, 2003, Moody's Investors Service (Moody's) announced that it was
lowering Progress Energy, Inc.'s senior unsecured debt rating from Baa1 to Baa2,
and changing the outlook of the rating from negative to stable. Moody's cited
the slower than planned pace of the Company's efforts to pay down debt from its
acquisition of Florida Progress as the primary reason for the ratings change.
Moody's also changed the outlook of Florida Power Corporation (A1 senior
secured) and Progress Capital Holdings, Inc. (A3 senior unsecured) from stable
to negative and lowered the trust preferred rating of FPC Capital I from A3 to
Baa1 with a negative outlook.
The change in outlook by the rating agencies has not materially affected
Progress Energy's access to liquidity or the cost of its short-term borrowings.
Fitch Ratings Service announced on February 14, 2003 it was assigning an initial
rating to Progress Energy's senior unsecured debt of BBB-. No short-term rating
was assigned. Fitch also announced that it was downgrading the ratings of
Florida Power and CP&L. The ratings outlook for the three entities is stable.
Florida Power's senior secured rating was changed to A- from AA- and its senior
unsecured rating was changed to BBB+ from A+. Florida Power's short-term rating
was changed to F-2 from F-1+. CP&L's senior secured rating was changed to A-
from A+ and its senior unsecured rating was changed to BBB+ from A. CP&L's
short-term rating was changed to F-2 from F-1.
Interest Rate Derivatives
Progress Energy uses interest rate derivative instruments to manage the fixed
and variable rate debt components of its debt portfolio. The Company's long-term
objective is to maintain a debt portfolio mix of approximately 30% variable rate
debt, with the balance being fixed rate. As of December 31, 2002, Progress
Energy's variable rate and fixed rate debt comprised 18% and 82%, respectively,
including the effects of interest rate derivatives.
During March, April and May 2002, Progress Energy converted $1.0 billion of
fixed rate debt into variable rate debt by executing interest rate derivative
agreements with a group of five banks. Under the terms of the agreements, which
were scheduled to mature in 2006 and 2007 and coincide with the maturity dates
of the related debt issuances, Progress Energy received a fixed rate and paid a
floating rate based on three-month LIBOR. These instruments were designated as
fair value hedges for accounting purposes. In June 2002, Progress Energy
terminated these agreements. The terminations resulted in a $21.2 million
deferred hedging gain reflected in long-term debt, which will be amortized and
recorded as a reduction to interest expense over the life of the related debt
issuances.
In August 2002, Progress Energy converted $800 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of four banks. Under the terms of the agreements, which were scheduled to mature
in 2006 and coincide with the maturity date of the related debt issuance,
Progress Energy received a fixed rate and paid a floating rate based on
three-month LIBOR. These instruments were designated as fair value hedges for
accounting purposes. In November 2002, Progress Energy terminated these
agreements. The terminations resulted in a $14 million deferred hedging gain
reflected in long-term debt, which will be amortized and recorded as a reduction
to interest expense over the life of the related debt issuance.
In December 2002, Progress Energy converted $350 million of fixed rate debt into
variable rate debt by executing interest rate derivative agreements with a group
of two banks. Under the terms of the agreements, which are scheduled to mature
in 2007 and coincide with the maturity date of the related debt issuance,
Progress Energy receives a fixed rate and pays a floating rate based on
three-month LIBOR. These instruments are designated as fair value hedges for
accounting purposes. At December 31, 2002, the value of these derivatives was a
$5.2 million asset position.
In December 2002, Florida Power entered into a Treasury Rate Lock agreement,
with a notional amount of $35 million, to hedge the interest rate risk on an
anticipated debt issuance. At December 31, 2002, the value of this hedge was a
$0.5 million liability position. In January 2003, Florida Power entered into a
Treasury Rate Lock agreement, with a notional amount of $20 million, to hedge
the on an anticipated debt issuance. These contracts are
designated as cash flow hedges for accounting purposes.
59
In January 2003, Progress Energy converted $500 million of fixed rate debt into
variable rate by executing interest rate derivative contracts, bringing its
variable rate percentage to 22.7%. Under the terms of the agreements, Progress
Energy will receive a fixed rate and will pay a floating rate based on
three-month LIBOR. These instruments were designated as fair value hedges for
accounting purposes.
Progress Genco Ventures, LLC has a floating rate credit facility that requires,
as part of the loan terms, a cash flow hedge against floating interest rate
exposure. In order to satisfy this requirement, Progress Genco Ventures, LLC
entered into a series of interest rate collars during 2002 with notional amounts
up to a maximum of $195 million and a final maturity date of March 20, 2007. At
December 31, 2002, the value of this hedge was a $12.3 million liability
position. See Note 16 to the Progress Energy consolidated financial statements
for further discussion of interest rate derivatives.
Future Commitments
The following tables reflect Progress Energy's contractual cash obligations and
other commercial commitments in the respective periods in which they are due.
(in millions)
- --------------------------------------------------------------------------------------------------------------------
Contractual Cash
Obligations Total 2003 2004 2005 2006 2007 Thereafter
- --------------------------------------------------------------------------------------------------------------------
Long-term debt $ 10,082 $ 275 $ 869 $ 355 $ 909 $ 899 $ 6,775
Capital lease 45 3 3 3 3 3 30
obligations
Operating leases 293 76 59 35 25 20 78
Fuel 5,439 1,681 1,070 914 908 851 15
Purchased power 7,148 396 405 418 406 415 5,108
- --------------------------------------------------------------------------------------------------------------------
Total $ 23,007 $ 2,431 $ 2,406 $ 1,725 $ 2,251 $ 2,188 $ 12,006
Other Commercial
Commitments Total 2003 2004 2005 2006 2007 Thereafter
- --------------------------------------------------------------------------------------------------------------------
Standby letters of $ 48 $ 48 $ - $ - $ - $ - $ -
credit
Guarantees and 569 52 41 30 20 19 407
other commitments
- --------------------------------------------------------------------------------------------------------------------
Total $ 617 $ 100 $ 41 $ 30 $ 20 $ 19 $ 407
Information on the Company's contractual obligations at December 31, 2002 is
included in the notes to the Progress Energy consolidated financial statements.
Future debt maturities and lease obligations are included in Note 8 and Note 12
to the Progress Energy consolidated financial statements, respectively. The
Company's fuel and purchased power obligations are included in Note 24A and Note
24B to the Progress Energy consolidated financial statements. The Company's
guarantees and other commitments are included in Note 24C to the Progress Energy
consolidated financial statements.
FUTURE OUTLOOK
The results of continuing 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.
Regulatory issues facing Progress Energy are discussed in the "Current
Regulatory Environment" discussion under OTHER MATTERS below.
General Strategy
Progress Energy is an integrated energy company, with primary focus on the
end-use electricity market. This focus includes the generation, transmission and
distribution of electricity in both regulated and competitive markets. This
model includes the operations of the regulated utilities, CP&L and Florida
Power, and the competitive generation and fuels businesses of Progress Ventures.
60
Regulated Utilities
The regulated utility operations of CP&L and Florida Power include the
transmission and distribution of over 20,350 megawatts of generation capacity
within the traditional service areas. Additional generation capacity and
capacity uprates are planned to serve the growth expected in the Company's
service territories and to increase capacity reserve margins at the electric
utilities. CP&L and Florida Power will continue to grow their customer bases and
focus on value-added services and technologies to enhance customer
relationships. These companies will focus on achieving top quartile results for
customer satisfaction, operational excellence and cost control (expense and
capital).
Progress Ventures
The competitive energy businesses of Progress Ventures include natural gas
exploration and production; coal fuel extraction, manufacturing and delivery,
which includes synthetic fuels operations; nonregulated generation; and energy
marketing and limited trading activities on behalf of its nonregulated plants.
Progress Ventures is scheduled to complete the remaining approximate 1,545
megawatts of nonregulated generation in 2003 for a total of 3,100 megawatts of
nonregulated generation in its portfolio by the end of 2003. Progress Ventures
is actively marketing this additional generation to serve demand in the
Southeast.
Progress Energy expects the wholesale electric energy market to remain soft for
at least the next several years. Through its Progress Ventures' business, the
Company will continue to search for opportunities to secure long-term contracts
with load serving entities. Future expansion of the nonregulated generating
portfolio, if it occurs, will depend upon achieving confidence in profitable
long-term sales from acquired assets. In the meantime, Progress Ventures will
continue to develop its natural gas production asset base both as an economic
hedge for nonregulated generation and as a profitable business in its own right.
Also, Progress Ventures will continue to leverage its coal blending, storage and
transportation assets in the Ohio River Valley area.
Diversified Subsidiaries
Progress Energy plans to divest its Progress Rail subsidiary at an opportune
time. The Company expects to accomplish the divestiture within the next three
years.
Progress Energy expects its Progress Telecom subsidiary to break even in 2003
and to fund its capital needs from internally generated funds. The Company is
open to opportunities for divestiture or business combination, but it does not
see this as a high probability due to ongoing difficulty in the overall
telecommunications industry.
Financial Strategy and Expectations
Progress Energy is focused on strengthening its balance sheet. The Company has
implemented a deleveraging plan through the use of asset sales and equity
issuances through its direct stock purchase plan and employee benefit plans.
This plan also includes the issuance of equity to fund strategic acquisitions
and controlled capital spending. The Company expects its ratio of total debt to
total capitalization to decline between 200 to 300 basis points per year over
the next several years.
Progress Energy's Board of Directors reviews its dividend policy each year. In
2002, the Company increased the dividend for the fifteenth consecutive year.
Progress Energy has paid quarterly cash dividends on its common stock without
interruption since 1947.
OTHER MATTERS
Progress Ventures - Generation Acquisition
During February 2002, PVI completed the acquisition of two electric generating
projects totaling nearly 1,100 megawatts in Georgia from LG&E for a total cash
purchase price of approximately $350 million including direct transaction costs.
The two projects consist of 1) the Walton project in Monroe, Georgia, a 460
megawatt natural gas-fired plant placed in service in June 2001 and 2) the
Washington project in Washington County, Georgia, a planned 600 megawatt natural
gas-fired plant expected to be operational by June 2003. The transaction
included a power purchase agreement with LG&E Marketing for both projects
through December 31, 2004. In addition, there is a project management and
completion agreement whereby LG&E has agreed to manage the completion of the
Washington site construction for PVI in exchange for cash consideration of $181
million. The estimated costs to complete the Washington project as of December
31, 2002 are approximately $57.8 million.
61
Progress Ventures - Fuel Acquisition
On April 26, 2002, Progress Energy finalized the acquisition of Westchester Gas
Company, which includes approximately 215 natural gas-producing wells, 52 miles
of intrastate gas pipeline and 170 miles of gas-gathering systems. The aggregate
purchase price of approximately $153 million consisted of cash consideration of
approximately $22 million and the issuance of 2.5 million shares of Progress
Energy common stock valued at approximately $129 million. The purchase price
included approximately $1.7 million of direct transaction costs. The properties
are located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border. This transaction added 140 billion cubic feet (Bcf) of gas reserves to
PVI's growing energy portfolio.
Current Regulatory Environment
General
The Company's electric and gas utility operations in North Carolina, South
Carolina and Florida are regulated by the North Carolina Utility Commission
(NCUC), the Public Service Commission of South Carolina (SCPSC) and the Florida
Public Service Commission (FPSC), respectively. The electric businesses are also
subject to regulation by the Federal Energy Regulatory Commission (FERC), the
U.S. Nuclear Regulatory Commission (NRC) and other federal and state agencies
common to the utility business. In addition, the Company is subject to SEC
regulation as a registered holding company under PUHCA. As a result of
regulation, many of the fundamental business decisions, as well as the rate of
return the electric utilities and the gas utility are permitted to earn, are
subject to the approval of governmental agencies.
Electric Industry Restructuring
CP&L and Florida Power continue to monitor progress toward a more competitive
environment and have actively participated in regulatory reform deliberations in
North Carolina, South Carolina and Florida. Movement toward deregulation in
these states has been affected by recent developments, including developments
related to deregulation of the electric industry in California and other states.
o North Carolina. The Company expects the North Carolina General
Assembly will continue to monitor the experiences of states that have
implemented electric restructuring legislation.
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 December 11, 2001, the Florida 2020 Study Commission
issued its final report to the Florida Legislature. The report covered
a number of issues with recommendations in the areas of wholesale
competition and reliability, efficiency, transmission infrastructure,
environmental issues and new technologies. A key recommendation
related to wholesale competition and reliability permits the transfer
or sale of existing generation at book value and on a plant-by-plant
basis, with the sale and transfer being at the discretion of the
investor-owned utility. The Florida Legislature did not take any
action on the proposed outline or final report during the 2001 or 2002
legislative session.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
Florida Retail Rate Proceeding
On March 27, 2002, the parties in Florida Power's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC on April 23, 2002. The Agreement
is generally effective from May 1, 2002 through December 31, 2005; provided,
however, that if Florida Power's base rate earnings fall below a 10% return on
equity, Florida Power may petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues from
the sale of electricity by an annual amount of $125 million. The Agreement also
provides that Florida Power will operate under a Revenue Sharing Incentive Plan
(the Plan) through 2005, and thereafter until terminated by the FPSC, that
establishes annual revenue caps and sharing thresholds. The Plan provides that
retail base rate revenues between the sharing thresholds and the retail base
rate revenue caps will be divided into two shares - a 1/3 share to be received
by Florida Power's shareholders, and a 2/3 share to be refunded to Florida
Power's retail customers; provided, however, that for the year 2002 only, the
refund to customers will be limited to 67.1% of the 2/3 customer share. The
retail base rate revenue sharing threshold amounts for 2002 were $1.296 billion
and will increase $37 million each year thereafter. The Plan also provides that
all retail base rate revenues above the retail base rate revenue cap established
for each year will be refunded to retail customers on an annual basis. For 2002,
the refund to customers was limited to 67.1% of the retail base rate revenues
that exceed the 2002 cap. The retail base revenue cap for 2002 was $1.356
billion and will increase $37 million each year thereafter. Any amounts above
the retail base revenue caps will be refunded 100% to customers. As of December
31, 2002, $4.7 million was accrued and will be refunded to customers by March
2003.
62
Per the Agreement, Florida Power was required to refund to customers $35 million
of revenues Florida Power collected during the interim period since March 13,
2001. This one-time retroactive revenue refund was recorded in the first quarter
of 2002 and was returned to retail customers over an eight-month period ended
December 31, 2002. Any additional refunds under the Agreement are recorded when
they become probable.
See Note 15B to the Progress Energy consolidated financial statements for
additional information on the Agreement.
North Carolina Clean Air Legislation
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and sulfur
dioxide from coal-fired power plants. Progress Energy expects its capital costs
to meet these emission targets to be approximately $813 million by 2013. CP&L
currently has approximately 5,100 megawatts of coal-fired generation in North
Carolina that is affected by this legislation. The legislation requires the
emissions reductions to be completed in phases by 2013, and applies to each
utility's total system rather than setting requirements for individual power
plants. The legislation also freezes the utilities' base rates for five years
unless there are significant cost changes due to governmental action,
significant expenditures due to force majeure or other extraordinary events
beyond the control of the utilities or unless the utilities persistently earn a
return substantially in excess of the rate of return established and found
reasonable by the NCUC in the utilities' last general rate case. Further, the
legislation allows the utilities to recover from their retail customers the
projected capital costs during the first seven years of the ten-year compliance
period beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period. Pursuant
to the new law, CP&L entered into an agreement with the state of North Carolina
to transfer to the state all future emissions allowances it generates from
over-complying with the new federal emission limits when these units are
completed. The new law also requires the state to undertake a study of mercury
and carbon dioxide emissions in North Carolina. Progress Energy cannot predict
the future regulatory interpretation, implementation or impact of this new law.
Other Retail Rate Matters
See Note 15C to the Progress Energy consolidated financial statements for
additional information on the Company's other retail rate matters.
Regional Transmission Organizations and Standard Market Design
Florida Power
In early 2000, FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions that
RTOs must meet, including independent transmission service. As a result of Order
2000, Florida Power, along with Florida Power & Light Company and Tampa Electric
Company, filed with FERC, in October 2000, an application for approval of a Grid
Florida RTO. On March 28, 2001, FERC issued an order provisionally approving
GridFlorida. However, in July 2001, FERC issued orders recommending that
companies in the Southeast engage in a mediation to develop a plan for a single
RTO for the Southeast. Florida Power participated in the mediation. FERC has not
issued an order specifically on this mediation. FERC held a discussion on the
mediation report on November 24, 2001. In January 2002, FERC stated that it
would issue orders on the RTO formations for the Southeast during the first half
of 2002 after the development of a standardized market design for the wholesale
electricity market. On July 31, 2002, FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design (SMD
NOPR). The proposed rules set forth in the SMD NOPR would require, among other
things, that 1) all transmission owning utilities transfer control of their
transmission facilities to an independent third party; 2) transmission service
to bundled retail customers be provided under the FERC-regulated transmission
tariff, rather than state-mandated terms and conditions; 3) new terms and
conditions for transmission service be adopted nationwide, including new
provisions for pricing transmission in the event of transmission congestion; 4)
new energy markets be established for the buying and selling of electric energy;
and 5) load serving entities be required to meet minimum criteria for generating
reserves. If adopted as proposed, the rules set forth in the SMD NOPR would
materially alter the manner in which transmission and generation services are
provided and paid for. Florida Power, as a subsidiary of Progress Energy, filed
comments on November 15, 2002 and supplement comments on January 10, 2003. On
January 15, 2003, FERC announced the issuance of a White Paper on SMD NOPR to be
released in April 2003. Florida Power, as a subsidiary of Progress Energy, plans
to file comments on the White Paper. FERC has also indicated that it expects to
issue final rules during the summer 2003. The Company cannot predict the outcome
of these matters or the effect that they may have on the GridFlorida proceedings
currently ongoing before the FERC.
63
On May 16, 2001, the FPSC initiated dockets to review the prudence of the
GridFlorida applicants' decision to form and participate in the GridFlorida RTO.
On October 15, 2002 the FPSC abated its proceedings regarding its review of the
proposed GridFlorida RTO. The GridFlorida RTO proposal includes the formation of
a not-for-profit Independent System Operator (ISO) by the joint Applicants -
Florida Power Corporation, Florida Power & Light Company and Tampa Electric
Company. Participation is expected from many of the other transmission owners in
the state of Florida. The FPSC previously found the Applicants were prudent in
proactively forming GridFlorida but ordered the Applicants to modify their
proposal. The modifications include but are not limited to addressing 1) pricing
structure that recognizes the FPSC's jurisdiction over retail transmission
rates, 2) pricing/rate structure of long-term transmission contracts, 3)
elimination of pancaking of short-term transmission revenues, 4) cost recovery
of incremental costs imposed on the Applicants, 5) demarcation dates for new
facilities and long-term transmission contracts, and 6) market design. The FPSC
action to abate the proceedings came in response to the Florida Office of Public
Counsel's appeal before the state Supreme Court requesting review of the FPSC's
order approving the transfer of operational control of electric transmission
assets to an RTO under the jurisdiction of the FERC. It is unknown what the
outcome of this appeal will be at this time. It is unknown what impact the
future proceedings in regard to GridFlorida will have on the Company's earnings,
revenues or prices.
CP&L
In early 2000, FERC issued Order 2000 regarding RTOs. This Order set minimum
characteristics and functions that RTOs must meet, including independent
transmission service. In October 2000, as a result of Order 2000, CP&L, along
with Duke Energy Corporation and South Carolina Electric & Gas Company, filed an
application with the FERC for approval of a GridSouth RTO. On July 12, 2001,
FERC issued an order provisionally approving GridSouth. However, in July 2001,
FERC issued orders recommending that companies in the Southeast engage in a
mediation to develop a plan for a single RTO for the Southeast. CP&L
participated in the mediation. FERC has not issued an order specifically on this
mediation. FERC held a discussion on the mediation report on November 24, 2001.
In January 2002, FERC stated that it would issue orders on the RTO formations
for the Southeast during the first half of 2002 after the development of a
standardized market design for the wholesale electricity market. On July 31,
2002, FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000,
Remedying Undue Discrimination through Open Access Transmission Service and
Standard Electricity Market Design (SMD NOPR). The proposed rules set forth in
the SMD NOPR would require, among other things, that 1) all transmission owning
utilities transfer control of their transmission facilities to an independent
third party; 2) transmission service to bundled retail customers be provided
under the FERC-regulated transmission tariff, rather than state-mandated terms
and conditions; 3) new terms and conditions for transmission service be adopted
nationwide, including new provisions for pricing transmission in the event of
transmission congestion; 4) new energy markets be established for the buying and
selling of electric energy; and 5) load serving entities be required to meet
minimum criteria for generating reserves. If adopted as proposed, the rules set
forth in the SMD NOPR would materially alter the manner in which transmission
and generation services are provided and paid for. CP&L, as a subsidiary of
Progress Energy, filed comments on November 15, 2002 and supplement comments on
January 10, 2003. On January 15, 2003, FERC announced the issuance of a White
Paper on SMD NOPR to be released in April 2003. CP&L, as a subsidiary of
Progress Energy, plans to file comments on the White Paper. FERC has also
indicated that it expects to issue final rules during the summer 2003. The
Company cannot predict the outcome of these matters or the effect that they may
have on the GridSouth proceedings currently ongoing before FERC.
CP&L applied to the NCUC and the SCPSC for permission to transfer operational
control of its transmission assets to GridSouth. On June 21, 2001, the Public
Staff of the NCUC filed a motion asking the NCUC to hold the GridSouth docket in
abeyance until the U.S. Supreme Court had ruled on the appeal of FERC's Order
No. 888. That appeal addresses the scope of FERC's jurisdiction over
transmission service used to serve retail customers. The appeal of Order No. 888
was heard by the Court on October 3, 2001, and its decision affirmed FERC's
order. The NCUC issued an order holding that CP&L's and Duke Energy
Corporation's petition to transfer operational control of their transmission
assets to GridSouth shall be held in abeyance pending further order. In February
2002, CP&L and the other GridSouth applicants withdrew the GridSouth application
from the NCUC and SCPSC for purposes of making certain revisions to the
GridSouth proposal. The Company has $28.4 million invested in GridSouth at
December 31, 2002. It is unknown what impact the future proceedings in regard to
GridSouth will have on the Company's earnings, revenues or prices.
64
Franchise Litigation
Six cities, with a total of approximately 49,000 customers, have sued Florida
Power in various circuit courts in Florida. The lawsuits principally seek 1) a
declaratory judgment that the cities have the right to purchase Florida Power's
electric distribution system located within the municipal boundaries of the
cities, 2) a declaratory judgment that the value of the distribution system must
be determined through arbitration, and 3) injunctive relief requiring Florida
Power to continue to collect from Florida Power's customers and remit to the
cities, franchise fees during the pending litigation, and as long as Florida
Power continues to occupy the cities' rights-of-way to provide electric service,
notwithstanding the expiration of the franchise ordinances under which Florida
Power had agreed to collect such fees. Five circuit courts have entered orders
requiring arbitration to establish the purchase price of Florida Power's
electric distribution system within five cities. Two appellate courts have
upheld those circuit court decisions and authorized cities to determine the
value of Florida Power's electric distribution system within the cities through
arbitration. To date, no city has attempted to actually exercise the right to
purchase any portion of Florida Power's electric distribution system.
Arbitration in one of the cases was held in August 2002 and an award was issued
in October 2002 setting the value of Florida Power's distribution system within
one city at approximately $22 million. At this time, whether and when there will
be further proceedings following this award cannot be determined. Additional
arbitrations have been scheduled to occur in the first and second quarters of
2003.
As part of the above litigation, two appellate courts have also reached opposite
conclusions regarding whether Florida Power must continue to collect from its
customers and remit to the cities "franchise fees" under the expired franchise
ordinances. Florida Power has filed an appeal with the Florida Supreme Court to
resolve the conflict between the two appellate courts. The Florida Supreme Court
has issued an order setting a briefing schedule and reserving ruling on
accepting jurisdiction. On January 12, 2003, Florida Power served its Initial
Brief in the Supreme Court and its request for oral argument. Three amicus
curiae also filed motions seeking leave to participate in support of Florida
Power's position and filed amicus briefs. No oral argument has yet been set. The
Company cannot predict the outcome of these matters at this time.
Nuclear
In the Company's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdictions, the provisions
for nuclear decommissioning costs are approved by FERC. See Note 1H to the
Progress Energy consolidated financial statements for a discussion of the
Company's nuclear decommissioning costs.
Spent Fuel Storage
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
meant that CP&L was able to complete cooling systems and to begin installing
storage racks in its third and fourth storage pools at the Harris Plant.
Pressurized Water Reactors
On March 18, 2002, the NRC sent a bulletin to companies that hold licenses for
pressurized water reactors (PWRs) requiring information on the structural
integrity of the reactor vessel head and a basis for concluding that the vessel
head will continue to perform its function as a coolant pressure boundary. The
Company filed responses as required. Inspections of the vessel heads at the
Company's PWR plants have been performed during previous outages. In October
2001, at the Crystal River Plant (CR3), one nozzle was found to have a crack and
was repaired; however, no degradation of the reactor vessel head was identified.
Current plans are to replace the vessel head at CR3 during its next regularly
scheduled refueling outage in 2003. At the Robinson Plant, an inspection was
completed in April 2001 and no penetration nozzle cracking was identified and
there was no degradation of the reactor vessel head. At the Harris Plant,
sufficient inspections were completed during the last refueling outage in the
fourth quarter of 2001 to conclude there is no degradation of the reactor vessel
head. The Company's Brunswick Plant has a different design and is not affected
by the issue.
On August 9, 2002, the NRC issued an additional bulletin dealing with head
leakage due to cracks near the control rod nozzles. The NRC has asked licensees
to commit to high inspection standards to ensure the more susceptible plants
have no cracks. The Robinson Plant is in this category and had a refueling
outage in October 2002. The Company completed a series of examinations in
October 2002 of the entire reactor pressure vessel head and found no indications
of control rod drive mechanism cracking and no corrosion of the head itself.
During the outage, a boric acid leakage walkdown of the reactor coolant pressure
boundary was also completed and no corrosion was found. For CR3, the Company has
responded to the NRC that previous inspections are sufficient until the reactor
head is replaced in the fall of 2003. For the Harris Plant, the Company does not
plan further inspections until its next regularly scheduled outage in spring of
2003.
65
In February 2003, the NRC issued Order EA-03-009, requiring specific inspections
of the reactor pressure vessel head and associated penetration nozzles at PWRs.
The Company has responded to the Order, stating that the Company intends to
comply with the previsions of the order. No adverse impact is anticipated.
Security
On February 25, 2002, the NRC issued an interim compensatory measure with regard
to security at nuclear plants. This order formalized many of the security
enhancements made at the Company's nuclear plants since September 2001. This
order includes additional restrictions on access, increased security presence
and closer coordination with the Company's partners in intelligence, military,
law enforcement and emergency response at the federal, state and local levels.
The Company completed the requirements by the established deadlines and expects
the NRC to perform an inspection for compliance in the near future.
In addition, in January 2003 the NRC issued a final order with regards to access
control. This order requires the Company to enhance its current access control
program by January 7, 2004. The Company expects that it will be in full
compliance with the order by the established deadline.
As the NRC, other governmental entities and the industry continue to consider
security issues, it is possible that more extensive security plans could be
required.
Synthetic Fuels Tax Credits
Progress Energy, through the Progress Ventures business segment, produces
synthetic fuel from coal fines. The production and sale of the synthetic fuel
qualifies for tax credits under Section 29 if certain requirements are
satisfied, including a requirement that the synthetic fuel differs significantly
in chemical composition from the feedstock used to produce such synthetic fuel.
Any synthetic fuel tax credit amounts not utilized are carried forward
indefinitely and are included in deferred taxes on the accompanying Consolidated
Balance Sheet. See Note 20 to the Progress Energy consolidated financial
statements. All of Progress Energy's synthetic fuel facilities have received
private letter rulings from the IRS with respect to their operations. These tax
credits are subject to review by the IRS, and if Progress Energy fails to
prevail through the administrative or legal process, there could be a
significant tax liability owed for previously taken Section 29 credits, with a
significant impact on earnings and cash flows. Tax credits for the 12 months
ended December 31, 2002 and 2001, were $291 million and $349 million,
respectively. Total Section 29 credits generated to date (including FPC prior to
its acquisition by the Company) are approximately $897.2 million.
One synthetic fuel entity, Colona Synfuel Limited Partnership, L.L.L.P.
(Colona), from which the Company (and FPC prior to its acquisition by the
Company) has been allocated approximately $251 million in tax credits to date,
is being audited by the IRS. The audit of Colona was expected. The Company is
audited regularly in the normal course of business, as are most similarly
situated companies. In September 2002, all of Progress Energy's majority-owned
synthetic fuel entities, including Colona, were accepted into the IRS Pre-Filing
Agreement (PFA) program. The PFA program allows taxpayers to voluntarily
accelerate the IRS exam process in order to seek resolution of specific issues.
Either the Company or the IRS can withdraw from the program at any time, and
issues not resolved through the program may proceed to the next level of the IRS
exam process. While the ultimate outcome is uncertain, the Company believes that
participation in the PFA program will likely shorten the tax exam process. In
management's opinion, Progress Energy is complying with the private letter
rulings and all the necessary requirements to be allowed such credits under
Section 29 and believes it is likely, although it cannot provide certainty, that
it will prevail if challenged by the IRS on any credits taken. The current
Section 29 tax credit program expires in 2007.
The Company has retained an advisor to assist in selling an interest in one or
more synthetic fuel entities. The Company is pursuing the sale of a portion of
its synthetic fuel production capacity that is underutilized due to limits on
the amount of credits that can be generated and utilized by the Company. The
Company would expect to retain an ownership interest and to operate any sold
facility for a management fee. The final outcome and timing of these discussions
is uncertain and the Company cannot predict the outcome of this matter.
Environmental Matters
The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters. These environmental matters are discussed in detail in Note 24 to the
Progress Energy consolidated financial statements. This discussion identifies
specific environmental issues, the status of the issues, accruals associated
with issue resolutions and the associated exposures to the Company.
66
New Accounting Standards
See Note 1U and Note 6 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.
The following Management's Discussion and Analysis and the information
incorporated herein by reference contain forward-looking statements that involve
estimates, projections, goals, forecasts, assumptions, risks and uncertainties
that could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. Please review "Rick Factors" and
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors
that may impact any such forward-looking statements made herein.
RESULTS OF OPERATIONS
Note 1 to the CP&L consolidated financial statements discusses its significant
accounting policies. The most critical accounting policies and estimates that
impact CP&L's financial statements are the economic impacts of utility
regulation and asset impairment policies, which are described in more detail in
the Progress Energy Management's Discussion and Analysis section.
On July 1, 2000, CP&L distributed its ownership interest in the stock of NCNG,
SRS, Monroe Power and PVI to Progress Energy. Prior to that date, the
consolidated operations of CP&L and Progress Energy were substantially the same.
Subsequent to July 1, 2000, the operations of these subsidiaries are no longer
included in CP&L's results of operations or financial position.
The results of operations for the CP&L Electric segment are identical between
CP&L and Progress Energy for all periods presented. The primary difference
between the results of operations of the CP&L Electric segment and the
consolidated CP&L results of operations for the 2000, 2001 and 2002 comparison
periods relate to the non-electric operations, as summarized below:
(in millions) 2002 2001 2000
--------- --------- ----------
CP&L Electric net income $ 513.1 $ 468.3 $ 373.8
Caronet net income (loss) (79.4) (99.5) 81.0
Other non-electric net income (loss) (5.7) (7.5) 3.3
--------- --------- ----------
Earnings for common stock $ 428.0 $ 361.3 $ 458.1
========= ========= ==========
Caronet's results of operations for 2002 and 2001 include after-tax impairments
of $87.4 million and $102.4 million, respectively, for other-than-temporary
declines in the value of the assets of Caronet and Caronet's investment in
Interpath. The Interpath investment was sold in December 2002 for a nominal
amount. Caronet's results of operations for 2000 include the $121.1 million
after-tax gain from the sale of the BellSouth Carolinas PCS assets in September
2000. See Note 2 to the CP&L consolidated financial statements for further
discussion of this divestiture.
67
LIQUIDITY AND CAPITAL RESOURCES
The statements of cash flows for CP&L do not include amounts related to NCNG,
SRS, Monroe Power or PVI after July 1, 2000. Additionally, the CP&L statements
of cash flows do not include any amounts related to the acquisition of FPC or
the issuance of debt to consummate the transaction.
CP&L's estimated capital requirements for 2003, 2004 and 2005 are $620 million,
$690 million and $650 million, respectively, and primarily reflect construction
expenditures to support customer growth, 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 at December 31, 2002, and the discussion
above for Progress Energy under "Financing Activities" for information regarding
CP&L's financing activities.
FUTURE COMMITMENTS
The following tables reflect CP&L's contractual cash obligations and other
commercial commitments in the respective periods in which they are due.
(in millions)
- ------------------------------------------------------------------------------------------------------------
Contractual Cash Total Amounts
Obligations Committed 2003 2004 2005 2006 2007 Thereafter
- ------------------------------------------------------------------------------------------------------------
Long-term debt $ 3,065 $ - $ 300 $ 307 $ - $ 200 $ 2,258
Capital lease
obligations 31 2 2 2 2 2 21
Operating leases 44 10 8 6 4 4 12
Fuel 1,812 500 434 351 312 199 16
Purchased power 1,073 97 97 97 97 97 588
- ------------------------------------------------------------------------------------------------------------
Total $ 6,025 $ 609 $ 841 $ 763 $ 415 $ 502 $ 2,895
Other Commercial Total Amounts
Commitments Committed 2003 2004 2005 2006 2007 Thereafter
- ------------------------------------------------------------------------------------------------------------
Standby letters of
credit $ 5 $ 5 $ - $ - $ - $ - $ -
Guarantees and
other commitments 1 - - - - - 1
- ------------------------------------------------------------------------------------------------------------
Total $ 6 $ 5 $ - $ - $ - $ - $ 1
Information on CP&L's contractual obligations at December 31, 2002 is included
in the notes to the CP&L consolidated financial statements. Future debt
maturities and lease obligations are included in Note 6 and Note 7,
respectively, to the CP&L consolidated financial statements. CP&L's fuel and
purchased power obligations are included in Note 18A to the CP&L consolidated
financial statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PROGRESS ENERGY, INC.
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Certain market risks are inherent in the Company's financial
instruments, which arise from transactions entered into in the normal course of
business. The Company's primary exposures are changes in interest rates with
respect to its long-term debt and commercial paper, and fluctuations in the
return on marketable securities with respect to its nuclear decommissioning
trust funds. The Company manages its market risk in accordance with its
established risk management policies, which may include entering into various
derivative transactions.
These financial instruments are held for purposes other than trading. The fair
value of the Company's open trading positions was less than a $0.4 million
liability position at December 31, 2002. The risks discussed below do not
include the price risks associated with nonfinancial instrument transactions or
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, 2002 and 2001, about
the Company's interest rate risk sensitive instruments. The tables present
principal cash flows and weighted-average interest rates by expected maturity
dates for the fixed and variable rate long-term debt and FPC obligated
mandatorily redeemable securities of trust. The tables also include estimates of
the fair value of the Company's interest rate risk sensitive instruments based
on quoted market prices for these or similar issues. For interest-rate swaps and
interest-rate forward contracts, the tables present notional amounts and
weighted-average interest rates by contractual maturity dates. Notional amounts
are used to calculate the contractual cash flows to be exchanged under the
interest-rate swaps and the settlement amounts under the interest-rate forward
contracts. See "Interest Rate Derivatives" under LIQUIDITY AND CAPITAL RESOURCES
above for more information on interest rate derivatives.
December 31, 2002 Fair Value
December 31,
(Dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002
- --------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 275 $ 869 $ 355 $ 909 $ 674 $ 5,614 $ 8,696 $ 9,584
Average interest rate 6.42% 6.66% 7.38% 6.78% 6.41% 6.90% 6.83%
Variable rate long-term debt - - - - $ 225 $ 861 $ 1,086 $ 1,087
Average interest rate - - - - 0.03% 1.24% 1.61% -
FPC mandatorily redeemable
securities of trust - - - - - $ 300 $ 300 $ 303
Interest rate 7.10% 7.10% -
Interest rate swaps:
Pay fixed/receive variable(a) - - - - $ 350 - $ 350 $ 5.2
Interest rate forward
contracts(b) $ 35 - - - - - $ 35 $ (0.5)
Interest rate collars(c) $ 195 $ 195 $ (12.3)
(a) Receives floating rate based on three-month LIBOR and pays fixed rate of
7.17%. Designated as hedge of $350 million of fixed rate debt.
(b) Treasury Rate Lock agreement on $35 million designated as fair value hedge
of anticipated debt issuance.
(c) Interest rate collars on $195 million notional. Designated as hedge of
variable rate interest.
69
December 31, 2001 Fair Value
December 31,
(Dollars in millions) 2002 2003 2004 2005 2006 Thereafter Total 2001
- --------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 188 $ 283 $ 869 $ 348 $ 909 $ 5,379 $ 7,976 $ 8,322
Average interest rate 6.38% 6.42% 6.67% 7.39% 6.78% 6.97% 6.90% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - 1.58% 1.58% -
Extendible notes $ 500 - - - - - $ 500 $ 500
Average interest rate -
variable rate 2.83% - - - - - 2.83% -
FPC mandatorily redeemable
securities of trust - - - - - $ 300 $ 300 $ 291
Fixed rate - 7.10% 7.10% -
Interest rate swaps:
Pay fixed/receive variable (a) $ 500 - - - - - $ 500 $ (18.5)
(a) Receives floating rate based on three-month LIBOR and pays fixed rate of
7.17%. Designated as a hedge of interest payments on $500 million of
extendible notes.
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents, which
are exposed to price fluctuations in equity markets and to changes in interest
rates. The fair value of these funds was $796.8 million and $822.8 million at
December 31, 2002 and 2001, respectively. The Company actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, target allocation
percentages for various asset classes. The accounting for nuclear
decommissioning recognizes that the Company's regulated electric rates provide
for recovery of these costs net of any trust fund earnings and, therefore,
fluctuations in trust fund marketable security returns do not affect the
earnings of the Company.
Contingent Value Obligations Market Value Risk
In connection with the acquisition of FPC, the Company issued 98.6 million
contingent value obligations (CVOs). Each CVO represents the right to receive
contingent payments based on the performance of four synthetic fuel facilities
purchased by subsidiaries of FPC in October 1999. The payments, if any, are
based on the net after-tax cash flows the facilities generate. These CVOs are
recorded at fair value and unrealized gains and losses from changes in fair
value are recognized in earnings. At December 31, 2002 and 2001, the fair value
of these CVOs was $13.8 million and $41.9 million, respectively. A hypothetical
10% decrease in the December 31, 2002 market price would result in a $1.4
million decrease in the fair value of the CVOs.
70
CAROLINA POWER & LIGHT COMPANY
The information required by this item is incorporated herein by reference to the
Progress Energy Quantitative and Qualitative Disclosures About Market Risk
insofar as it relates to CP&L.
The following tables provide information as of December 31, 2002 and 2001, about
CP&L's interest rate risk sensitive instruments.
December 31, 2002
- ----------------- Fair Value
December 31,
(dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002
- --------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt - $ 300 $ 307 - $ 200 $ 1,638 $ 2,445 $ 2,708
Average interest rate - 6.87% 7.48% - 6.80% 6.61% 6.76% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 620
Average interest rate - - - - - 1.29% 1.29% -
December 31, 2001
- ----------------- Fair Value
December 31,
(dollars in millions) 2002 2003 2004 2005 2006 Thereafter Total 2001
- --------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 100 $ 7 $ 300 $ 300 - $ 1,488 $ 2,195 $ 2,274
Average interest rate 6.75% 6.43% 6.87% 7.50% - 6.88% 6.96% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - 1.58% 1.58% -
Extendible notes $ 500 - - - - - $ 500 $ 500
Average interest rate -
variable rate 2.83% - - - - - 2.83% -
Interest rate swaps:
Pay fixed/receive variable (a) $ 500 - - - - - $ 500 $ (18.5)
(a) Receives floating rate based on three-month LIBOR and pays fixed rate of
7.17%. Designated as a hedge on $500 million of Extendible notes.
71
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements, supplementary data and
consolidated financial statement schedules are included herein:
Page
Progress Energy, Inc.
Independent Auditors' Report 73
Consolidated Financial Statements - Progress Energy, Inc.:
Consolidated Statements of Income for the Years Ended December 31, 2002, 2001 and 2000 74
Consolidated Balance Sheets as of December 31, 2002 and 2001 75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000 76
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2002,
2001 and 2000 77
Consolidated Quarterly Financial Data (Unaudited) 78
Notes to Consolidated Financial Statements 79
Carolina Power & Light Company
Independent Auditors' Report 124
Consolidated Financial Statements - Carolina Power & Light Company:
Consolidated Statements of Income and Comprehensive Income for the Years Ended
December 31, 2002, 2001, and 2000 125
Consolidated Balance Sheets as of December 31, 2002 and 2001 126
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001
and 2000 127
Consolidated Schedules of Capitalization as of December 31, 2002 and 2001 128
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2002, 2001
and 2000 128
Consolidated Quarterly Financial Data (Unaudited) 128
Notes to Consolidated Financial Statements 129
Independent Auditors' Report on Consolidated Financial Statement Schedule - Progress Energy, Inc. 155
Independent Auditors' Report on Consolidated Financial Statement Schedule - Carolina Power &
Light Company 156
Consolidated Financial Statement Schedules for the Years Ended December 31,
2002, 2001 and 2000:
II-Valuation and Qualifying Accounts - Progress Energy, Inc. 157
II-Valuation and Qualifying Accounts - Carolina Power & Light Company 158
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.
72
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress Energy,
Inc. and its subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of income, changes in common stock equity and cash flows
for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company and its subsidiaries at December
31, 2002 and 2001, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2002, in conformity
with accounting principles generally accepted in the United States of America.
As discussed in Note 6 to the financial statements, in 2002 the Company changed
its method of accounting for goodwill to conform to Statement of Financial
Accounting Standards No. 142.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
73
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
Years ended December 31
(In thousands except per share data) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 6,600,689 $ 6,556,561 $ 3,545,694
Diversified business 1,344,431 1,528,819 223,228
- ---------------------------------------------------------------------------------------------------------------
Total Operating Revenues 7,945,120 8,085,380 3,768,922
- ---------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 1,614,879 1,559,998 682,627
Purchased power 862,395 868,078 364,977
Operation and maintenance 1,361,189 1,210,750 792,164
Depreciation and amortization 820,279 1,067,073 735,353
Taxes other than on income 386,254 379,830 162,268
Diversified business
Cost of sales 1,433,626 1,422,890 81,376
Impairment of long-lived assets 363,822 42,852 -
Other 98,193 304,817 266,931
- ---------------------------------------------------------------------------------------------------------------
Total Operating Expenses 6,940,637 6,856,288 3,085,696
- ---------------------------------------------------------------------------------------------------------------
Operating Income 1,004,483 1,229,092 683,226
- ---------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 14,526 22,481 18,353
Impairment of investments (25,011) (164,183) -
Gain on sale of investment - - 200,000
Other, net 33,804 (28,439) 15,423
- ---------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 23,319 (170,141) 233,776
- ---------------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 641,574 689,694 261,570
Allowance for borrowed funds used during construction (8,133) (16,801) (18,992)
- ---------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 633,441 672,893 242,578
- ---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax 394,361 386,058 674,424
Income Tax Expense (Benefit) (157,808) (154,338) 196,502
- ---------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 552,169 540,396 477,922
Discontinued Operations, net of tax (23,783) 1,214 439
- ---------------------------------------------------------------------------------------------------------------
Net Income $ 528,386 $ 541,610 $ 478,361
- ---------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 217,247 204,683 157,169
- ---------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations $ 2.54 $ 2.64 $ 3.04
Discontinued Operations, Net of Tax (.11) .01 .00
Net Income $ 2.43 $ 2.65 $ 3.04
- ---------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations $ 2.53 $ 2.63 $ 3.03
Discontinued Operations, Net of Tax (.11) .01 .00
Net Income $ 2.42 $ 2.64 $ 3.03
- ---------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.195 $ 2.135 $ 2.075
- ---------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
74
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands except per share data) December 31
Assets 2002 2001
- ----------------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 20,152,787 $ 19,176,021
Accumulated depreciation (10,480,880) (9,936,514)
- ----------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 9,671,907 9,239,507
Held for future use 15,109 15,380
Construction work in progress 752,336 1,004,011
Nuclear fuel, net of amortization 216,882 262,869
- ----------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 10,656,234 10,521,767
- ----------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 61,358 53,708
Accounts receivable 737,369 779,286
Unbilled accounts receivable 225,011 199,593
Inventory 875,485 871,643
Deferred fuel cost 183,518 146,652
Assets of discontinued operations 490,429 552,458
Prepayments and other current assets 283,036 294,460
- ----------------------------------------------------------------------------------------------------------------------
Total Current Assets 2,856,206 2,897,800
- ----------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 393,215 463,837
Nuclear decommissioning trust funds 796,844 822,821
Diversified business property, net 1,884,271 1,072,123
Miscellaneous other property and investments 463,776 441,932
Goodwill 3,719,327 3,656,970
Prepaid pension costs 60,169 487,551
Other assets and deferred debits 522,662 525,900
- ----------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 7,840,264 7,471,134
- ----------------------------------------------------------------------------------------------------------------------
Total Assets $ 21,352,704 $ 20,890,701
- ----------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- ----------------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500,000,000 shares authorized, 237,992,513 and
218,725,352 shares issued and outstanding,
respectively $ 4,950,558 $ 4,121,194
Unearned restricted shares (950,180 and 674,511 shares, respectively) (21,454) (13,701)
Unearned ESOP shares (4,616,400 and 5,199,388 shares, respectively) (101,560) (114,385)
Accumulated other comprehensive loss (237,762) (32,180)
Retained earnings 2,087,227 2,042,605
- ----------------------------------------------------------------------------------------------------------------------
Total common stock equity 6,677,009 6,003,533
- ----------------------------------------------------------------------------------------------------------------------
Preferred stock of subsidiaries-Not Subject to Mandatory Redemption 92,831 92,831
Long-Term debt 9,747,293 8,618,960
- ----------------------------------------------------------------------------------------------------------------------
Total capitalization 16,517,133 14,715,324
- ----------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 275,397 688,052
Accounts payable 756,287 760,116
Interest accrued 220,400 211,731
Dividends declared 132,232 117,857
Short-term obligations 694,850 942,314
Customer deposits 158,214 151,968
Liabilities of discontinued operations 124,767 162,917
Other current liabilities 372,161 403,868
- ----------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,734,308 3,438,823
- ----------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 932,813 1,408,155
Accumulated deferred investment tax credits 206,221 224,688
Regulatory liabilities 119,766 291,789
Other liabilities and deferred credits 842,463 811,922
- ----------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 2,101,263 2,736,554
- ----------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 24)
- ----------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 21,352,704 $ 20,890,701
- ----------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements
75
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 528,386 $ 541,610 $ 478,361
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (income) from discontinued operations 23,783 (1,214) (439)
Impairment of long-lived assets and investments 388,833 208,983 -
Depreciation and amortization 1,099,128 1,266,162 846,984
Deferred income taxes (402,040) (367,330) (93,379)
Investment tax credit (18,467) (22,701) (17,942)
Gain on sale of investment - - (200,000)
Deferred fuel cost (credit) (36,866) 68,705 (81,604)
Net (increase) decrease in accounts receivable (45,172) 182,514 (34,754)
Net (increase) decrease in inventories (48,785) (298,733) 15,931
Net (increase) decrease in prepayments and other current assets (39,141) (20,797) 57,141
Net increase (decrease) in accounts payable 57,387 (162,940) 229,117
Net increase (decrease) in other current liabilities 56,356 123,297 (148,813)
Other 34,509 (94,806) (197,725)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,597,911 1,422,750 852,878
- ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (1,174,220) (1,177,727) (853,584)
Diversified business property additions and acquisitions (934,910) (349,713) (157,510)
Nuclear fuel additions (80,573) (115,663) (59,752)
Acquisition of Florida Progress Corporation, net of cash - - (3,441,775)
Net proceeds from sale of assets and investment 42,825 53,010 200,000
Net contributions to nuclear decommissioning trust (18,502) (50,649) (32,391)
Investments in non-utility activities (27,030) (15,043) (89,351)
Other (19,424) - -
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (2,211,834) (1,655,785) (4,434,363)
- ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 687,000 488,290 -
Issuance of long-term debt, net 1,797,691 4,564,243 783,052
Net increase (decrease) in short-term indebtedness (247,464) (4,018,062) 3,782,071
Net increase (decrease) in cash provided by checks drawn in excess of bank balances 79 (45,372) 115,337
Retirement of long-term debt (1,157,286) (322,207) (710,373)
Dividends paid on common stock (479,981) (432,078) (368,004)
Other 21,482 (47,127) (66)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Financing Activities 621,521 187,687 3,602,017
- ---------------------------------------------------------------------------------------------------------------------------------
Cash Provided by (Used in) Discontinued Operations 52 (843) 525
- ---------------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 7,650 (46,191) 21,057
Cash and Cash Equivalents at Beginning of Year 53,708 99,899 78,842
- ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 61,358 $ 53,708 $ 99,899
- ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 630,935 $ 588,127 $ 244,224
income taxes (net of refunds) $ 219,278 $ 127,427 $ 367,665
Noncash Activities
o On June 28, 2000, Caronet, Inc., 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.
o On November 30, 2000, the Company purchased all outstanding shares of
Florida Progress Corporation. In conjunction with the purchase, the Company
issued approximately $1.9 billion in common stock and $49.3 million in
contingent value obligations.
o On April 26, 2002, Progress Fuels Corporation, a subsidiary of the Company,
acquired 100% of Westchester Gas Company. In conjunction with the purchase,
the Company issued approximately $129.0 million in common stock.
See Notes to Consolidated Financial Statements
76
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES IN COMMON STOCK EQUITY
Unearned Accumulated Total
Unearned ESOP Other Common
(In thousands except share data) Common Stock Outstanding Restricted Common Comprehensive Retained Stock
Shares Amount Stock Stock Income (Loss) Earnings Equity
- -----------------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2000 159,599,650 $ 1,753,393 $ (7,938) $ (140,153) $ - $ 1,807,345 $3,412,647
Net income 478,361 478,361
Issuance of shares 46,527,797 1,863,886 1,863,886
Purchase of restricted stock (10,067) (10,067)
Restricted stock expense recognition 3,671 3,671
Cancellation of restricted shares (38,400) (1,626) 1,626 -
Allocation of ESOP shares 5,957 12,942 18,899
Dividends ($2.075 per share) (343,196) (343,196)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000 206,089,047 3,621,610 (12,708) (127,211) - 1,942,510 5,424,201
Net income 541,610 541,610
FAS 133 transition adjustment (net of
tax of $15,130) (23,567) (23,567)
Change in net unrealized losses on cash
flow hedges (net of tax of $13,268) (20,703) (20,703)
Reclassification adjustment for amounts
included in net income (net of tax of
$8,739) 13,647 13,647
Foreign currency translation and other (1,557) (1,557)
-----------
Comprehensive income 509,430
-----------
Issuance of shares 12,658,027 488,592 488,592
Purchase of restricted stock (7,992) (7,992)
Restricted stock expense recognition 6,084 6,084
Cancellation of restricted shares (21,722) (915) 915 -
Allocation of ESOP shares 11,907 12,826 24,733
Dividends ($2.135 per share) (441,515) (441,515)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 218,725,352 4,121,194 (13,701) (114,385) (32,180) 2,042,605 6,003,533
Net income 528,386 528,386
Change in net unrealized losses on cash
flow hedges (net of tax of $17,712) (27,920) (27,920)
Reclassification adjustment for amounts
included in net income (net of tax of
$10,480) 16,307 16,307
Foreign currency translation and other (1,584) (1,584)
Minimum pension liability adjustment
(net of tax of $120,903) (192,385) (192,385)
-----------
Comprehensive income 322,804
-----------
Issuance of shares 19,282,212 815,393 815,393
Purchase of restricted stock (16,197) (16,197)
Restricted stock expense recognition 7,709 7,709
Cancellation of restricted shares (15,051) (735) 735 -
Allocation of ESOP shares 14,706 12,825 27,531
Dividends ($2.195 per share) (483,764) (483,764)
- -----------------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 237,992,513 $ 4,950,558 $(21,454) $ (101,560) $ (237,762) $ 2,087,227 $6,677,009
===================================================================================================================================
See Notes to Consolidated Financial Statements
77
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In thousands except per share data) First Quarter Second Quarter Third Quarter Fourth Quarter
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $1,787,302 $1,958,855 $2,277,040 $1,921,923
Operating income 241,981 305,288 200,221 256,993
Income from continuing operations 124,062 121,933 157,073 149,101
Net income 132,527 120,620 151,934 123,305
Common stock data:
Basic earnings per common share
Income from continuing operations 0.58 0.57 0.73 0.66
Net income 0.62 0.56 0.70 0.55
Diluted earnings per common share
Income from continuing operations 0.58 0.56 0.72 0.66
Net income 0.62 0.56 0.70 0.55
Dividends paid per common share 0.545 0.545 0.545 0.545
Market price per share - High 50.86 52.70 51.97 44.82
Low 43.01 47.91 36.54 32.84
- ---------------------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues $1,755,839 $2,233,383 $2,265,223 $1,830,935
Operating income 295,611 288,898 455,475 189,108
Income (loss) from continuing operations 146,807 117,080 369,733 (93,224)
Net income (loss) 154,003 111,702 366,443 (90,538)
Common stock data:
Basic earnings per common share
Income from continuing operations 0.73 0.59 1.80 (0.44)
Net income 0.77 0.56 1.78 (0.43)
Diluted earnings per common share
Income from continuing operations 0.73 0.58 1.79 (0.44)
Net income 0.77 0.56 1.77 (0.42)
Dividends paid per common share 0.530 0.530 0.530 0.530
Market price per share - High 49.25 45.00 45.79 45.60
Low 38.78 40.36 39.25 40.50
o In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
All amounts were restated for discontinued operations (See Note 3A).
o Second quarter 2001 includes seven months of revenue related to Progress
Rail Services due to reversal of net assets held for sale accounting
treatment.
o Fourth quarter 2001 includes impairment and other charges related to
Strategic Resource Solutions Corp. and Interpath Communications, Inc. of
$209.0 million ($152.8 million after tax) (See Note 7).
o Third quarter 2002 includes impairment and other charges related to Progress
Telecom, Caronet and Interpath Communications, Inc. of $355.4 million
($224.8 million after tax) (See Note 7).
o Fourth quarter 2002 includes estimated impairment on assets held for sale of
Railcar Ltd. of $58.8 million ($40.1 million after tax) (See Note 3B).
See Notes to Consolidated Financial Statements.
78
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a registered
holding company under the Public Utility Holding Company Act of 1935
(PUHCA), as amended. The Company and its subsidiaries are subject to the
regulatory provisions of PUHCA. The Company was formed as a result of the
reorganization of Carolina Power & Light Company (CP&L) into a holding
company structure (CP&L Energy, Inc.) on June 19, 2000. All shares of common
stock of CP&L were exchanged for an equal number of shares of CP&L Energy,
Inc. 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 and Florida Power Corporation
(Florida Power), the Company is primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina, South Carolina and Florida. Through the Progress Ventures business
unit, the Company is involved in nonregulated generation operations; natural
gas fuel exploration and production; coal fuel extraction, manufacturing and
delivery; and energy marketing and trading activities. Through the Rail
Services business unit, the Company is involved in nonregulated railcar
repair, rail parts reconditioning and sales, railcar leasing and sales, and
scrap metal recycling. Through its other business units, the Company engages
in other nonregulated business areas, including telecommunications and
holding company operations. Progress Energy's legal structure is not
currently aligned with the functional management and financial reporting of
the Progress Ventures business segment. Whether, and when, the legal and
functional structures will converge depends upon legislative and regulatory
action, which cannot currently be anticipated. Effective January 1, 2003,
CP&L, Florida Power and Progress Ventures, Inc. (PVI) began doing business
under the assumed names Progress Energy Carolinas, Inc., Progress Energy
Florida, Inc., and Progress Energy Ventures, Inc., respectively. The legal
names of these entities have not changed, and there is no restructuring of
any kind related to the name change. The current corporate and business unit
structure remains unchanged.
The Company's results of operations include the results of Florida Progress
Corporation (FPC) for the periods subsequent to November 30, 2000;
therefore, periods presented may not be comparable (See Note 2C).
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of the Company and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable and
the future recovery of the sales price through the ratemaking process is
probable. See Note 1K for a discussion of SFAS No. 71.
The accounting records of CP&L, Florida Power and North Carolina Natural Gas
Corporation (NCNG) 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).
Unconsolidated investments in companies over which the Company does not have
control, but has the ability to exercise influence over operating and
financial policies (generally 20% - 50% ownership), are accounted for under
the equity method of accounting. Other investments are stated principally at
cost. These equity and cost investments, which total approximately $108.9
million and $147.4 million at December 31, 2002 and 2001, respectively, are
included as miscellaneous other property and investments in the Consolidated
Balance Sheets. The primary component of this balance is the Company's
investments in affordable housing of $72.3 million and $82.4 million at
December 31, 2002 and 2001, respectively. Included in the December 31, 2001
investment balance is the Company's investment in Interpath Communications,
Inc. of $27.0 million.
79
Results of operations of Progress Rail Services Corporation and certain
other diversified operations are recognized one month in arrears.
Certain amounts for 2001 and 2000 have been reclassified to conform to the
2002 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and amounts
of revenues and expenses reflected during the reporting period. Actual
results could differ from those estimates.
D. Cash
The Company considers cash and cash equivalents to include unrestricted cash
on hand, cash in banks and temporary investments with a maturity of three
months or less.
E. Inventory
The Company accounts for inventory using the average-cost method. As of
December 31, inventory was comprised of (in thousands):
2002 2001
---------- ----------
Fuel $ 313,003 $ 296,772
Rail equipment and parts 155,206 200,697
Materials and supplies 362,708 349,127
Other 44,568 25,047
---------- ----------
Total inventory $ 875,485 $ 871,643
========== ==========
F. Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. The Company capitalizes all construction-related direct labor
and material costs of units of property as well as indirect construction
costs. The cost of renewals and betterments is also capitalized. Maintenance
and repairs of property, and replacements and renewals of items determined
to be less than units of property, are charged to maintenance expense as
incurred. The cost of units of property replaced, renewed or retired, plus
removal or disposal costs, less salvage, is charged to accumulated
depreciation. Subsequent to the acquisition of FPC, the utility plants of
FPC continue to be presented on a gross basis to reflect the treatment of
such plant in cost-based regulation.
The balances of electric utility plant in service at December 31 are listed
below (in thousands), with a range of depreciable lives for each:
2002 2001
------------- -------------
Production plant (7-33 years) $ 11,062,405 $ 10,670,717
Transmission plant (30-75 years) 2,104,520 2,013,243
Distribution plant (12-50 years) 6,072,901 5,767,788
General plant and other (8-75 years) 912,961 724,273
------------- -------------
Utility plant in service $ 20,152,787 $ 19,176,021
============= =============
Generally, electric utility plant other than nuclear fuel is pledged as
collateral for the first mortgage bonds of CP&L and Florida Power (See Note
8).
80
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The total
equity funds portion of AFUDC was $8.7 million, $8.8 million and $13.6
million in 2002, 2001 and 2000, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2% in both 2002 and 2001 and 8.2% in
2000. The composite AFUDC rate for Florida Power's electric utility plant
was 7.8% in 2002, 2001 and 2000.
G. Depreciation and Amortization - Utility Plant
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated net salvage. Depreciation provisions, including decommissioning
costs (See Note 1H) and excluding accelerated cost recovery of nuclear
generating assets, as a percent of average depreciable property other than
nuclear fuel, were approximately 3.6%, 4.0% and 4.1% in 2002, 2001 and 2000,
respectively. Total depreciation provisions were $730.3 million, $804.1
million and $707.5 million in 2002, 2001 and 2000, respectively.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000.
Cumulative accelerated depreciation ranging from $530 million to $750
million will be recorded by December 31, 2009. The accelerated cost recovery
of these assets resulted in additional depreciation expense of approximately
$53 million, $75 million and $275 million in 2002, 2001 and 2000,
respectively. Total accelerated depreciation recorded through December 31,
2002 was $326 million for the North Carolina jurisdiction and $77 million
for the South Carolina jurisdiction (See Note 15C).
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE) and costs associated with
obligations to the DOE for the decommissioning and decontamination of
enrichment facilities, is computed primarily on the units-of-production
method and charged to fuel used in electric generation in the accompanying
Consolidated Statements of Income. The total of these costs for the years
ended December 31, 2002, 2001 and 2000 were $141.1 million, $130.1 million
and $114.6 million, respectively.
Effective January 1, 2002 the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets," and no longer amortizes goodwill (See Note 6).
Prior to the adoption of SFAS No. 142, the Company amortized goodwill on a
straight-line basis over a period not exceeding 40 years. Intangible assets
are being amortized on a straight-line basis over their respective lives.
H. 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 $30.9 million, $38.5 million and $32.5
million in 2002, 2001 and 2000, respectively. The Florida Power rate case
settlement required Florida Power to suspend accruals on its reserves for
nuclear decommissioning and fossil dismantlement through December 31, 2005
(See Note 15B).
Accumulated decommissioning costs, which are included in accumulated
depreciation, were approximately $1.0 billion at December 31, 2002 and 2001.
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 unrealized gains and losses related
to changes in the fair value of trust assets.
81
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 years 2010 for Robinson Unit No. 2, 2016 for Brunswick
Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. An
application to extend the Robinson license 20 years was submitted in 2002,
and a similar application will be made for the Brunswick units in 2004. An
extension will also be sought for the Harris Plant, tentatively scheduled
for 2009.
Florida Power's most recent site-specific estimate of decommissioning costs
for the Crystal River Nuclear Plant (CR3) was developed in 2000 based on
prompt dismantlement decommissioning. The estimate, in 2000 dollars, is
$490.9 million and is subject to change based on the same factors as
discussed above for CP&L's estimates. The cost estimate excludes the portion
attributable to other co-owners of CR3. CR3's operating license expires in
2016. An application to extend the plant license for 20 years is anticipated
to be submitted in 2007.
Management believes that decommissioning costs that have been and will be
recovered through rates by CP&L and Florida Power will be sufficient to
provide for the costs of decommissioning.
Florida Power maintains a reserve for fossil plant dismantlement. At
December 31, 2002 and 2001, this reserve was approximately $141.6 million
and $140.5 million, respectively, and was included in accumulated
depreciation. The provision for fossil plant dismantlement was previously
suspended per a 1997 FPSC settlement agreement, but resumed mid-2001. The
2001 annual provision, approved by the FPSC, was $8.8 million. The accrual
for fossil dismantlement reserves was suspended again in 2002 by the Florida
rate case settlement (See Note 15B).
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," that will change the
accounting for the decommissioning and dismantlement provisions beginning in
2003 (See Note 1U).
I. Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If an impairment is recognized on an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis using the
estimated useful lives indicated in the table below. Depletion of mineral
rights is provided on the units-of-production method based upon the
estimates of recoverable amounts of clean mineral.
The Company uses the full cost method to account for its natural gas and oil
properties. Under the full cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition, exploration
and development of natural gas and oil reserves are capitalized. These
capitalized costs include the costs of all unproved properties, internal
costs directly related to acquisition and exploration activities. These
costs are amortized using the units-of-production method over the life of
the Company's proved reserves. Total capitalized costs are limited to a
ceiling based on the present value of discounted (at 10%) future net
revenues using current prices, plus the lower of cost or fair market value
of unproved properties. If the ceiling (discounted revenues) is not equal to
or greater than total capitalized costs, the Company is required to
write-down capitalized costs to this level. The Company performs this
ceiling test calculation every quarter. No write-downs were required in
2002, 2001 or 2000.
The Company's nonregulated businesses capitalize interest costs under SFAS
No. 34, "Capitalizing Interest Costs." During the year ended December 31,
2002, the Company capitalized $38.2 million of its interest expense of
$679.8 million related to the expansion of its nonregulated generation
portfolio at PVI. Capitalized interest is included in diversified business
property, net on the Consolidated Balance Sheets.
82
Diversified business depreciation expense was $86.2 million, $72.3 million
and $18.5 million at December 31, 2002, 2001 and 2000, respectively.
The following is a summary of diversified business property (in thousands)
as of December 31, with ranges of depreciable lives:
2002 2001
------------ ------------
Equipment (3 - 25 years) $ 298,747 $ 228,673
Nonregulated generation plant and equipment (3 - 40 years) 549,115 108,512
Land and mineral rights 89,506 76,598
Buildings and plants (5 - 40 years) 153,186 125,032
Oil and gas properties (units-of-production) 264,767 41,413
Telecommunications equipment (5 - 20 years) 42,514 266,603
Rail equipment (3 - 20 years) 48,279 54,105
Marine equipment (3 - 35 years) 80,501 78,868
Computers, office equipment and software (3 - 10 years) 33,575 42,855
Construction work in progress 643,742 342,179
Accumulated depreciation (319,661) (292,715)
------------ ------------
Diversified business property, net $ 1,884,271 $ 1,072,123
============ ============
During 2002, the Company recorded asset impairments related to assets held
by the Company's telecommunications operations (See Note 7).
J. Impairment of Long-Lived Assets and Investments
The Company reviews the recoverability of long-lived and intangible assets
whenever indicators exist. Examples of these indicators include current
period losses, combined with a history of losses or a projection of
continuing losses, or a significant decrease in the market price of a
long-lived asset group. If an indicator exists for assets to be held and
used, then the asset group is tested for recoverability by comparing the
carrying value to the sum of undiscounted expected future cash flows
directly attributable to the asset group. If the asset group is not
recoverable through undiscounted cash flows or the asset group is to be
disposed of, then an impairment loss is recognized for the difference
between the carrying value and the fair value of the asset group. The
accounting for impairment of assets is based on SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," which was adopted by
the Company effective January 1, 2002. Prior to the adoption of this
standard, impairments were accounted for under SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," which was superceded by SFAS No. 144. See Note 7 for a discussion of
impairment evaluations performed and charges taken.
K. Cost-Based Regulation
The Company's regulated operations are subject to SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation." SFAS No. 71 allows a
regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, the Company records assets and liabilities that result from the
regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the accompanying
Consolidated Balance Sheets as regulatory assets and regulatory liabilities
(See Note 15A).
L. Income Taxes
The Company and its affiliates file a consolidated federal income tax
return. Deferred income taxes have been provided for temporary differences.
These occur when there are differences between the book and tax carrying
amounts of assets and liabilities. Investment tax credits related to
regulated operations have been deferred and are being amortized over the
estimated service life of the related properties. Credits for the production
and sale of synthetic fuel are deferred to the extent they cannot be or have
not been utilized in the annual consolidated federal income tax returns (See
Note 20).
83
M. Excise Taxes
CP&L and Florida Power collect from customers certain excise taxes levied by
the state or local government upon the customers. CP&L and Florida Power
account for excise taxes on a gross basis. For the years ended December 31,
2002, 2001 and 2000, gross receipts tax, franchise taxes and other excise
taxes of approximately $211.0 million, $209.8 million and $84.0 million,
respectively, are included in taxes other than on income in the accompanying
Consolidated Statements of Income. These approximate amounts are also
included in utility revenues.
N. Derivatives
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138.
SFAS No. 133, as amended, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS No. 133 requires that an
entity recognize all derivatives as assets or liabilities in the balance
sheet and measure those instruments at fair value. See Note 16 for
information regarding risk management activities and derivative
transactions.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivatives
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices. In particular, that guidance discusses
whether the pricing in a contract that contains broad market indices (e.g.,
CPI) could qualify as a normal purchase or sale (the normal purchase or sale
term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
The Company is currently re-evaluating which contracts, if any, that have
previously been designated as normal purchases or sales would now not
qualify for this exception. The Company is currently evaluating the effects
that this guidance will have on its results of operations and financial
position.
O. Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts receivable, which
totaled approximately $39.6 million and $38.7 million at December 31, 2002
and 2001, respectively.
P. Unamortized Debt Premiums, Discounts and Expenses
Long-term debt premiums, discounts and issuance expenses for the utilities
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utilities are amortized over the applicable life
using the straight-line method consistent with ratemaking treatment.
Q. Revenue Recognition
The Company recognizes electric utility revenues as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Diversified business revenues are generally recognized at
the time products are shipped or as services are rendered. Leasing
activities are accounted for in accordance with SFAS No. 13, "Accounting for
Leases." Gains and losses from energy trading activities are reported on a
net basis. Revenues related to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
R. Fuel Cost Deferrals
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by the electric utilities' regulators. These
clauses allow the utilities to recover fuel costs and portions of purchased
power costs through surcharges on customer rates.
84
S. Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
expenditures are expensed as incurred or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as additional
information develops or circumstances change. Costs of future expenditures
for environmental remediation obligations are not discounted to their
present value. Recoveries of environmental remediation costs from other
parties are recognized when their receipt is deemed probable (See Note 24E).
T. Benefit Plans
The Company follows the guidance in SFAS No. 87, "Employers' Accounting for
Pensions," to account for its defined benefit retirement plans. In addition
to pension benefits, the Company provides other postretirement benefits
which are accounted for under SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." See Note 18 for related
disclosures for these plans.
U. New Accounting Standards
SFAS No. 143, "Accounting for Asset Retirement Obligations"
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in July 2001. This statement provides accounting and disclosure requirements
for retirement obligations associated with long-lived assets and is
effective January 1, 2003. This statement requires that the present value of
retirement costs for which the Company has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation will be recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of this
statement. The cumulative effect of initially applying this statement is
recognized as a change in accounting principle. The adoption of this
statement will have no impact on the income of regulated entities, as the
effects are expected to be offset by the establishment of regulatory assets
or liabilities pursuant to SFAS No. 71.
The Company's review identified legal retirement obligations for nuclear
decommissioning of radiated plant, coal mine operations, synthetic fuel
operations and gas production. The Company will record liabilities pursuant
to SFAS No. 143 beginning in 2003. The Company used an expected cash flow
approach to measure the obligations. The following proforma liabilities, as
of December 31, reflect amounts as if this statement had been applied during
all periods:
(in millions) 2002 2001
---------- -----------
Regulated:
Nuclear decommissioning $ 1,182.5 $ 1,117.7
Nonregulated:
Coal mine operations $ 6.1 $ 5.6
Synfuel operations 2.0 1.7
Gas production 2.2 2.0
Nuclear decommissioning and coal mine operations have previously-recorded
liabilities. Amounts recorded for nuclear decommissioning of radiated plant
were $775.1 million and $737.1 million at December 31, 2002 and 2001,
respectively. Amounts recorded for coal mine reclamation were $4.7 million
and $4.8 million at December 31, 2002 and 2001, respectively. Synthetic fuel
operations and gas production have no previously-recorded liabilities.
Proforma net income and earnings per share have not been presented for the
years ended December 31, 2002, 2001 or 2000 because the proforma application
of SFAS No. 143 to prior periods would result in proforma net income and
earnings per share not materially different from the actual amounts reported
for those periods in the accompanying Consolidated Statements of Income.
85
The Company has identified but not recognized asset retirement obligation
(ARO) liabilities related to electric transmission and distribution, gas
distribution and telecommunications assets as the result of easements over
property not owned by the Company. These easements are generally perpetual
and only require retirement action upon abandonment or cessation of use of
the property for the specified purpose. The ARO liability is not estimable
for such easements as the Company intends to utilize these properties
indefinitely. In the event the Company decides to abandon or cease the use
of a particular easement, an ARO liability would be recorded at that time.
The utilities have previously recognized removal costs as a component of
depreciation in accordance with regulatory treatment. To the extent these
amounts do not represent SFAS No. 143 legal retirement obligations, they
will be disclosed as regulatory liabilities upon adoption of the standard.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections"
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." This newly issued statement rescinds SFAS No. 4, "Reporting
Gains and Losses from Extinguishment of Debt (an amendment of APB Opinion
No. 30)," which required all gains and losses from the extinguishment of
debt to be aggregated and, if material, classified as an extraordinary item,
net of related income tax effect. As a result, the criteria set forth by APB
Opinion 30 will now be used to classify those gains and losses. Any gain or
loss on extinguishment will be recorded in the most appropriate line item to
which it relates within net income before extraordinary items. For regulated
companies, any expenses or call premiums associated with the reacquisition
of debt obligations are amortized over the applicable life using the
straight-line method consistent with ratemaking treatment (See Note 1P).
SFAS No. 145 also amends SFAS No. 13 to require that certain lease
modifications that have economic effects similar to sale-leaseback
transactions be accounted for in the same manner as sale-leaseback
transactions. In addition, SFAS No. 145 amends other existing authoritative
pronouncements to make various technical corrections, clarify meanings or
describe their applicability under changed conditions. For the provisions
related to the rescission of SFAS No. 4, SFAS No. 145 is effective for the
Company beginning in fiscal year 2004. The remaining provisions of SFAS No.
145 are effective for the Company in fiscal year 2003. The Company is
currently evaluating the effects, if any, that this statement will have on
its results of operations and financial position.
SFAS No. 148, "Accounting for Stock-Based Compensation"
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure -- an Amendment of FASB Statement
No. 123," and provided alternative methods of transition for a voluntary
change to the fair value-based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements
of SFAS No. 123, "Accounting for Stock-Based Compensation," to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. This statement requires that
companies follow the prescribed format and provide the additional
disclosures in their annual reports for years ending after December 15,
2002. The Company applies the recognition and measurement principles of APB
Opinion No. 25, "Accounting for Stock Issued to Employees," as allowed by
SFAS Nos. 123 and 148, and related interpretations in accounting for its
stock-based compensation plans, as described in Note 17.
86
For purposes of the proforma disclosures required by SFAS No. 148, the
estimated fair value of the options is amortized to expense over the
options' vesting period. Under SFAS No. 123, compensation expense would have
been $13.5 million and $2.9 million in 2002 and 2001, respectively. The
stock option plan was not in effect in 2000. The Company's information
related to the proforma impact on earnings and earnings per share follows:
(in thousands except per share data) 2002 2001 2000
---------- ---------- ----------
Net income, as reported $ 528,386 $ 541,610 $ 478,361
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 8,036 1,765 -
---------- ---------- ----------
Proforma net income $ 520,350 $ 539,845 $ 478,361
========== ========== ==========
Earnings per share:
Basic - as reported $2.43 $2.65 $3.04
Basic - proforma $2.40 $2.64 $3.04
Diluted - as reported $2.42 $2.64 $3.03
Diluted - proforma $2.39 $2.63 $3.03
FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an Interpretation of FASB Statements
No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No.
45). This interpretation clarifies the disclosures to be made by a guarantor
in its interim and annual financial statements about obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of certain guarantees, a liability
for the fair value of the obligation undertaken in issuing the guarantee.
The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements are effective
for financial statements of interim or annual periods ending after December
15, 2002. The applicable disclosures required by FIN No. 45 have been made
in Notes 9 and 24C. The Company is currently evaluating the effects, if any,
that this interpretation will have on its results of operations and
financial position.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities (previously known as special purpose entities or SPEs) and
determining whether such entities should be consolidated. Certain
disclosures are required when FIN No. 46 becomes effective if it is
reasonably possible that a company will consolidate or disclose information
about a variable interest entity when it initially applies FIN No. 46. This
interpretation must be applied immediately to variable interest entities
created or obtained after January 31, 2003. For those variable interest
entities created or obtained on or before January 31, 2003, the Company must
apply the provisions of FIN No. 46 in the third quarter of 2003.
The Company has an arrangement with Railcar Asset Financing Trust (RAFT),
through its Railcar Ltd. subsidiary, to which this interpretation may apply.
Because the Company expects to sell Railcar Ltd. during 2003 (See Note 3B),
the application of FIN No. 46 is not expected to have a material impact with
respect to this arrangement. The Company is currently evaluating what
effects, if any, this interpretation will have on its results of operations
and financial position.
EITF Issue 02-03, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities."
In June 2002, the EITF reached a consensus on a portion of Issue 02-03,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF Issue 02-03 requires all gains and losses (realized or
unrealized) on energy trading contracts to be shown net in the income
statement. The Company's policy already required the gains and losses to be
recorded on a net basis. The net of the gains and losses is recorded in
diversified business revenue and other, net on the Consolidated Statements
of Income. The Company does not recognize a dealer profit or unrealized gain
or loss at the inception of a derivative unless the fair value of that
instrument, in its entirety, is evidenced by quoted market prices or current
market transactions.
87
2. Acquisitions
A. Generation Acquisition
On February 15, 2002, PVI acquired 100% of two electric generating projects
located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. The
two projects consist of 1) Walton County Power, LLC in Monroe, Georgia, a
460 megawatt natural gas-fired plant placed in service in June 2001 and 2)
Washington County Power, LLC in Washington County, Georgia, a planned 600
megawatt natural gas-fired plant expected to be operational by June 2003.
The Walton and Washington projects have been accounted for using the
purchase method of accounting and accordingly have been included in the
consolidated financial statements since the acquisition date.
In the final allocation, the aggregate cash purchase price of approximately
$347.9 million was allocated to diversified business property, intangibles
and goodwill for $250.4 million, $33.4 million and $64.1 million,
respectively. Of the acquired intangible assets, $33.0 million was assigned
to tolling and power sale agreements with LG&E Energy Marketing, Inc. for
each project and is being amortized through December 31, 2004. Goodwill was
assigned to the Progress Ventures segment and will be deductible for tax
purposes (See Note 6).
In addition, PVI entered into a project management and completion agreement
whereby LG&E Energy Corp. agreed to manage the completion of the Washington
site construction for PVI. As of December 31, 2002, the remaining payments
related to the agreement are estimated to be $57.8 million. The Company has
guaranteed certain payments on behalf of PVI related to the construction of
the facility (See Note 24C).
The proforma results of operations reflecting the acquisition would not be
materially different than the reported results of operations for the years
ended December 31, 2002 or 2001.
B. Westchester Acquisition
On April 26, 2002, Progress Fuels Corporation (Progress Fuels), a subsidiary
of Progress Energy, acquired 100% of Westchester Gas Company (Westchester).
The acquisition included approximately 215 natural gas-producing wells, 52
miles of intrastate gas pipeline and 170 miles of gas-gathering systems
located within a 25-mile radius of Jonesville, Texas, on the Texas-Louisiana
border.
The aggregate purchase price of approximately $153 million consisted of cash
consideration of approximately $22 million and the issuance of 2.5 million
shares of Progress Energy common stock valued at approximately $129 million.
The purchase price included approximately $2 million of direct transaction
costs. The purchase price has been preliminarily allocated to fixed assets
including oil and gas properties, based on the preliminary fair values of
the assets acquired. The preliminary purchase price allocation is subject to
adjustment for changes in the preliminary assumptions pending additional
information, including final asset valuations.
The acquisition has been accounted for using the purchase method of
accounting and, accordingly, the results of operations for Westchester have
been included in Progress Energy's consolidated financial statements since
the date of acquisition. The proforma results of operations reflecting the
acquisition would not be materially different than the reported results of
operations for the years ended December 31, 2002 or 2001.
C. Florida Progress Corporation Acquisition
On November 30, 2000, the Company completed its acquisition of FPC, a
diversified, exempt electric utility holding company, for an aggregate
purchase price of approximately $5.4 billion. The Company paid cash
consideration of approximately $3.5 billion and issued 46.5 million common
shares valued at approximately $1.9 billion. In addition, the Company issued
98.6 million contingent value obligations (CVOs) valued at approximately
$49.3 million (See Note 10). The purchase price included $20.1 million in
direct transaction costs.
88
The acquisition was accounted for using the purchase method of accounting
and, accordingly, the results of operations for FPC have been included in
the Company's consolidated financial statements since the date of
acquisition. The excess of the purchase price over the fair value of the net
identifiable assets and liabilities acquired was recorded as goodwill. The
goodwill, of approximately $3.6 billion, was being amortized on a
straight-line basis over a period of 40 years. Effective January 1, 2002,
goodwill is no longer subject to amortization (See Note 6).
The U.S. Securities and Exchange Commission (SEC) order approving the merger
requires the Company to divest of Rail Services and certain immaterial,
nonregulated investments of FPC by November 30, 2003. The Company is
evaluating opportunities and actively marketing these investments but may
not find the right divestiture opportunity by that date. Therefore, the
Company plans to seek an extension from the SEC.
3. Divestitures
A. NCNG Divestiture
On October 16, 2002, the Company announced the Board of Directors' approval
to sell NCNG and the Company's equity investment in Eastern North Carolina
Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc., for
approximately $400 million in net proceeds. The sale is expected to close by
summer of 2003 and must be approved by the NCUC and federal regulatory
agencies.
The accompanying consolidated financial statements have been restated for
all periods presented for the discontinued operations of NCNG. The net
income of these operations is reported as discontinued operations in the
Consolidated Statements of Income. Interest expense of $15.6 million, $14.5
million and $13.6 million for the years ended December 31, 2002, 2001 and
2000, respectively, has been allocated to discontinued operations based on
the net assets of NCNG, assuming a uniform debt-to-equity ratio across the
Company's operations. The Company ceased recording depreciation effective
October 1, 2002, upon classification of the assets as discontinued
operations. The asset group, including goodwill, has been recorded at fair
value less cost to sell, resulting in an estimated loss on disposal of
approximately $29.4 million, which has been recorded until the disposition
is complete and the actual loss can be determined. Results of discontinued
operations for years ended December 31, were as follows:
(in thousands) 2002 2001 2000
---------- ---------- -----------
Revenues $ 299,820 $ 321,422 $ 330,365
========== ========== ===========
Earnings before income taxes $ 8,944 $ 3,909 $ 6,711
Income tax expense 3,350 2,695 6,272
---------- ---------- -----------
Net earnings from discontinued operations 5,594 1,214 439
Estimated loss on disposal of discontinued operations,
including applicable income tax expense of $3,214 (29,377) - -
---------- ----------- -----------
Earnings (loss) from discontinued operations $ (23,783) $ 1,214 $ 439
========== =========== ===========
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets, as of December
31, are as follows:
(in thousands) 2002 2001
---------- ----------
Utility plant, net $ 398,931 $ 393,149
Current assets 72,821 116,969
Deferred debits and other assets 18,677 42,340
---------- ----------
Assets of discontinued operations $ 490,429 $ 552,458
========== ==========
Current liabilities $ 76,372 $ 126,208
Deferred credits and other liabilities 48,395 36,709
---------- ----------
Liabilities of discontinued operations $ 124,767 $ 162,917
========== ==========
89
The Company's equity investment in ENCNG of $7.7 million as of December 31,
2002 is included in miscellaneous other property and investments in the
Consolidated Balance Sheets.
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the
Rail Services segment. A series of sales transactions is expected to take
place throughout 2003. In accordance with SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," an estimated impairment on
assets held for sale of $58.8 million has been recognized for the write-down
of the assets to be sold to fair value less the costs to sell. This
impairment has been included in impairment of long-lived assets in the
Consolidated Statements of Income (See Note 7).
The assets of Railcar Ltd. have been grouped as assets held for sale and are
included in other current assets on the Consolidated Balance Sheets as of
December 31, 2002. The assets are recorded at $23.6 million, which reflects
the Company's initial estimate of the fair value expected to be realized
from the sale of these assets. The primary component of assets held for sale
is current assets of $21.6 million. These assets are subject to certain
commitments under operating leases (See Note 12). The Company expects to be
relieved of the majority of these commitments as a result of the sale.
C. Inland Marine Transportation Divestiture
During 2001, the Company completed the sale of its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc., and related
investments to AEP Resources, Inc., a wholly owned subsidiary of American
Electric Power, for a sales price of $270 million. Of the $270 million
purchase price, $230 million was used to pay early termination of certain
off-balance sheet arrangements for assets leased by the business. In
connection with the sale, the Company entered into environmental
indemnification provisions covering both known and unknown sites (See Note
24E).
The Company adjusted the FPC purchase price allocation to reflect a $15.0
million negative net realizable value of the Inland Marine business. The
Company's results of operations exclude Inland Marine Transportation net
income of $9.1 million for 2001 and $1.8 million for the month of December
2000. These earnings were included in the determination of net realizable
value for the purchase price allocation.
D. BellSouth Carolinas PCS Partnership Interest Divestiture
In September 2000, Caronet, Inc. (Caronet), 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.
4. Financial Information by Business Segment
The Company currently provides services through the following business
segments: CP&L Electric, Florida Power Electric, Progress Ventures, Rail
Services and Other.
The CP&L Electric and Florida Power Electric segments are engaged in the
generation, transmission, distribution and sale of electric energy in
portions of North Carolina, South Carolina and Florida. These electric
operations are subject to the rules and regulations of FERC, the NCUC, the
SCPSC and the FPSC.
The Progress Ventures segment operations include nonregulated generation
operations; natural gas exploration and production; coal fuel extraction,
manufacturing and delivery; and energy marketing and limited trading
activities on behalf of the utility operating companies as well as for its
nonregulated plants. Management reviews the operations of the segment after
the allocation of energy marketing and trading activities, which Progress
Ventures performs on behalf of the regulated utilities, CP&L and Florida
Power.
The Rail Services segment operations include railcar repair, rail parts
reconditioning and sales, railcar leasing and sales, and scrap metal
recycling. These activities include maintenance and reconditioning of
salvageable scrap components of railcars, locomotive repair and right-of-way
maintenance. Included in this segment is an estimated impairment on assets
held for sale (See Note 3B).
90
The Other segment is made up of other nonregulated business areas including
telecommunications and holding company operations. The discontinued
operations related to the sale of NCNG are not included in the operating
segments below (See Note 3A).
(In thousands) Florida
Power Rail
CP&L Electric Progress Services Consolidated
Electric (c) Vendures (b) Other Totals
FOR THE YEAR ENDED DECEMBER 31, 2002
Revenues
Unaffiliated $3,538,957 $3,061,732 $748,317 $714,499 ($118,385) $7,945,120
Intersegment - - 326,639 4,623 (331,262) -
----------------------------------------------------------------------------
Total revenues 3,538,957 3,061,732 1,074,956 719,122 (449,647) 7,945,120
Depreciation and amortization 523,846 294,856 67,295 20,436 33,495 939,928
Net interest charges 211,536 106,783 12,132 32,767 270,223 633,441
Impairment of long-lived assets and
investments
(Notes 3B and 7) - - - 58,836 329,997 388,833
Income taxes (benefit) (e) 237,362 163,273 (359,862) (15,370) (183,211) (157,808)
Income (loss) from continuing operations 513,115 322,594 198,088 (41,733) (439,895) 552,169
Segment income (loss) from continuing
operations after allocation (a) 453,115 309,594 271,088 (41,733) (439,895) 552,169
Total segment assets (d) 8,659,297 5,226,243 2,354,081 614,640 4,008,014 20,862,275
Capital and investment expenditures 624,202 550,019 805,609 8,332 120,968 2,109,130
=======================================================================================================================
FOR THE YEAR ENDED DECEMBER 31, 2001
Revenues
Unaffiliated $3,343,720 $3,212,841 $526,200 $890,328 $112,291 $8,085,380
Intersegment - - 398,228 1,174 (399,402) -
----------------------------------------------------------------------------
Total revenues 3,343,720 3,212,841 924,428 891,502 (287,111) 8,085,380
Depreciation and amortization 521,910 452,971 40,695 36,053 109,615 1,161,244
Net interest charges 241,427 113,707 24,085 40,589 253,085 672,893
Impairment of long-lived assets and
investments
(Note 7) - - - - 207,035 207,035
Income taxes (benefit) 264,078 182,590 (421,559) (6,416) (173,031) (154,338)
Income (loss) from continuing operations 468,328 309,576 201,990 (12,108) (427,390) 540,396
Segment income (loss) from continuing
operations after allocation (a) 405,661 285,566 288,667 (12,108) (427,390) 540,396
Total segment assets 8,884,385 5,009,640 1,018,875 602,597 4,822,746 20,338,243
Capital and investment expenditures 823,952 353,433 265,183 12,886 71,986 1,527,440
=======================================================================================================================
FOR THE YEAR ENDED DECEMBER 31, 2000
Revenues
Unaffiliated $3,308,215 $ 241,606 $108,739 $ - $110,362 $3,768,922
Intersegment - - 15,717 - (15,717) -
----------------------------------------------------------------------------
Total revenues 3,308,215 241,606 124,456 - 94,645 3,768,922
Depreciation and amortization 698,633 28,872 17,020 - 15,657 760,182
Net interest charges 221,856 9,777 5,714 - 5,231 242,578
Gain on sale of investment - - - - 200,000 200,000
Income taxes (benefit) 227,705 13,580 (109,057) - 64,274 196,502
Income (loss) from continuing operations 373,764 21,764 39,816 - 42,578 477,922
Segment income (loss) from continuing
operations after allocation (a) 289,724 20,057 125,563 - 42,578 477,922
Total segment assets 8,840,736 4,997,728 644,234 - 4,515,053 18,997,751
Capital and investment expenditures 821,991 49,805 38,981 - 100,317 1,011,094
=======================================================================================================================
(a) Amounts include allocation of energy marketing and trading net income
managed by Progress Ventures on behalf of the electric utilities.
(b) Amounts for the year ended December 31, 2001 reflect cumulative operating
results of Rail Services since the acquisition date of November 30, 2000. As
of December 31, 2000, the Rail Services segment was included as Net Assets
Held for Sale and, therefore, no assets are reflected for this segment as of
that date. During 2001, the Company announced its intention to retain the
Rail Services segment and, therefore, these assets were reclassified to
operating assets.
(c) Amounts for the year ended December 31, 2000, reflect operating results of
Florida Power electric since the acquisition date of November 30, 2000 (See
Note 2C).
(d) In February 2002, CP&L transferred the Rowan Plant totaling approximately
$245 million to Progress Ventures.
(e) Amounts for 2002 include income tax benefit reallocation from holding
company to profitable subsidiaries according to an SEC order.
91
Segment totals for depreciation and amortization expense include expenses
related to the Progress Ventures, Rail Services and Other segments that are
included in diversified business expenses on the Consolidated Statements of
Income. Segment totals for interest expense exclude immaterial expenses
related to the Progress Ventures, Rail Services and Other segments that are
included in other, net on the Consolidated Statements of Income.
5. Related Party Transactions
NCNG sells natural gas to CP&L, Florida Power and PVI. During the years
ended December 31, 2002, 2001 and 2000, sales of natural gas to CP&L,
Florida Power and PVI amounted to $19.5 million, $18.7 million and $5.9
million, respectively. These revenues are included in discontinued
operations on the Consolidated Statements of Income. Progress Fuels sells
coal to Florida Power. These intercompany revenues are eliminated in
consolidation; however, in accordance with SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation," profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable and
the future recovery of the sales price through the ratemaking process is
probable.
The Company and its operating subsidiaries participate in a money pool
arrangement to better manage cash and working capital requirements. Under
this arrangement, subsidiaries with surplus short-term funds provide
short-term loans to participating affiliates.
The Company has announced plans to sell NCNG to Piedmont Natural Gas
Company, Inc. (See Note 3A). At December 31, 2002 and 2001, the Company and
its affiliates had amounts due from and payable to NCNG. Under the terms of
the sales agreement, these amounts will be settled at the time of the
transaction and therefore, the amounts are no longer being eliminated in
consolidation. The receivables due from and the payables due to the Company
are included in assets of discontinued operations and liabilities of
discontinued operations, respectively, on the Consolidated Balance Sheets.
At December 31, 2002 and 2001, NCNG had notes payable balances due to the
Company related to the money pool of $5.8 million and $51.7 million,
respectively. Interest payable balances as of December 31, 2002 and 2001 and
amounts recorded for interest income and interest expense related to the
money pool for 2002, 2001 and 2000 were not significant. The remaining
amounts of receivables and payables with the Company and its affiliates at
December 31, 2002 and 2001 represent amounts generated through NCNG's normal
course of operations. NCNG had payables to the Company of $5.0 million and
$31.9 million and receivables from the Company of $3.6 million and $51.9
million at December 31, 2002 and 2001, respectively.
In 2000, prior to the acquisition of FPC, the Company purchased a 90%
membership interest in two synthetic fuel related limited liability
companies from a wholly owned subsidiary of FPC. Interest expense incurred
during the pre-acquisition period was approximately $3.3 million. Subsequent
to the acquisition date, intercompany amounts have been eliminated in
consolidation (See Note 2C).
6. Goodwill and Other Intangible Assets
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets." This statement clarifies the criteria for
recording of other intangible assets separately from goodwill. Effective
January 1, 2002, goodwill is no longer subject to amortization over its
estimated useful life. Instead, goodwill is subject to at least an annual
assessment for impairment by applying a two-step fair value-based test. This
assessment could result in periodic impairment charges.
The Company completed the first step of the initial transitional goodwill
impairment test, which indicated that the Company's goodwill was not
impaired as of January 1, 2002. In addition, the Company performed the
annual goodwill impairment tests for the CP&L Electric and Florida Power
Electric segments during the second quarter 2002, which indicated that the
Company's goodwill was not impaired. The annual test for Progress Ventures'
goodwill will be performed during 2003.
92
In connection with the pending sale of NCNG, goodwill attributable to these
operations has been reclassified to assets of discontinued operations. The
Company reviewed the carrying value of the NCNG disposal group in accordance
with SFAS No. 144 (See Note 3A).
The changes in the carrying amount of goodwill for the year ended December
31, 2002, by reportable segment, are as follows:
Florida Power Progress
(In thousands) CP&L Electric Electric Ventures Other Total
Balance as of January 1, 2002 $ 1,921,802 $ 1,733,448 $ - $ 34,960 $ 3,690,210
Acquisitions - - 64,077 - 64,077
Divestitures - - - (1,720) (1,720)
Discontinued operations - - - (33,240) (33,240)
------------------------------------------------------------------------------
Balance as of December 31, 2002 $ 1,921,802 $ 1,733,448 $ 64,077 $ - $ 3,719,327
==============================================================================
The acquired goodwill relates to the acquisition of generating assets from
LG&E Energy Corp. in February 2002 (See Note 2A).
As required by SFAS No. 142, the results for the prior year periods have not
been restated. A reconciliation of net income as if SFAS No. 142 had been
adopted is presented below for years ending December 31. The goodwill
amortization used in the reconciliation includes $5.9 million for both years
ending December 31, 2001 and 2000 for NCNG, which is included in
discontinued operations.
(In thousands, except per share data) 2001 2000
----------- ----------
Reported net income $ 541,610 $ 478,361
Goodwill amortization 96,828 14,100
----------- ----------
Adjusted net income $ 638,438 $ 492,461
=========== ==========
Basic earnings per common share:
Reported net income $ 2.65 $ 3.04
Adjusted net income $ 3.12 $ 3.13
Diluted earnings per common share:
Reported net income $ 2.64 $ 3.03
Adjusted net income $ 3.11 $ 3.12
The gross carrying amount and accumulated amortization of the Company's
intangible assets as of December 31, 2002 and 2001 are as follows:
2002 2001
------------------------------------- ---------------------------------
(In thousands) Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
----------------------------------- ---------------------------------
Synthetic fuel intangibles $ 140,469 $ (45,189) $ 140,469 $ (22,237)
Power sale agreements 33,000 (5,593) - -
Other 40,968 (7,792) 36,071 (5,938)
----------------------------------- ---------------------------------
Total $ 214,437 $ (58,574) $ 176,540 $ (28,175)
=================================== =================================
All of the Company's intangibles are subject to amortization. Synthetic fuel
intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Code in
December 2007 (See Note 20). The power sale agreement intangibles were
recorded as part of the acquisition of generating assets from LG&E Energy
Corp. and are amortized on a straight-line basis beginning with the
in-service date of these plants through December 31, 2004 (See Note 2A).
Other intangibles are primarily customer contracts and permits that are
amortized over their respective lives.
Net intangible assets are included in other assets and deferred debits in
the accompanying Consolidated Balance Sheets. Amortization expense recorded
on intangible assets for the years ended December 31, 2002, 2001 and 2000
were $32.8 million, $21.6 million and $6.3 million, respectively. The
estimated amortization expense for intangible assets for 2003 through 2007,
in millions, is approximately $33.5, $36.5, $20.3, $19.8 and $19.8,
respectively.
93
7. Impairments of Long-Lived Assets and Investments
Effective January 1, 2002, the Company adopted SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." In 2002 and 2001, the Company recorded pre-tax long-lived asset and
investment impairments of approximately $388.8 million and $209.0 million,
respectively. There were no impairments recorded in 2000. Estimated
impairments of assets held for sale of $58.8 million is included in the 2002
amount, which relates to Railcar Ltd. (See Note 3B).
A. Long-Lived Assets
Due to the decline of the telecommunications industry and continued
operating losses, the Company initiated an independent valuation study
during 2002 to assess the recoverability of the long-lived assets of
Progress Telecommunications Corporation (Progress Telecom) and Caronet.
Based on this assessment, the Company recorded asset impairments of $305.0
million on a pre-tax basis and other charges of $25.4 million on a pre-tax
basis primarily related to inventory adjustments in the third quarter of
2002. This write-down constitutes a significant reduction in the book value
of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, using market approaches as supporting information.
Due to historical losses at Strategic Resource Solutions Corp. (SRS) and the
decline in the market value for technology companies, the Company evaluated
the long-lived assets of SRS in 2001. Fair value was determined based on
discounted cash flows. As a result of this review, the Company recorded
asset impairments of $42.9 million and other charges of $1.9 million on a
pre-tax basis during the fourth quarter of 2001.
B. Investments
The Company continually reviews its investments to determine whether a
decline in fair value below the cost basis is other-than-temporary.
Effective June 28, 2000, Caronet entered into an agreement with Bain Capital
whereby it contributed the net assets used in its application service
provider business to a newly formed company, named Interpath Communications,
Inc. (Interpath), for a 35% ownership interest (15% voting interest) in
Interpath. In 2001, the Company obtained a valuation study to assess its
investment in Interpath based on current valuations in the technology
sector. As a result, the Company recorded an impairment for
other-than-temporary declines in the fair value of its investment in
Interpath. Investment impairments were also recorded related to certain
investments of SRS. Investment write-downs totaled $164.2 million on a
pre-tax basis for the year ended December 31, 2001. In May 2002, Interpath
merged with a third party. Pursuant to the terms of the merger agreement and
due to additional funds being contributed by Bain Capital, the Company's
ownership was diluted to 19% (7% voting interest). As a result, the Company
reviewed the Interpath investment for impairment and wrote off the remaining
amount of its cost-basis investment in Interpath, recording a pre-tax
impairment of $25.0 million in the third quarter of 2002. In the fourth
quarter of 2002, the Company sold its remaining interest in Interpath for a
nominal amount.
94
8. Debt and Credit Facilities
A. Debt and Credit
At December 31, 2002 and 2001 the Company's long-term debt consisted of the
following (maturities and weighted-average interest rates as of December 31,
2002):
(in thousands) 2002 2001
--------------- ----------------
Progress Energy, Inc.:
Senior unsecured notes, maturing 2004-2031 6.93% $ 4,800,000 $4,000,000
Unamortized fair value hedge gain 33,676 -
Unamortized premium and discount, net (31,256) (29,708)
--------------- ----------------
4,802,420 3,970,292
--------------- ----------------
Carolina Power & Light Company:
First mortgage bonds, maturing 2004-2023 6.92% 1,550,000 1,800,000
Pollution control obligations, maturing 2010-2024 1.86% 707,800 707,800
Unsecured notes, maturing 2012 6.50% 500,000 -
Extendible notes, maturing 2002 - - 500,000
Medium-term notes, maturing 2008 6.65% 300,000 300,000
Miscellaneous notes 6.44% 6,910 7,234
Unamortized premium and discount, net (16,244) (16,716)
--------------- ----------------
3,048,466 3,298,318
--------------- ----------------
Florida Power Corporation:
First mortgage bonds, maturing 2003-2023 6.83% 810,000 810,000
Pollution control obligations, maturing 2018-2027 1.11% 240,865 240,865
Medium-term notes, maturing 2003-2028 6.74% 416,900 449,100
Unamortized premium and discount, net (6,433) (2,935)
--------------- ----------------
1,461,332 1,497,030
--------------- ----------------
Progress Ventures Holdings, Inc.:
Variable rate project financing, maturing 2007 3.02% 225,000 -
Florida Progress Funding Corporation (Note 9):
Mandatorily redeemable preferred securities, maturing 2039 7.10% 300,000 300,000
Purchase accounting fair value adjustment (30,276) (30,413)
Unamortized premium and discount, net (8,680) (8,922)
--------------- ----------------
261,044 260,665
--------------- ----------------
Progress Capital Holdings, Inc.:
Medium-term notes, maturing 2003-2008 6.96% 223,000 273,000
Miscellaneous notes 1.53% 1,428 7,707
--------------- ----------------
224,428 280,707
--------------- ----------------
Current portion of long-term debt (275,397) (688,052)
--------------- ----------------
Total long-term debt $ 9,747,293 $ 8,618,960
=============== ================
As of December 31, 2002 and 2001, the Company had $694.9 million and $942.3
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, 2002 and 2001 were
1.67% and 2.95%, respectively. The Company no longer reclassifies commercial
paper to long-term debt. Certain amounts for 2001 have been reclassified to
conform to 2002 presentation, with no effect on previously reported net
income or common stock equity.
At December 31, 2002, the Company had committed lines of credit totaling
$1.74 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 (in millions):
95
Company Description Total
----------------------------------------------------------------
Progress Energy 364-Day (expiring 11/11/03) $ 430.2
Progress Energy 3-Year (expiring 11/13/04) 450.0
CP&L 364-Day (expiring 7/30/03) 285.0
CP&L 3-Year (expiring 7/31/05) 285.0
Florida Power 364-Day (expiring 4/1/03) 90.5
Florida Power 5-Year (expiring 11/30/03) 200.0
----------
Total credit facilities $ 1,740.7
==========
As of December 31, 2002, there were no loans outstanding under these
facilities.
Progress Energy and Florida Power each have an uncommitted bank bid facility
authorizing them to borrow and re-borrow, and have loans outstanding at any
time, up to $300 million and $100 million, respectively. These bank bid
facilities were not drawn as of December 31, 2002.
The combined aggregate maturities of long-term debt for 2003 through 2007
are approximately $275 million, $869 million, $355 million, $909 million,
and $899 million, respectively.
B. Covenants and Default Provisions
Financial Covenants
Progress Energy's, CP&L's and Florida Power's credit lines and the bank
facility of Progress Genco Ventures, LLC (Genco), a PVI subsidiary, contain
various terms and conditions that could affect the Company's ability to
borrow under these facilities. These include maximum debt to total capital
ratios, interest coverage tests, material adverse change clauses and
cross-default provisions.
All of the credit facilities agreements include a defined maximum total debt
to total capital ratio. As of December 31, 2002, the calculated ratio for
these four companies, pursuant to the terms of the agreements, are as
follows:
Company Maximum Ratio Actual Ratio (b)
----------------------------------- ------------------- ------------------
Progress Energy, Inc. 70% (a) 62.4%
Carolina Power & Light Company 65% 52.7%
Florida Power Corporation 65% 48.6%
Progress Genco Ventures, LLC 40% 24.8%
(a) Progress Energy's maximum debt ratio reduces to 68% effective June 30,
2003.
(b) Indebtedness as defined by the bank agreements includes certain letters
of credit and guarantees which are not recorded on the Consolidated Balance
Sheets.
Progress Energy's 364-day credit facility has a financial covenant for
interest coverage. This covenant requires Progress Energy's EBITDA to
interest expense to be at least 2.5 to 1. For the year ended December 31,
2002, this ratio was 3.43 to 1. Genco's bank facility requires a minimum
1.25 to 1 debt service coverage ratio. For the year ended December 31, 2002,
Genco's debt service coverage was 7.65 to 1.
Material Adverse Change Clause
The credit facilities of Progress Energy, CP&L, Florida Power and Genco
include a provision under which lenders could refuse to advance funds in the
event of a material adverse change in the borrower's financial condition.
Cross-Default Provisions
Progress Energy's, CP&L's and Florida Power's credit lines include
cross-default provisions for defaults of indebtedness in excess of $10
million. Progress Energy's cross-default provisions only apply to defaults
of indebtedness by Progress Energy and its significant subsidiaries (i.e.,
CP&L, FPC, Florida Power, PVI, Progress Fuels and Progress Capital Holdings,
Inc.). CP&L's and Florida Power's cross-default provisions only apply to
defaults of indebtedness by CP&L and Florida Power and their subsidiaries,
respectively, not other affiliates of CP&L or Florida Power. The Genco
credit facility includes a similar provision for defaults by Progress Energy
or PVI.
96
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25
million; these provisions only apply to other obligations of Progress
Energy, not its subsidiaries. In the event that these indenture
cross-default provisions are triggered, the debt holders could accelerate
payment of approximately $4.8 billion in long-term debt. Certain agreements
underlying the Company's indebtedness also limit its ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
Other Restrictions
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's
subsidiaries as outlined below.
CP&L's mortgage indenture provides that so long as any first mortgage bonds
are outstanding, cash dividends and distributions on its common stock, and
purchases of its common stock, are restricted to aggregate net income
available for CP&L, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2002, none of
CP&L's retained earnings of $1.3 billion was restricted.
In addition, CP&L's Articles of Incorporation provide that cash dividends on
common stock shall be limited to 75% of net income available for dividends
if common stock equity falls below 25% of total capitalization, and to 50%
if common stock equity falls below 20%. On December 31, 2002, CP&L's common
stock equity was approximately 46.6% of total capitalization.
Florida Power's mortgage indenture provides that it will not pay any cash
dividends upon its common stock, or make any other distribution to the
stockholders, except a payment or distribution out of net income of Florida
Power subsequent to December 31, 1943. At December 31, 2002, none of Florida
Power's retained earnings of $598 million was restricted.
In addition, Florida Power's Articles of Incorporation provide that no cash
dividends or distributions on common stock shall be paid, if the aggregate
amount thereof since April 30, 1944, including the amount then proposed to
be expended, plus all other charges to retained earnings since April 30,
1944, exceed (a) all credits to retained earnings since April 30, 1944, plus
(b) all amounts credited to capital surplus after April 30, 1944, arising
from the donation to Florida Power of cash or securities or transfers
amounts from retained earnings to capital surplus.
Florida Power's Articles of Incorporation also provide that cash dividends
on common stock shall be limited to 75% of net income available for
dividends if common stock equity falls below 25% of total capitalization,
and to 50% if common stock equity falls below 20%. On December 31, 2002,
Florida Power's common stock equity was approximately 50.7% of total
capitalization.
Genco is required to hedge 75% of the amount outstanding under its bank
facility through September 2005 and 50% thereafter, pursuant to the term of
the agreement for expansion of its nonregulated generation portfolio. At
December 31, 2002, Genco held interest rate cash flow hedges with a notional
amount of $195 million and a total fair value of $12.3 million liability
position related to this covenant. See additional discussion of interest
rate cash flow hedges in Note 16.
C. Secured Obligations
CP&L's and Florida Power's first mortgage bonds are secured by their
respective mortgage indentures. Each mortgage constitutes a first lien on
substantially all of the fixed properties of the respective company, subject
to certain permitted encumbrances and exceptions. Each mortgage also
constitutes a lien on subsequently acquired property. At December 31, 2002,
CP&L and Florida Power had a total of approximately $3.3 billion of first
mortgage bonds outstanding, including those related to pollution control
obligations. Each mortgage allows the issuance of additional mortgage bonds
upon the satisfaction of certain conditions.
97
Genco obtained a bank facility to be used exclusively for expansion of its
nonregulated generation portfolio. Borrowings under this facility are
secured by the assets in the generation portfolio. The facility is for up to
$310 million, of which $225 million had been drawn as of December 31, 2002.
Borrowings under the facility are restricted for the operations,
construction, repayments and other related charges of the credit facility
for the development projects. Cash held and restricted to operations was
$21.1 million at December 31, 2002, and is included in other current assets.
Cash held and restricted for long-term purposes was $37.1 million at
December 31, 2002 and is included in other assets and deferred debits on the
Consolidated Balance Sheets.
D. Guarantees of Subsidiary Debt
FPC has guaranteed the outstanding debt obligations for two of its wholly
owned subsidiaries, FPC Capital I and Progress Capital Holdings, Inc.
At December 31, 2002 and 2001, Progress Capital Holdings, Inc. had $223
million and $273 million, respectively, in medium-term notes outstanding
which were fully guaranteed by FPC (See Note 8). FPC Capital I had $300
million in mandatorily redeemable securities outstanding at December 31,
2002 and 2001 for which FPC has also guaranteed payment. See Note 9 for
additional discussion of these notes. This debt is recorded on the Company's
accompanying Consolidated Balance Sheets.
E. Hedging Activities
Progress Energy uses interest rate derivatives to adjust the fixed and
variable rate components of its debt portfolio and to hedge cash flow risk
of fixed rate debt to be issued in the future. See discussion of risk
management activities and derivative transactions at Note 16.
9. FPC-Obligated Mandatorily Redeemable Preferred Securities of a Subsidiary
Holding Solely FPC Guaranteed Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly owned
subsidiary of FPC, issued 12 million shares of $25 par cumulative
FPC-obligated mandatorily redeemable preferred securities (Preferred
Securities) due 2039, with an aggregate liquidation value of $300 million
and an annual distribution rate of 7.10%. Currently, all 12 million shares
of the Preferred Securities that were issued are outstanding. Concurrent
with the issuance of the Preferred Securities, the Trust issued to Florida
Progress Funding Corporation (Funding Corp.) all of the common securities of
the Trust (371,135 shares) for $9.3 million. Funding Corp. is a direct
wholly owned subsidiary of FPC.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Funding Corp. its 7.10% Junior Subordinated Deferrable
Interest Notes (subordinated notes) due 2039, for a principal amount of
$309.3 million. The subordinated notes and the Notes Guarantee (as discussed
below) are the sole assets of the Trust. Funding Corp.'s proceeds from the
sale of the subordinated notes were advanced to Progress Capital and used
for general corporate purposes including the repayment of a portion of
certain outstanding short-term bank loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding
Corp. under the subordinated notes (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.
These Preferred Securities are classified as long-term debt on the Company's
Consolidated Balance Sheets.
98
10. Contingent Value Obligations
In connection with the acquisition of FPC during 2000, the Company issued
98.6 million CVOs. Each CVO represents the right to receive contingent
payments based on the performance of four synthetic fuel facilities
purchased by subsidiaries of FPC in October 1999. The payments, if any,
would be based on the net after-tax cash flows the facilities generate. The
CVO liability is adjusted to reflect market price fluctuations. The
liability, included in other liabilities and deferred credits, at December
31, 2002 and 2001, was $13.8 million and $41.9 million, respectively.
11. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock was issued by its subsidiaries and was
not subject to mandatory redemption. Preferred stock outstanding at December
31, 2002 and 2001 consisted of the following (in thousands, except share
data):
Carolina Power & Light Company:
Authorized - 300,000 shares, cumulative, $100 par value Preferred
Stock; 20,000,000 shares, cumulative, $100 par value Serial
Preferred Stock
$5.00 Preferred - 236,997 shares outstanding (redemption price $110.00) $24,349
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10,000
$5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00) 24,985
----------
$59,334
----------
Florida Power Corporation:
Authorized - 4,000,000 shares, cumulative, $100 par value Preferred
Stock; 5,000,000 shares, cumulative, no par value Preferred Stock;
1,000,000 shares, $100 par value Preference Stock
$100 par value Preferred Stock:
4.00% - 39,980 shares outstanding (redemption price $104.25) $ 3,998
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 $92,831
==========
12. Leases
The Company leases office buildings, computer equipment, vehicles, railcars
and other property and equipment with various terms and expiration dates.
Some rental payments for transportation equipment include minimum rentals
plus contingent rentals based on mileage. These contingent rentals are not
significant. Rent expense (under operating leases) totaled $57.1 million,
$62.6 million and $26.8 million for 2002, 2001 and 2000, respectively.
Assets recorded under capital leases at December 31 consist of (in
thousands):
2002 2001
--------- ---------
Buildings $ 27,626 $ 27,626
Equipment and other 2,919 12,170
Less: Accumulated amortization (9,422) (8,975)
--------- ---------
$ 21,123 $ 30,821
========= =========
Equipment and other capital lease assets were written down in conjunction
with the impairments of Progress Telecom and Caronet during the third
quarter of 2002 (See Note 7A).
99
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as of
December 31, 2002 are (in thousands):
Capital Leases Operating Leases
--------------- ----------------
2003 $ 3,300 $75,722
2004 3,300 58,750
2005 3,300 35,356
2006 3,300 24,695
2007 3,300 20,185
Thereafter 29,014 78,400
--------------- ----------------
$45,514 $293,108
================
Less amount representing imputed interest (17,042)
---------------
Present value of net minimum lease payments
under capital leases $ 28,472
===============
The Company expects to sell Railcar Ltd. during 2003 (See Note 3B). The
operating lease obligations above include $34.2 million, $24.0 million, $6.7
million, $1.5 million and $1.4 million for the years 2003 through 2007,
respectively, which are attributable to Railcar Ltd. Upon the sale of the
related assets, the Company expects to be relieved of these obligations.
The Company is also a lessor of land, buildings, railcars and other types of
properties it owns under operating leases with various terms and expiration
dates. The leased buildings and railcars are depreciated under the same
terms as other buildings and railcars included in diversified business
property. Minimum rentals receivable under noncancelable leases for 2003
through 2007 are approximately $11.3 million, $7.7 million, $6.0 million,
$4.8 million and $2.7 million, respectively, with $7.3 million receivable
thereafter. These rentals receivable totals include $10.3 million, $7.0
million, $5.6 million, $4.5 million and $2.6 million, for the years 2003
through 2007, respectively, and $4.4 million thereafter, which are
attributable to Railcar Ltd. Upon the sale of the related assets, the
Company expects to no longer receive this income.
CP&L and Florida Power are lessors of electric poles and streetlights. Rents
received are contingent upon usage and totaled $80.8 million, $78.4 million
and $27.5 million for 2002, 2001 and 2000, respectively.
13. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term obligations
approximate fair value due to the short maturities of these instruments. At
December 31, 2002 and 2001, investments in company-owned life insurance and
other benefit plan assets, with carrying amounts of approximately $149.9
million and $124.3 million, respectively, are included in miscellaneous
other property and investments and approximate fair value due to the short
maturity of the instruments. Other instruments are presented at fair value
in accordance with GAAP. The carrying amount of the Company's long-term
debt, including current maturities, was $10.1 billion and $9.4 billion at
December 31, 2002 and 2001, respectively. The estimated fair value of this
debt, as obtained from quoted market prices for the same or similar issues,
was $11.0 billion and $9.7 billion at December 31, 2002 and 2001,
respectively.
External funds have been established as a mechanism to fund certain costs of
nuclear decommissioning (See Note 1H). These nuclear decommissioning trust
funds are invested in stocks, bonds and cash equivalents. Nuclear
decommissioning trust funds are presented on the Consolidated Balance Sheets
at amounts that approximate fair value. Fair value is obtained from quoted
market prices for the same or similar investments.
14. Common Stock
In November 2002, the Company issued 14.67 million shares of common stock
for net cash proceeds of approximately $600.0 million, which were primarily
used to retire commercial paper. In April 2002, the Company issued 2.5
million shares of common stock, valued at approximately $129.0 million
dollars, in conjunction with the purchase of Westchester Gas Company (See
Note 2B). In August 2001, the Company issued 12.65 million shares of common
stock for net cash proceeds of $488.0 million, which were primarily used to
retire commercial paper. In November 2000, the Company issued 46.5 million
shares of common stock, valued at approximately $1.9 billion, in conjunction
with the FPC acquisition (See Note 2C).
100
As of December 31, 2002, the Company had 52,537,780 shares of common stock
authorized by the Board of Directors that remained unissued and reserved,
primarily to satisfy the requirements of the Company's stock plans. In July
2002, the Board of Directors authorized meeting the requirements of the
Progress Energy 401(k) Savings and Stock Ownership Plan and the Investor
Plus Stock Purchase Plan with original issue shares. Prior to that
authorization, the Company met the requirements of these stock plans with
issued and outstanding shares held by the Trustee of the Progress Energy
401(k) Savings and Stock Ownership Plan (previously known as the Progress
Energy, Inc. Stock Purchase-Savings Plan) or with open market purchases of
common stock shares, as appropriate. During 2002, the Company issued
approximately 2.1 million shares under these plans for net proceeds of
approximately $87.0 million. The Company continues to meet the requirements
of the restricted stock plan with issued and outstanding shares.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. As of December 31, 2002,
there were no significant restrictions on the use of retained earnings.
15. 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 GAAP for nonregulated entities. The utilities' ability to continue to
meet the criteria for application of SFAS No. 71 may be affected in the
future by competitive forces and restructuring in the electric utility
industry. In the event that SFAS No. 71 no longer applied to a separable
portion of the Company's operations, related regulatory assets and
liabilities would be eliminated unless an appropriate regulatory recovery
mechanism was provided. Additionally, these factors could result in an
impairment of utility plant assets as determined pursuant to SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets" (See Note
1J).
At December 31, 2002 and 2001, the balances of the utilities' regulatory
assets (liabilities) were as follows (in thousands):
2002 2001
----------- -----------
Deferred fuel costs (included in current assets) $ 183,518 $ 146,652
----------- -----------
Income taxes recoverable through future rates 230,025 236,312
Deferred purchased power contract termination costs 46,601 95,326
Harris Plant deferred costs 16,888 32,476
Loss on reacquired debt 32,979 25,649
Deferred DOE enrichment facilities-related costs (Note 1G) 31,525 39,102
Other postretirement benefits (Note 18C) 11,018 12,207
Other 24,179 22,765
----------- -----------
Total regulatory assets 393,215 463,837
----------- -----------
Nuclear maintenance and refueling (9,601) (346)
Defined benefit retirement plan (Note 18C) (50,988) (234,102)
Emission allowance gains (7,774) (7,494)
Storm reserve (Note 24D) (35,631) (35,527)
Other (15,772) (14,320)
----------- -----------
Total regulatory liabilities (119,766) (291,789)
----------- -----------
Net regulatory assets $ 456,967 $ 318,700
=========== ===========
101
NCNG is allowed to recover the costs of gas purchased for resale through
customer rates. NCNG was in an overrecovery position as of December 31, 2002
and 2001. The NCNG liability of $12.7 million as of December 31, 2002 and
$4.5 million as of December 31, 2001 is included in liabilities of
discontinued operations.
Except for portions of deferred fuel, all regulatory assets earn a return or
the cash has not yet been expended, in which case the assets are offset by
liabilities that do not incur a carrying cost.
B. Florida Power Rate Case Settlement
Florida Power's retail rates are set by the FPSC, while its wholesale rates
are governed by FERC. Florida Power's last general retail rate case was
approved in 1992 and allowed a 12% regulatory return on equity with an
allowed range between 11% and 13%. Florida Power previously operated under
an agreement committing several parties not to seek any reduction in its
base rates or authorized return on equity. That agreement expired on June
30, 2001. The FPSC initiated a rate proceeding in 2001 regarding Florida
Power's future base rates. On March 27, 2002, the parties in Florida Power's
rate case entered into a Stipulation and Settlement Agreement (the
Agreement) related to retail rate matters. The Agreement was approved by the
FPSC on April 23, 2002. The Agreement is generally effective from May 1,
2002 through December 31, 2005; provided, however, that if Florida Power's
base rate earnings fall below a 10% return on equity, Florida Power may
petition the FPSC to amend its base rates.
The Agreement provides that Florida Power will reduce its retail revenues
from the sale of electricity by an annual amount of $125 million. The
Agreement also provides that Florida Power will operate under a Revenue
Sharing Incentive Plan (the Plan) through 2005, and thereafter until
terminated by the FPSC, that establishes annual revenue caps and sharing
thresholds. The Plan provides that retail base rate revenues between the
sharing thresholds and the retail base rate revenue caps will be divided
into two shares - a 1/3 share to be received by Florida Power's
shareholders, and a 2/3 share to be refunded to Florida Power's retail
customers; provided, however, that for the year 2002 only, the refund to
customers will be limited to 67.1% of the 2/3 customer share. The retail
base rate revenue sharing threshold amounts for 2002 were $1.296 billion and
will increase $37 million each year thereafter. The Plan also provides that
all retail base rate revenues above the retail base rate revenue caps
established for each year will be refunded to retail customers on an annual
basis. For 2002, the refund to customers was limited to 67.1% of the retail
base rate revenues that exceed the 2002 cap. The retail base revenue cap for
2002 was $1.356 billion and will increase $37 million each year thereafter.
Any amounts above the retail base revenue caps will be refunded 100% to
customers. As of December 31, 2002, $4.7 million was accrued and will be
refunded to customers by March 2003.
The Agreement also provides that beginning with the in-service date of
Florida Power's Hines Unit 2 and continuing through December 31, 2005,
Florida Power will be allowed to recover through the fuel cost recovery
clause a return on average investment and depreciation expense for Hines
Unit 2, to the extent such costs do not exceed the unit's cumulative fuel
savings over the recovery period. Hines Unit 2 is a 516 MW combined-cycle
unit under construction and currently scheduled for completion in late 2003.
Additionally, the Agreement provided that Florida Power would effect a
mid-course correction of its fuel cost recovery clause to reduce the fuel
factor by $50 million for 2002. The fuel cost recovery clause will operate
as it normally does, including, but not limited to, any additional
mid-course adjustments that may become necessary, and the calculation of
true-ups to actual fuel clause expenses.
Florida Power will suspend accruals on its reserves for nuclear
decommissioning and fossil dismantlement through December 31, 2005.
Additionally, for each calendar year during the term of the Agreement,
Florida Power will reduce depreciation expense by $62.5 million, and may, at
its option, record up to an equal annual amount as an offsetting accelerated
depreciation expense. In addition, Florida Power is authorized, at its
discretion, to accelerate the amortization of certain regulatory assets over
the term of the Agreement. Florida Power recorded no accelerated
depreciation or amortization expense for the year ended December 31, 2002.
102
Under the terms of the Agreement, Florida Power agreed to continue the
implementation of its four-year Commitment to Excellence Reliability Plan
and expects to achieve a 20% improvement in its annual System Average
Interruption Duration Index by no later than 2004. If this improvement level
is not achieved for calendar years 2004 or 2005, Florida Power will provide
a refund of $3 million for each year the level is not achieved to 10% of its
total retail customers served by its worst performing distribution feeder
lines.
Per the Agreement, Florida Power was required to refund to customers $35
million of revenues Florida Power collected during the interim period since
March 13, 2001. This one-time retroactive revenue refund was recorded in the
first quarter of 2002 and was returned to retail customers over an
eight-month period ended December 31, 2002. Any additional refunds under the
Agreement are recorded when they become probable.
C. 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. On June 14, 2002, the NCUC approved modification of CP&L's ongoing
accelerated cost recovery of its nuclear generating assets. Effective
January 1, 2003, the NCUC will no longer require annual minimum accelerated
depreciation. The aggregate minimum and maximum amounts of accelerated
depreciation, $415 million and $585 million, respectively, are unchanged
from the original NCUC order. The date by which the minimum amount must be
depreciated was extended from December 31, 2004 to December 31, 2009. On
October 29, 2002, the SCPSC approved similar modifications. The order was
effective November 1, 2002, and the aggregate minimum and maximum of $115
million and $165 million established for accelerated cost recovery by the
SCPSC is unchanged. The accelerated cost recovery of these assets resulted
in additional depreciation expense of approximately $53 million, $75 million
and $275 million in 2002, 2001 and 2000, respectively. Recovering the costs
of its nuclear generating assets on an accelerated basis will better
position CP&L for the uncertainties associated with potential restructuring
of the electric utility industry. Total accelerated depreciation recorded
through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion
of its annual accelerated cost recovery of nuclear generating assets by the
amount of sulfur dioxide (SO2) emission allowance expense. CP&L offset
accelerated depreciation expense against emission allowance expense by
approximately $5.8 million in 2002. CP&L did not offset accelerated
depreciation expense against emission allowance expense in 2001. CP&L is
allowed to recover emission allowance expense through the fuel clause
adjustment in its South Carolina retail jurisdiction. Florida Power is also
allowed to recover its emission allowance expenses through the fuel
adjustment clause in its retail jurisdiction. See Note 24E regarding the
North Carolina rate freeze and accelerated recovery of environmental costs
beginning January 1, 2003.
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.
In conjunction with the acquisition of NCNG, CP&L agreed to cap base retail
electric rates in North Carolina and South Carolina through December 2004.
The cap on base retail electric rates in South Carolina was extended to
December 2005 in conjunction with regulatory approval to form a holding
company. NCNG also agreed to cap its North Carolina margin rates for gas
sales and transportation services, with limited exceptions, through November
1, 2003. In February 2002, NCNG filed a general rate case with the NCUC
requesting an annual rate increase of $47.6 million, based upon its
completion of major expansion projects. On May 3, 2002, NCNG withdrew the
application, based upon the NCUC Public Staff's and other parties'
interpretation of the order approving the merger of CP&L and NCNG that such
a case was not permitted until 2003. On May 16, 2002, NCNG filed a request
to increase its margin rates and rebalance its rates with the NCUC,
requesting an annual rate increase of $4.1 million to recover costs
associated with specific system improvements. On September 23, 2002, the
NCUC issued its order approving the $4.1 million rate increase. The rate
increase was effective October 1, 2002.
In conjunction with the FPC merger, CP&L reached a settlement with the
Public Staff of the NCUC in which it agreed to provide credits to its
non-real time pricing customers in the amounts of $3.0 million in 2002, $4.5
million in 2003, $6.0 million in 2004 and $6.0 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.
103
At December 31, 2000, Florida Power, with the approval of the FPSC, had
established a regulatory liability to defer $63 million of revenues. In
2001, Florida Power applied the deferred revenues, plus accrued interest, to
reduce its regulatory asset related to deferred purchased power termination
costs. In addition, Florida Power recorded accelerated amortization of $34.0
million to further offset this regulatory asset during 2001.
In February 2003, Florida Power petitioned the FPSC to increase its fuel
factors due to continuing increases in oil and natural gas commodity prices.
The crisis in the Middle East along with the Venezuelan oil workers' strike
have put upward pressure on commodity prices that was not anticipated by
Florida Power when fuel factors for 2003 were approved by the FPSC in
November 2002. If Florida Power's petition is approved, the increase would
go into effect April 1, 2003.
D. Regional Transmission Organizations
In early 2000 FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions
that RTOs must meet, including independent transmission service. As a result
of Order 2000, Florida Power, along with Florida Power & Light Company and
Tampa Electric Company, filed with FERC, in October 2000, an application for
approval of a GridFlorida RTO. On March 28, 2001, FERC issued an order
provisionally approving GridFlorida. CP&L, along with Duke Energy
Corporation and South Carolina Electric & Gas Company, filed with FERC, for
approval of a GridSouth RTO. On July 12, 2001, FERC issued an order
provisionally approving GridSouth. However, in July 2001, FERC issued orders
recommending that companies in the Southeast engage in a mediation to
develop a plan for a single RTO for the Southeast. Florida Power and CP&L
participated in the mediation. FERC has not issued an order specifically on
this mediation. On July 31, 2002, FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design (SMD
NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would
materially alter the manner in which transmission and generation services
are provided and paid for. Florida Power and CP&L, as subsidiaries of
Progress Energy, filed comments on November 15, 2002 and supplement comments
on January 10, 2003. On January 15, 2003 FERC announced the issuance of a
White Paper on SMD NOPR to be released in April 2003. Florida Power and
CP&L, as subsidiaries of Progress Energy, plan to file comments on the White
Paper. FERC has also indicated that it expects to issue final rules during
the summer 2003. The Company cannot predict the outcome of these matters or
the effect that they may have on the GridFlorida and GridSouth proceedings
currently ongoing before the FERC. The Company has $28.4 million and an
insignificant amount invested in GridSouth and GridFlorida, respectively, at
December 31, 2002. It is unknown what impact the future proceedings will
have on the Company's earnings, revenues or prices.
16. Risk Management Activities and Derivatives Transactions
Under its risk management policy, the Company may use a variety of
instruments, including swaps, options and forward contracts, to manage
exposure to fluctuations in commodity prices and interest rates. Such
instruments contain credit risk if the counterparty fails to perform under
the contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. Potential 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.
A. Commodity Contracts - General
Most of the Company's commodity contracts are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Cash Flow Hedges
The Company held natural gas and oil cash flow hedging instruments at
December 31, 2002. The objective for holding these instruments is to manage
a portion of the market risk associated with fluctuations in the price of
natural gas and oil on the Company's forecasted sales of natural gas and oil
production. As of December 31, 2002, the Company is hedging exposures to the
price variability of these commodities for contracts maturing through
December 2004.
The total fair value of these instruments at December 31, 2002 was a $10.2
million liability position. The ineffective portion of commodity cash flow
hedges was not material in 2002. As of December 31, 2002, $5.0 million of
after-tax deferred losses in accumulated other comprehensive income (OCI)
are expected to be reclassified to earnings during the next 12 months as the
hedged transactions occur. Due to the volatility of the commodities markets,
the value in OCI is subject to change prior to its reclassification into
earnings.
104
C. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity and natural gas contracts, are
entered into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations
in commodity prices, these instruments are not designated as hedges for
accounting purposes and are monitored consistent with trading positions. The
Company manages open positions with strict policies that limit its exposure
to market risk and require daily reporting to management of potential
financial exposures. Gains and losses from such contracts were not material
during 2002, 2001 or 2000, and the Company did not have material outstanding
positions in such contracts at December 31, 2002 or 2001.
D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company manages its interest rate exposure in part by maintaining its
variable-rate and fixed-rate exposures within defined limits. In addition,
the Company also enters into financial derivative instruments, including,
but not limited to, interest rate swaps and lock agreements to manage and
mitigate interest rate risk exposure.
The Company uses cash flow hedging strategies to hedge variable interest
rates on long-term debt and to hedge interest rates with regard to future
fixed-rate debt issuances. At December 31, 2002, the Company held an
interest rate cash flow hedge, with a notional amount of $35.0 million,
related to an anticipated 2003 issuance of fixed-rate debt and held interest
rate cash flow hedges, with a varying notional amount and maximum of $195.0
million, related to variable-rate debt. The total fair value of these hedges
at December 31, 2002 was a $12.8 million liability position. As of December
31, 2002, $7.8 million of after-tax deferred losses in OCI, including
amounts in OCI related to terminated hedges, are expected to be reclassified
to earnings during the next 12 months as the hedged interest payments occur.
Due to the volatility of interest rates, the value in OCI is subject to
change prior to its reclassification into earnings. At December 31, 2001,
the Company had open interest rate cash flow hedges with notional amounts
totaling $500.0 million and a total fair value of $18.5 million liability
position.
The Company uses fair value hedging strategies to manage its exposure to
fixed interest rates on long-term debt. At December 31, 2002, the Company
had open interest rate fair value hedges with notional amounts totaling
$350.0 million and a total fair value of $5.2 million asset position. In
addition, the Company initiated and terminated interest rate fair value
hedges on long-term debt in 2002, resulting in total deferred hedging gains
of approximately $35.2 million reflected in long-term debt, which are being
amortized over periods ending in 2006 and 2007 coinciding with the maturity
of the related debt instruments.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
17. Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the
provisions of APB Opinion No. 25 as allowed by SFAS Nos. 123 and 148.
A. Employee Stock Ownership Plan
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
Plan (401(k)) for which substantially all full-time non-bargaining unit
employees and certain part-time non-bargaining unit employees within
participating subsidiaries are eligible. Participating subsidiaries within
the Company as of January 1, 2002 were CP&L, NCNG, Florida Power, Progress
Telecom, Progress Fuels (Corporate) and Progress Energy Service Company. The
401(k), which has Company matching and incentive goal features, encourages
systematic savings by employees and provides a method of acquiring Company
common stock and other diverse investments. The 401(k), as amended in 1989,
is an Employee Stock Ownership Plan (ESOP) that can enter into acquisition
loans to acquire Company common stock to satisfy 401(k) common share needs.
Qualification as an ESOP did not change the level of benefits received by
employees under the 401(k). Common stock acquired with the proceeds of an
ESOP loan is held by the 401(k) Trustee in a suspense account. The common
105
stock is released from the suspense account and made available for
allocation to participants as the ESOP loan is repaid. Such allocations are
used to partially meet common stock needs related to Company matching and
incentive contributions and/or reinvested dividends. All or a portion of the
dividends paid on ESOP suspense shares and on ESOP shares allocated to
participants may be used to repay ESOP acquisition loans. To the extent used
to repay such loans, the dividends are deductible for income tax purposes.
Also, beginning in 2002, the dividends paid on ESOP shares which are either
paid directly to participants or used to purchase additional shares which
are then allocated to participants are fully deductible for income tax
purposes.
There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
and 2001, respectively, with a fair value of $200.1 million and $234.1
million, respectively. ESOP shares allocated to plan participants totaled
13,554,283 and 14,088,173 at December 31, 2002 and 2001, respectively. The
Company's matching and incentive goal compensation cost under the 401(k) is
determined based on matching percentages and incentive goal attainment as
defined in the plan. Such compensation cost is allocated to participants'
accounts in the form of Company common stock, with the number of shares
determined by dividing compensation cost by the common stock market value at
the time of allocation. The Company currently meets common stock share needs
with open market purchases, with shares released from the ESOP suspense
account and with newly issued shares. Matching and incentive cost met with
shares released from the suspense account totaled approximately $20.3
million, $18.2 million and $15.6 million for the years ended December 31,
2002, 2001 and 2000, respectively. The Company has a long-term note
receivable from the 401(k) Trustee related to the purchase of common stock
from the Company in 1989. The balance of the note receivable from the 401(k)
Trustee is included in the determination of unearned ESOP common stock,
which reduces common stock equity. ESOP shares that have not been committed
to be released to participants' accounts are not considered outstanding for
the determination of earnings per common share. Interest income on the note
receivable and dividends on unallocated ESOP shares are not recognized for
financial statement purposes.
B. Stock Option Agreements
Pursuant to the Company's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, amended and restated as of July 10, 2002, the Company may
grant options to purchase shares of common stock to directors, officers and
eligible employees. Generally, options granted to employees, vest one-third
per year with 100% vesting at the end of year three and options granted to
directors vest 100% at the end of one year. The options expire ten years
from the date of grant. All option grants have an exercise price equal to
the fair market value of the Company's common stock on the grant date.
Compensation expense is measured for stock options as the difference between
the market price of the Company's common stock and the exercise price of the
option at the grant date. Accordingly, no compensation expense has been
recognized for stock option grants.
The pro forma information presented in Note 1U regarding net income and
earnings per share is required by SFAS No. 123. Under this statement,
compensation cost is measured at the grant date based on the fair value of
the award and is recognized over the vesting period. The pro forma amounts
presented in Note 1U have been determined as if the Company had accounted
for its employee stock options under SFAS No. 123. The fair value for these
options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions:
2002 2001
----------------------
Risk-free interest rate (%) 4.14% 4.83%
Dividend yield (%) 5.20% 5.21%
Volatility factor (%) 24.98% 26.47%
Weighted-average expected life of the options (in years) 10 10
The option valuation model requires the input of highly subjective
assumptions, primarily stock price volatility, changes in which can
materially affect the fair value estimate.
The options outstanding as of December 31, 2002 and 2001 had a
weighted-average remaining contractual life of 9.32 and 9.75 years,
respectively, and had exercise prices that ranged from $41.97 to $51.85.
There were no options outstanding at December 31, 2000. At December 31,
2002, 92,400 outstanding shares were antidilutive for purposes of
calculating diluted earnings per share. All options outstanding at December
31, 2001 were antidilutive. As of December 31, 2002, no options have expired
or been exercised. The tabular information for the option activity is as
follows:
106
2002 2002 2001 2001
----------- ------------------ ----------- ---------------
Number of Weighted-Average Number of Weighted-
Options Exercise Price Options Average
Exercise Price
Options outstanding, January 1 2,328,855 $43.49 - -
Granted 2,893,650 $42.34 2,353,155 $43.49
Forfeited (65,310) $43.71 (24,300) $43.49
Options outstanding, December 31 5,157,195 $42.84 2,328,855 $43.49
Options exercisable at December 31,
with a remaining contractual life of
8.75 years 754,538 $43.49 - -
Weighted-average grant date fair value
of options granted during the year $6.83 $8.05
C. Other Stock-Based Compensation Plans
The Company has additional compensation plans for officers and key employees
of the Company that are stock-based in whole or in part. The two primary
programs are the Performance Share Sub-Plan (PSSP) and the Restricted Stock
Awards program (RSA), both of which were established pursuant to the
Company's 1997 Equity Incentive Plan and were continued under the Company's
2002 Equity Incentive Plan, as amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares that vest over a three-year consecutive period.
Each performance share has a value that is equal to, and changes with, the
value of a share of the Company's common stock, and dividend equivalents are
accrued on, and reinvested in, the performance shares. The PSSP has two
equally weighted performance measures, both of which are based on the
Company's results as compared to a peer group of utilities. Compensation
expense is recognized over the vesting period based on the expected ultimate
cash payout. Compensation expense is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to
officers and key employees of the Company. The restricted shares generally
vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period, with
corresponding increases in common stock equity. The weighted-average price
of restricted shares at the grant date was $44.27, $41.86 and $36.97 in
2002, 2001 and 2000, 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:
2002 2001 2000
---------- ----------- ------------
Beginning balance 674,511 653,344 331,900
Granted 365,920 113,651 359,844
Vested (75,200) (70,762) -
Forfeited (15,051) (21,722) (38,400)
---------- ----------- ------------
Ending balance 950,180 674,511 653,344
========== =========== ============
The total amount expensed for other stock-based compensation plans was $16.7
million, $14.3 million and $15.6 million in 2002, 2001 and 2000,
respectively.
107
18. Postretirement Benefit Plans
A. Pension Benefits
The Company and some of its subsidiaries have a non-contributory defined
benefit retirement (pension) plan for substantially all full-time employees.
The Company also has supplementary defined benefit pension plans that
provide benefits to higher-level employees.
The components of net periodic pension benefit for the years ended December
31 are (in thousands):
2002 2001 2000
--------------- --------------- ---------------
Expected return on plan assets $ (161,181) $ (169,329) $ (87,628)
Service cost 45,414 31,863 22,123
Interest cost 105,646 96,200 56,924
Amortization of transition obligation 106 125 125
Amortization of prior service (benefit) cost 306 (1,325) (1,314)
Amortization of actuarial (gain) loss 2,050 (4,989) (5,721)
--------------- --------------- ---------------
Net periodic pension benefit (7,659) (47,455) (15,491)
Additional benefit recognition (Note 18C) (7,614) (16,464) (3,401)
--------------- --------------- ---------------
Net periodic pension benefit recognized $ (15,273) $(63,919) $ (18,892)
=============== =============== ===============
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.
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):
2002 2001
------------ ------------
Projected benefit obligation at January 1 $ 1,390,737 $ 1,376,859
Interest cost 105,646 96,200
Service cost 45,414 31,863
Benefit payments (91,114) (86,010)
Actuarial loss 242,898 13,164
Plan amendments - 20,882
Acquisition adjustment (Note 2C) - (62,221)
------------ ------------
Projected benefit obligation at December 31 1,693,581 1,390,737
Fair value of plan assets at December 31 1,363,943 1,677,630
------------ ------------
Funded status (329,638) 286,893
Unrecognized transition obligation 264 370
Unrecognized prior service cost 5,040 5,346
Unrecognized actuarial loss 741,885 111,600
Minimum pension liability adjustment (496,904) -
------------ ------------
Prepaid (accrued) pension cost at December 31, net (Note 18C) $ (79,353) $ 404,209
============ ============
108
The net accrued pension cost of $79.4 million at December 31, 2002 is
recognized in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $60.2 million and accrued benefit cost of $139.6 million, of
which $130.7 is included in other liabilities and deferred credits and $8.9
million is included in liabilities of discontinued operations. The net
prepaid pension cost of $404.2 million at December 31, 2001 is recognized in
the accompanying Consolidated Balance Sheets as prepaid pension cost of
$487.6 million, accrued benefit cost of $85.4 million, which is included in
other liabilities and deferred credits, and NCNG prepaid pension cost of
$2.0 million included in assets of discontinued operations. The defined
benefit plans with accumulated benefit obligations in excess of plan assets
had projected benefit obligations totaling $1.51 billion and $85.1 million
at December 31, 2002 and 2001, respectively. Those plans had accumulated
benefit obligations totaling $1.35 billion and $83.9 million at December 31,
2002 and 2001, respectively, plan assets totaling $1.22 billion at December
31, 2002 and no plan assets at December 31, 2001.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $496.9 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $5.3 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, a $178.3 million charge to a
pension-related regulatory liability (See Note 18C) and a pre-tax charge of
$313.3 million to accumulated other comprehensive loss, a component of
common stock equity.
Reconciliations of the fair value of pension plan assets are (in thousands):
2002 2001
------------ ------------
Fair value of plan assets at January 1 $ 1,677,630 $ 1,843,410
Actual return on plan assets (228,256)
(84,254)
Benefit payments (91,114) (86,010)
Employer contributions 5,683 4,484
------------ ------------
Fair value of plan assets at December 31 $ 1,363,943 $ 1,677,630
============ ============
The weighted-average discount rate used to measure the pension obligation
was 6.6% and 7.5% in 2002 and 2001, respectively. The weighted-average rate
of increase in future compensation for non-bargaining unit employees used to
measure the pension obligation was 4.0% in 2002, 2001 and 2000. The
corresponding rate of increase in future compensation for bargaining unit
employees was 3.5% in 2002, 2001 and 2000. The expected long-term rate of
return on pension plan assets used in determining the net periodic pension
cost was 9.25% in 2002, 2001 and 2000.
B. Retiree Health and Life Insurance Benefits
In addition to pension benefits, the Company and some of its subsidiaries
provide contributory other postretirement benefits (OPEB), including certain
health care and life insurance benefits, for retired employees who meet
specified criteria.
The components of net periodic OPEB cost for the years ended December 31 are
(in thousands):
2002 2001 2000
----------- ----------- -----------
Expected return on plan assets $ (4,565) $(4,651) $ (4,045)
Service cost 13,099 13,231 10,067
Interest cost 31,876 28,414 15,446
Amortization of prior service cost 506 319 107
Amortization of transition obligation 3,066 4,701 5,878
Amortization of actuarial (gain) loss 656 (592) (819)
----------- ----------- -----------
Net periodic OPEB cost 44,638 41,422 26,634
Additional cost recognition (Note 18C) 1,863 3,461 202
----------- ----------- -----------
Net periodic OPEB cost recognized $ 46,501 $ 44,883 $ 26,836
=========== =========== ===========
109
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):
2002 2001
----------- -----------
OPEB obligation at January 1 $ 400,944 $ 374,923
Interest cost 31,876 28,414
Service cost 13,099 13,231
Benefit payments (24,144) (17,207)
Actuarial loss 91,842 27,428
Plan amendment - (25,845)
---------- -----------
OPEB obligation at December 31 513,617 400,944
Fair value of plan assets at December 31 52,354 55,529
---------- -----------
Funded status (461,263) (345,415)
Unrecognized transition obligation 30,063 33,129
Unrecognized prior service cost 7,169 7,675
Unrecognized actuarial loss 106,686 6,429
---------- -----------
Accrued OPEB cost at December 31 (Note 18C) $(317,345) $(298,182)
========== ===========
The accrued OPEB cost is included in other liabilities and deferred credits
in the accompanying Consolidated Balance Sheets.
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2002 2001
--------- ---------
Fair value of plan assets at January 1 $ 55,529 $ 54,642
Actual return on plan assets (4,506) (444)
Employer contribution 25,475 18,538
Benefits paid (24,144) (17,207)
--------- ---------
Fair value of plan assets at December 31 $ 52,354 $ 55,529
========= =========
The assumptions used to measure the OPEB obligation and determine the net
periodic OPEB cost are:
2002 2001 2000
Weighted-average long-term rate of return on plan assets 8.20% 8.70% 9.20%
Weighted-average discount rate 6.60% 7.50% 7.50%
Initial medical cost trend rate for pre-Medicare benefits 7.50% 7.50% 7.2% - 7.5%
Initial medical cost trend rate for post-Medicare benefits 7.50% 7.50% 6.2% - 7.5%
Ultimate medical cost trend rate 5.25% 5.0% 5.0% - 5.3%
Year ultimate medical cost trend rate is achieved 2009 2008 2005-2009
110
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 2002 would increase by $7.0 million, and
the OPEB obligation at December 31, 2002, would increase by $50.8 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 2002
would decrease by $6.0 million and the OPEB obligation at December 31, 2002,
would decrease by $46.2 million.
C. FPC Acquisition
During 2000, the Company completed the acquisition of FPC (See Note 2C).
FPC's pension and OPEB liabilities, assets and net periodic costs are
reflected in the above information as appropriate. Certain of FPC's
non-bargaining unit benefit plans were merged with those of the Company
effective January 1, 2002.
Florida Power continues to recover qualified plan pension costs and OPEB
costs in rates as if the acquisition had not occurred. Accordingly, a
portion of the accrued OPEB cost reflected in the table above has a
corresponding regulatory asset at December 31, 2002 and 2001 (see Note 15A).
In addition, a portion of the prepaid pension cost reflected in the table
above has a corresponding regulatory liability. Pursuant to its rate
treatment, Florida Power recognized additional periodic pension credits and
additional periodic OPEB costs, as indicated in the net periodic cost
information above.
19. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average number of
common shares outstanding. Diluted earnings per share includes the effect of
the non-vested portion of restricted stock awards and the effect of stock
options outstanding.
A reconciliation of the weighted-average number of common shares outstanding
for basic and dilutive purposes is as follows (in thousands):
2002 2001 2000
------------- ------------ ------------
Weighted-average common shares - basic 217,247 204,683 157,169
Restricted stock awards 766 664 455
Stock options 153 - -
------------- ------------ ------------
Weighted-average shares - fully dilutive 218,166 205,347 157,624
============= ============ ============
There are no adjustments to net income or to income from continuing
operations between the calculations of basic and fully diluted earnings per
common share. ESOP shares that have not been committed to be released to
participants' accounts are not considered outstanding for the determination
of earnings per common share. The weighted-average of these shares totaled
4.8 million, 5.4 million and 5.7 million for the years ended December 31,
2002, 2001 and 2000, respectively.
20. 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.
111
Accumulated deferred income tax (assets) liabilities at December 31 are (in
thousands):
2002 2001
------------ ------------
Accelerated depreciation and property cost differences $ 1,657,410 $ 1,748,646
Deferred costs, net (33,485) 79,819
Federal income tax credit carry forward (474,545) (278,773)
Minimum pension liability adjustment (117,064) -
Miscellaneous other temporary differences, net (106,650) (149,615)
Valuation allowance 46,779 35,270
------------ ------------
Net accumulated deferred income tax liability $ 972,445 $ 1,435,347
============ ============
Total deferred income tax liabilities were $2.50 billion and $2.64 billion
at December 31, 2002 and 2001, respectively. Total deferred income tax
assets were $1.53 billion and $1.20 billion at December 31, 2002 and 2001,
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 federal income tax credit carry forward at December 31, 2002 consists of
$451.6 million of alternative minimum tax credit with an indefinite carry
forward period and $22.9 million of general business credit with a carry
forward period that will begin to expire in 2020.
The Company established valuation allowances of $11.5 million, $24.4 million
and $10.9 million during 2002, 2001 and 2000, respectively, due to the
uncertainty of realizing certain future state tax benefits. The Company
believes it is more likely than not that the results of future operations
will generate sufficient taxable income to allow for the utilization of the
remaining deferred tax assets.
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
2002 2001 2000
---------- ---------- -----------
Effective income tax rate (40.0)% (40.0)% 29.1%
State income taxes, net of federal benefit (8.2) (7.7) (4.7)
AFUDC amortization (5.2) (5.0) (5.2)
Federal tax credits 78.0 94.5 12.3
Goodwill amortization and write-offs - (11.4) (0.5)
Investment tax credit amortization 4.7 5.9 4.2
ESOP dividend deduction 3.8 1.9 1.0
Interpath investment impairment - (2.1) -
Other differences, net 1.9 (1.1) (1.2)
---------- ---------- -----------
Statutory federal income tax rate 35.0% 35.0% 35.0%
========== ========== ===========
Income tax expense (benefit) applicable to continuing operations is
comprised of (in thousands):
2002 2001 2000
----------- ----------- ----------
Current - federal $ 194,914 $ 183,548 $ 247,991
state 67,785 52,144 59,832
Deferred - federal (378,939) (356,919) (82,966)
state (23,101) (10,411) (10,414)
Investment tax credit (18,467) (22,700) (17,941)
----------- ----------- ----------
Total income tax expense (benefit) $ (157,808) $ (154,338) $ 196,502
=========== =========== ==========
112
The Company, through its subsidiaries, is a majority owner in five entities
and a minority owner in one entity that own facilities that produce
synthetic fuel as defined under the Internal Revenue Service Code (Code).
The production and sale of the synthetic fuel from these facilities
qualifies for tax credits under Section 29 of the Code (Section 29) if
certain requirements are satisfied, including a requirement that the
synthetic fuel differs significantly in chemical composition from the coal
used to produce such synthetic fuel. Total Section 29 credits generated to
date (including FPC prior to its acquisition by the Company) are
approximately $897.2 million. All entities have received private letter
rulings (PLR's) from the Internal Revenue Service (IRS) with respect to
their synthetic fuel operations. The PLR's do not limit the production on
which synthetic fuel credits may be claimed. Should the tax credits be
denied on future audits, and the Company fails to prevail through the IRS or
legal process, there could be a significant tax liability owed for
previously taken Section 29 credits, with a significant impact on earnings
and cash flows.
One of the Company's synthetic fuel entities, Colona Synfuel Limited
Partnership, L.L.L.P. (Colona), is being audited by the IRS. The audit of
Colona was expected. The Company is audited regularly in the normal course
of business as are most similarly situated companies. The Company (including
FPC prior to its acquisition by the Company) has been allocated
approximately $251 million in tax credits to date for this synthetic fuel
entity. As provided for in contractual arrangements pertaining to Progress
Energy's purchase of Colona, the Company has begun escrowing quarterly
royalty payments owed to an unaffiliated entity until final resolution of
the audit.
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS's Pre-Filing
Agreement (PFA) program. The PFA program allows taxpayers to voluntarily
accelerate the IRS exam process in order to seek resolution of specific
issues. Either the Company or the IRS can withdraw from the program at any
time, and issues not resolved through the program may proceed to the next
level of the IRS exam process. While the ultimate outcome is uncertain, the
Company believes that participation in the PFA program will likely shorten
the tax exam process.
In management's opinion, Progress Energy is complying with all the necessary
requirements to be allowed such credits and believes it is likely, although
it cannot provide certainty, that it will prevail if challenged by the IRS
on any credits taken.
21. Other Income and Other Expense
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items as
discussed below. The components of other, net as shown on the Consolidated
Statements of Income for the years ended December 31 are as follows (in
thousands):
113
2002 2001 2000
------------ ------------- ------------
Other income
Net financial trading gain (loss) $ (1,942) $ (696) $ 15,603
Net energy purchased for resale 1,540 2,786 2,260
Nonregulated energy and delivery services income 28,754 29,183 26,225
Contingent value obligation unrealized gain (Note 10) 28,109 - 8,876
Investment gains 30,218 2,500 6,722
AFUDC equity 8,739 8,842 13,568
Other 31,174 16,444 12,828
------------- ------------- -------------
Total other income $ 126,592 $ 59,059 $ 86,082
------------- ------------- -------------
Other expense
Nonregulated energy and delivery services expenses 28,766 34,734 25,459
Donations 21,302 23,035 9,397
Investment losses 18,235 4,365 6,672
Contingent value obligation unrealized loss (Note 10) - 1,479 -
Other 24,485 23,885 29,131
------------- ------------- -------------
Total other expense $ 92,788 $ 87,498 $ 70,659
Other, net $ 33,804 $ (28,439) $ 15,423
============= ============= =============
Net financial trading gain (loss) represents non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include power
protection services and mass market programs (surge protection, appliance
services and area light sales) and delivery, transmission and substation
work for other utilities.
22. Joint Ownership of Generating Facilities
CP&L and Florida Power hold undivided ownership interests in certain jointly
owned generating facilities. Each is entitled to shares of the generating
capability and output of each unit equal to their respective ownership
interests. Each also pays its ownership share of additional construction
costs, fuel inventory purchases and operating expenses. CP&L's and Florida
Power's share of expenses for the jointly owned facilities is included in
the appropriate expense category. The co-owner of P11 has exclusive rights
to the output of the unit during the months of June through September.
Florida Power has that right for the remainder of the year.
CP&L's and Florida Power's ownership interests in the jointly owned
generating facilities are listed below with related information as of
December 31, 2002 and 2001 (dollars in thousands):
2002
Company Construction
Ownership Plant Accumulated Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Decommissioning Progress
---------- -------- -------- ---------- ------------ --------------- -----------
CP&L Mayo Plant 83.83% $ 464,202 $ 239,971 $ - $ 14,089
CP&L Harris Plant 83.83% 3,159,946 1,432,245 95,643 6,117
CP&L Brunswick Plant 81.67% 1,476,534 867,530 339,521 26,436
CP&L Roxboro Unit 4 87.06% 316,491 138,408 - 8,079
Florida Power Crystal River Unit 3 91.78% 777,141 504,417 396,868 27,907
Florida Power Intercession Unit P-11 66.67% 22,090 5,232 - 3,987
114
2001
Company Construction
Ownership Plant Accumulated Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Decommissioning Progress
---------- -------- -------- ---------- ------------ --------------- -----------
CP&L Mayo Plant 83.83% $ 460,026 $ 230,630 $ - $ 7,116
CP&L Harris Plant 83.83% 3,154,183 1,321,694 93,637 14,416
CP&L Brunswick Plant 81.67% 1,427,842 828,480 339,945 41,455
CP&L Roxboro Unit 4 87.06% 309,032 126,007 - 7,881
Florida Power Crystal River Unit 3 91.78% 773,835 469,840 416,995 25,723
Florida Power Intercession Unit P-11 66.67% 22,302 4,583 - 94
In the table above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
23. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows (in
thousands):
2002 2001
------------ -------------
Loss on cash flow hedges $ (42,236) $(30,623)
Minimum pension liability adjustments (192,385) -
Foreign currency translation and other (3,141) (1,557)
------------ -------------
Total accumulated other comprehensive loss $(237,762) $(32,180)
============ =============
24. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between CP&L and Power Agency, CP&L is obligated to purchase a percentage of
Power Agency's ownership capacity of, and energy from, the Harris Plant. In
1993, CP&L and Power Agency entered into an agreement to restructure
portions of their contracts covering power supplies and interests in jointly
owned units. Under the terms of the 1993 agreement, CP&L increased the
amount of capacity and energy purchased from Power Agency's ownership
interest in the Harris Plant, and the buyback period was extended six years
through 2007. The estimated minimum annual payments for these purchases,
which reflect capacity costs, total approximately $33 million. These
contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
for 2002, 2001 and 2000, respectively. In 1987, the NCUC ordered CP&L to
reflect the recovery of the capacity portion of these costs on a levelized
basis over the original 15-year buyback period, thereby deferring for future
recovery the difference between such costs and amounts collected through
rates. At December 31, 2002 and 2001, CP&L had deferred purchased capacity
costs, including carrying costs accrued on the deferred balances, of $16.9
million and $32.5 million, respectively. Increased purchases (which are not
being deferred for future recovery) resulting from the 1993 agreement with
Power Agency were approximately $32.2 million, $28.6 million and $26.0
million for 2002, 2001 and 2000, respectively.
CP&L has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts
of capacity through 2009 with minimum annual payments of approximately $31
million, representing capital-related capacity costs. Total purchases
(including transmission use charges) under the Rockport agreement amounted
to $58.6 million, $62.8 million and $61.0 million for 2002, 2001 and 2000,
respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 megawatts of
capacity through 2021 with an original minimum annual payment of
approximately $16 million, primarily representing capital-related capacity
costs. A separate long-term agreement for additional power from Broad River
115
commenced June 1, 2002. This agreement provided for the additional purchase
of approximately 300 megawatts of capacity through 2022 with an original
minimum annual payment of approximately $16 million representing
capital-related capacity costs. Total purchases under the Broad River
agreements amounted to $37.7 million and $21.2 million in 2002 and 2001,
respectively.
Florida Power has long-term contracts for approximately 473 megawatts of
purchased power with other utilities, including a contract with The Southern
Company for approximately 413 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, for both energy and
capacity, under these agreements amounted to $159.3 million, $111.7 million
and $104.5 million for 2002, 2001 and 2000, respectively. Total capacity
payments were $50.5 million, $54.1 million and $54.0 million for 2002, 2001
and 2000, respectively. Minimum purchases under these contracts,
representing capital-related capacity costs, are approximately $50 million
annually through 2005 and $30 million annually for 2006 and 2007.
Both CP&L and Florida Power have ongoing purchased power contracts with
certain cogenerators (qualifying facilities) with expiration dates ranging
from 2003 to 2025. These purchased power contracts generally provide for
capacity and energy payments. Energy payments for the Florida Power
contracts are based on actual power taken under these contracts. Capacity
payments are subject to the qualifying facilities meeting certain contract
performance obligations. Florida Power's total capacity purchases under
these contracts amounted to $231.7 million, $225.8 million and $226.4
million for 2002, 2001 and 2000, respectively. Minimum expected future
capacity payments under these contracts as of December 31, 2002 are $246.8
million, $257.4 million, $268.7 million, $279.7 million and $289.4 million
for 2003 through 2007, respectively. CP&L has various pay-for-performance
contracts with qualifying facilities for approximately 300 megawatts of
capacity expiring at various times through 2009. Payments for both capacity
and energy are contingent upon the qualifying facilities' ability to
generate. Payments made under these contracts were $144.5 million in 2002,
$145.1 million in 2001 and $168.4 million in 2000.
Florida Power and CP&L have entered into various long-term contracts for
coal, gas and oil requirements of their generating plants. Payments under
these commitments were $1.9 billion, $1.7 billion and $678.8 million for
2002, 2001 and 2000, respectively. Estimated annual payments for firm
commitments of fuel purchases and transportation costs under these contracts
are approximately $1.7 billion, $1.1 billion, $913.8 million, $907.7 million
and $850.6 million for 2003 through 2007, respectively.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties) of up
to $11.4 million on sales from each plant annually through 2007. The related
agreements were amended in December 2001 to require the payment of minimum
annual royalties of approximately $6.6 million for each plant through 2007.
As a result of the amendment, the Company recorded a liability (included in
other liabilities and deferred credits on the Consolidated Balance Sheets)
and a deferred cost asset (included in other assets and deferred debits in
the Consolidated Balance Sheets), each of approximately $114.3 million and
$134.3 million at December 31, 2002 and 2001, respectively, representing the
minimum amounts due through 2007, discounted at 6.05%. As of December 31,
2002 and 2001, the portions of the asset and liability recorded that were
classified as current were $23.8 million and $25.8 million, respectively.
The deferred cost asset will be amortized to expense each year as synthetic
fuel sales are made. The maximum amounts payable under these agreements
remain unchanged. Actual amounts paid under these agreements were
approximately $51.4 million in 2002, $45.8 million in 2001 and $43.1 million
in 2000.
The Company has entered into a joint venture to build a 750-mile natural gas
pipeline system to serve 14 eastern North Carolina counties. The Company has
agreed to fund approximately $22.0 million of the project. The entire
project is expected to be completed in early 2005. In conjunction with the
NCNG divestiture, the Company expects to sell its interest in the venture to
Piedmont Natural Gas, Inc. by summer 2003, subject to receipt of required
regulatory approvals (See Note 3A).
116
C. Guarantees
As a part of normal business, Progress Energy and certain subsidiaries enter
into various agreements providing financial or performance assessments to
third parties. Such agreements include guarantees, standby letters of credit
and surety bonds. These agreements are entered into primarily to support or
enhance the creditworthiness otherwise attributed to a subsidiary on a
stand-alone basis, thereby facilitating the extension of sufficient credit
to accomplish the subsidiaries' intended commercial purposes.
At December 31, outstanding guarantees are summarized as follows (in
millions):
2002 2001
------------ -----------
Guarantees supporting nonregulated portfolio expansion
and energy marketing and trading activities $ 329.0 $ 23.0
Standby letters of credit 48.2 29.2
Surety bonds 106.8 52.1
Other guarantees 18.6 39.8
------------ -----------
Total $ 502.6 $ 144.1
============ ===========
Guarantees Supporting Nonregulated Portfolio Expansion and Energy Marketing
and Trading Activities
Progress Energy has issued approximately $317.0 million of guarantees on
behalf of PVI and its subsidiaries for obligations under power purchase
agreements, tolling agreements, gas agreements, construction agreements and
trading operations. Approximately $145.0 million of these commitments relate
to certain guarantee agreements issued to support obligations related to
PVI's expansion of its nonregulated generation portfolio.
The remaining $172.0 million of these new commitments issued by Progress
Energy are guarantees issued to support PVI's energy marketing and trading
functions. The majority of the marketing and trading contracts supported by
the guarantees contain language regarding downgrade events, ratings
triggers, monthly netting of exposure and/or payments and offset provisions
in the event of a default. Based upon the amount of trading positions
outstanding at December 31, 2002, if the Company's ratings were to decline
below investment grade, the Company would have to deposit cash or provide
letters of credit or other cash collateral for approximately $13.7 million
for the benefit of the Company's counterparties.
In addition, PVI issued a $12.0 million guarantee related to expansion of
the portfolio. These guarantees ensure performance under generation
construction and operating agreements.
Standby Letters of Credit
The Company has issued stand-by letters of credit to financial institutions
for the benefit of third parties that have extended credit to the Company
and certain subsidiaries. These letters of credit have been issued primarily
for the purpose of supporting payments of trade payables, securing
performance under contracts and lease obligations and self-insurance for
workers compensation. If a subsidiary does not pay amounts when due under a
covered contract, the counterparty may present its claim for payment to the
financial institution, which will in turn request payment from the Company.
Any amounts owed by the Company's subsidiaries are reflected in the
accompanying Consolidated Balance Sheets.
Surety Bonds
At December 31, 2002, the Company had $106.8 million in surety bonds
purchased primarily for purposes such as providing worker compensation
coverage and obtaining licenses, permits and rights-of-way. To the extent
liabilities are incurred as a result of the activities covered by the surety
bonds, such liabilities are included in the accompanying Consolidated
Balance Sheets.
117
Other Guarantees
The Company has other guarantees outstanding related primarily to prompt
performance payments, lease obligations and other payments subject to
contingencies.
As of December 31, 2002, management does not believe conditions are likely
for performance under these agreements.
D. Insurance
CP&L and Florida Power are members of Nuclear Electric Insurance Limited
(NEIL), which provides primary and excess insurance coverage against
property damage to members' nuclear generating facilities. Under the primary
program, each company is insured for $500 million at each of its respective
nuclear plants. In addition to primary coverage, NEIL also provides
decontamination, premature decommissioning and excess property insurance
with limits of $2.0 billion on the Brunswick and Harris Plants, and $1.1
billion on the Robinson and CR3 Plants.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. Both CP&L and Florida Power are insured
thereunder, following a twelve-week deductible period, for 52 weeks in the
amount of $3.5 million per week at each of the nuclear units. An additional
110 weeks of coverage is provided at 80% of the above weekly amount. For the
current policy period, the companies are subject to retrospective premium
assessments of up to approximately $31.4 million with respect to the primary
coverage, $32.5 million with respect to the decontamination, decommissioning
and excess property coverage, and $22.2 million for the incremental
replacement power costs coverage, in the event covered losses at insured
facilities exceed premiums, reserves, reinsurance and other NEIL resources.
Pursuant to regulations, each company's property damage insurance policies
provide that all proceeds from such insurance be applied, first, to place
the plant in a safe and stable condition after an accident and, second, to
decontaminate, before any proceeds can be used for decommissioning, plant
repair or restoration. Each company is responsible to the extent losses may
exceed limits of the coverage described above.
Both CP&L and Florida Power are insured against public liability for a
nuclear incident up to $9.55 billion per occurrence. Under the current
provisions of the Price Anderson Act, which limits liability for accidents
at nuclear power plants, each company, as an owner of nuclear units, can be
assessed for a portion of any third-party liability claims arising from an
accident at any commercial nuclear power plant in the United States. In the
event that public liability claims from an insured nuclear incident exceed
$300 million (currently available through commercial insurers), each company
would be subject to pro rata assessments of up to $88.1 million for each
reactor owned per occurrence. Payment of such assessments would be made over
time as necessary to limit the payment in any one year to no more than $10
million per reactor owned. Congress is expected to approve revisions to the
Price Anderson Act in the first quarter of 2003, that will include increased
limits and assessments per reactor owned. The final outcome of this matter
cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were
multiple terrorism losses occurring within one year after the first loss
from terrorism, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant. If
terrorism losses occurred beyond the one-year period, a new set of limits
and resources would apply. For nuclear liability claims arising out of
terrorist acts, the primary level available through commercial insurers is
now subject to an industry aggregate limit of $300 million. The second level
of coverage obtained through the assessments discussed above would continue
to apply to losses exceeding $300 million and would provide coverage in
excess of any diminished primary limits due to the terrorist acts aggregate.
CP&L and Florida Power self-insure their transmission and distribution lines
against loss due to storm damage and other natural disasters. Florida Power
accrues $6 million annually to a storm damage reserve pursuant to a
regulatory order and may defer losses in excess of the reserve (See Note
15A).
118
E. Claims and uncertainties
1. The Company is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
both electric utilities and the gas utility have some connection. In this
regard, both electric utilities and the gas utility and other potentially
responsible parties are participating in investigating and, if necessary,
remediating former MGP sites with several regulatory agencies, including,
but not limited to, the U.S. Environmental Protection Agency (EPA), the
Florida Department of Environmental Protection (FDEP) and the North Carolina
Department of Environment and Natural Resources, Division of Waste
Management (DWM). In addition, the Company and its subsidiaries are
periodically notified by regulators such as the EPA and various state
agencies of their involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation. A discussion
of these sites by legal entity follows.
CP&L. There are 12 former MGP sites and 14 other sites associated with CP&L
that have required or are anticipated to require investigation and/or
remediation costs. CP&L received insurance proceeds to address costs
associated with environmental liabilities related to its involvement with
MGP sites. All eligible expenses related to these are charged against a
specific fund containing these proceeds. As of December 31, 2002,
approximately $8.0 million remains in this centralized fund with a related
accrual of $8.0 million recorded for the associated expenses of
environmental issues. As CP&L's share of costs for investigating and
remediating these sites becomes known, the fund is assessed to determine if
additional accruals will be required. CP&L does not believe that it can
provide an estimate of the reasonably possible total remediation costs
beyond what remains in the environmental insurance recovery fund. This is
due to the fact that the sites are at different stages: investigation has
not begun at 15 sites, investigation has begun but remediation cannot be
estimated at seven sites and four sites have begun remediation. CP&L
measures its liability for these sites based on available evidence including
its experience in investigating and remediating environmentally impaired
sites. The process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. Once the
environmental insurance recovery fund is depleted, CP&L will accrue costs
for the sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, CP&L cannot determine the total costs that
may be incurred in connection with the remediation of all sites. According
to current information, these future costs at the CP&L sites are not
expected to be material to the Company's financial condition or results of
operations.
Florida Power. There are two former MGP sites and 11 other active sites
associated with Florida Power that have required or are anticipated to
require investigation and/or remediation costs. As of December 31, 2002 and
2001, Florida Power has accrued approximately $10.9 million and $8.5
million, respectively, for probable and reasonably estimable costs at these
sites. Florida Power does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what is currently
accrued. In 2002, Florida Power filed a petition for recovery of
approximately $4.0 million in environmental costs through the Environmental
Cost Recovery Clause with the FPSC. Florida Power was successful with this
filing and will recover costs through rates for investigation and
remediation associated with transmission and distribution substations and
transformers. As more activity occurs at these sites, Florida Power will
assess the need to adjust the accruals. These accruals have been recorded on
an undiscounted basis. Florida Power measures its liability for these sites
based on available evidence including its experience in investigating and
remediating environmentally impaired sites. This process often includes
assessing and developing cost-sharing arrangements with other potentially
responsible parties.
119
NCNG. There are five former MGP sites associated with NCNG that have or are
anticipated to have investigation or remediation costs associated with them.
As of December 31, 2002, NCNG has accrued approximately $2.8 million for
probable and reasonably estimable remediation costs at these sites. These
accruals have been recorded on an undiscounted basis. NCNG measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often involves assessing and developing cost-sharing
arrangements with other potentially responsible parties. NCNG does not
believe it can provide an estimate of the reasonably possible total
remediation costs beyond the accrual because two of the five sites
associated with NCNG have not begun investigation activities. Therefore,
NCNG cannot currently determine the total costs that may be incurred in
connection with the investigation and/or remediation of all sites. Based
upon current information, the Company does not expect the future costs at
the NCNG sites to be material to the Company's financial condition or
results of operations. On October 16, 2002, the Company announced plans to
sell NCNG to Piedmont Natural Gas Company, Inc. (See Note 3A). The Company
will retain the environmental liability associated with the five former MGP
sites.
Florida Progress Corporation. In 2001, FPC sold its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc. to AEP Resources,
Inc. (See Note 3C). FPC established an accrual to address indemnities and
retained an environmental liability associated with the transaction. The
balance in this accrual is $9.9 million at December 31, 2002. FPC estimates
that its maximum contractual liability to AEP Resources, Inc., associated
with Inland Marine Transportation is $60 million. This accrual has been
determined on an undiscounted basis. FPC measures its liability for this
site based on estimable and probable remediation scenarios. The Company
believes that it is reasonably probable that additional costs, which cannot
be currently estimated, may be incurred related to the environmental
indemnification provision beyond the amount accrued. The Company cannot
predict the outcome of this matter.
CP&L, Florida Power, PVI and NCNG have filed claims with the Company's
general liability insurance carriers to recover costs arising out of actual
or potential environmental liabilities. Some claims have been settled and
others are still pending. While the Company cannot predict the outcome of
these matters, the outcome is not expected to have a material effect on the
consolidated financial position or results of operations.
The Company is also currently in the process of assessing potential costs
and exposures at other environmentally impaired sites. As the assessments
are developed and analyzed, the Company will accrue costs for the sites to
the extent the costs are probable and can be reasonably estimated.
Air and Water Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nation-wide caps and
emission rates over an extended period of time. This national
multi-pollutant approach to air pollution control could involve significant
capital costs which could be material to the Company's consolidated
financial position or results of operations. Some companies may seek
recovery of the related cost through rate adjustments or similar mechanisms.
Control equipment that will be installed on North Carolina fossil generating
facilities as part of the North Carolina legislation discussed below may
address some of the issues outlined above. However, the Company cannot
predict the outcome of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both CP&L and Florida Power were asked to provide information to the EPA as
part of this initiative and cooperated in providing the requested
information. The EPA initiated civil enforcement actions against other
unaffiliated utilities as part of this initiative. Some of these actions
resulted in settlement agreements calling for expenditures, ranging from
$1.0 billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule addressing the regional transport of
ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce nitrogen oxide emissions in
120
order to attain a pre-set state NOx emission levels by May 31, 2004. CP&L is
currently installing controls necessary to comply with the rule. Capital
expenditures needed to meet these measures in North and South Carolina could
reach approximately $370 million, which has not been adjusted for inflation.
Increased operation and maintenance costs relating to the NOx SIP Call are
not expected to be material to the Company's results of operations. Further
controls are anticipated as electricity demand increases. The Company cannot
predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new eight-hour
ozone standard. In October 1999, the District of Columbia Circuit Court of
Appeals ruled against the EPA with regard to the federal eight-hour ozone
standard. The U.S. Supreme Court has upheld, in part, the District of
Columbia Circuit Court of Appeals decision. Designation of areas that do not
attain the standard is proceeding, and further litigation and rulemaking on
this and other aspects of the standard are anticipated. North Carolina
adopted the federal eight-hour ozone standard and is proceeding with the
implementation process. North Carolina has promulgated final regulations,
which will require CP&L to install nitrogen oxide controls under the state's
eight-hour standard. The costs of those controls are included in the $370
million cost estimate set forth above. However, further technical analysis
and rulemaking may result in a requirement for additional controls at some
units. The Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated, required certain sources
to make reductions in nitrogen oxide emissions by May 1, 2003. The final
rule also includes a set of regulations that affect nitrogen oxide emissions
from sources included in the petitions. The North Carolina coal-fired
electric generating plants are included in these petitions. Acceptable state
plans under the NOx SIP Call can be approved in lieu of the final rules the
EPA approved as part of the Section 126 petitions. CP&L, other utilities,
trade organizations and other states participated in litigation challenging
the EPA's action. On May 15, 2001, the District of Columbia Circuit Court of
Appeals ruled in favor of the EPA, which will require North Carolina to make
reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in
its May 15th decision, rejected the EPA's methodology for estimating the
future growth factors the EPA used in calculating the emissions limits for
utilities. In August 2001, the Court granted a request by CP&L and other
utilities to delay the implementation of the Section 126 Rule for electric
generating units pending resolution by the EPA of the growth factor issue.
The Court's order tolls the three-year compliance period (originally set to
end on May 1, 2003) for electric generating units as of May 15, 2001. On
April 30, 2002, the EPA published a final rule harmonizing the dates for the
Section 126 Rule and the NOx SIP Call. In addition, the EPA determined in
this rule that the future growth factor estimation methodology was
appropriate. The new compliance date for all affected sources is now May 31,
2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP
Call rule and has indicated it will rescind the Section 126 rule in a future
rule making. The Company expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. Progress Energy expects its
capital costs to meet these emission targets will be approximately $813
million by 2013. CP&L currently has approximately 5,100 MW of coal-fired
generation capacity in North Carolina that is affected by this legislation.
The legislation requires the emissions reductions to be completed in phases
by 2013, and applies to each utility's total system rather than setting
requirements for individual power plants. The legislation also freezes the
utilities' base rates for five years unless there are extraordinary events
beyond the control of the utilities or unless the utilities persistently
earn a return substantially in excess of the rate of return established and
found reasonable by the NCUC in the utilities' last general rate case.
Further, the legislation allows the utilities to recover from their retail
customers the projected capital costs during the first seven years of the
ten-year compliance period beginning on January 1, 2003. The utilities must
recover at least 70% of their projected capital costs during the five-year
rate freeze period. Pursuant to the new law, CP&L entered into an agreement
with the state of North Carolina to transfer to the state all future
emissions allowances it generates from over-complying with the new federal
emission limits when these units are completed. The new law also requires
the state to undertake a study of mercury and carbon dioxide emissions in
North Carolina. Progress Energy cannot predict the future regulatory
interpretation, implementation or impact of this new law.
Certain historical waste sites exist that are being addressed voluntarily by
PVI. An immaterial accrual has been established to address investigation
expenses related to these sites. The Company cannot determine the total
costs that may be incurred in connection with these sites. According to
current information, these future costs are not expected to be material to
the Company's financial condition or results of operations.
121
Rail Services is voluntarily addressing certain historical waste sites. An
immaterial accrual has been established to address estimable costs. The
Company cannot determine the total costs that may be incurred in connection
with these sites. According to current information, these future costs are
not expected to be material to the Company's financial condition or results
of operations.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol,
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush administration
favors voluntary programs. Reductions in carbon dioxide emissions to the
levels specified by the Kyoto Protocol and some legislative proposals could
be materially adverse to Company financials and operations if associated
costs cannot be recovered from customers. The Company favors the voluntary
program approach recommended by the administration, and is evaluating
options for the reduction, avoidance, and sequestration of greenhouse gases.
However, the Company cannot predict the outcome of this matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, the EPA determined
in 2000 that regulation of mercury emissions from coal-fired power plants
was appropriate. The EPA is currently developing a Maximum Available Control
Technology (MACT) standard, which is expected to become final in December
2004, with compliance in 2008. Achieving compliance with the MACT standard
could be materially adverse to the Company's financials and operations.
However, the Company cannot predict the outcome of this matter.
2. CP&L, like other electric power companies in North Carolina, pays a
franchise tax levied by the state pursuant to North Carolina General
Statutes Section 105-116, a state-level annual franchise tax (State
Franchise Tax). Part of the revenue generated by the State Franchise Tax is
required by North Carolina General Statutes Section 105-116.1(b) to be
distributed to North Carolina cities in which CP&L maintains facilities.
CP&L has paid and continues to pay the State Franchise Tax to the state when
such taxes are due. However, pursuant to an Executive Order issued on
February 5, 2002, by the Governor of North Carolina, the Secretary of
Revenue withheld distributions of State Franchise Tax revenues to cities for
two quarters of fiscal year 2001-2002 in an effort to balance the state's
budget.
In response to the state's failure to distribute the State Franchise Tax
proceeds, certain cities in which CP&L maintains facilities adopted
municipal franchise tax ordinances purporting to impose on CP&L a local
franchise tax. The local taxes are intended to be collected for as long as
the state withholds distribution of the State Franchise Tax proceeds from
the cities. The first local tax payments were due August 15, 2002. On August
2, 2002, CP&L filed a lawsuit against the cities seeking to enjoin the
enforcement of the local taxes and to have the local ordinances struck down
because the ordinances are beyond the cities' statutory authority and
violate provisions of the North Carolina and United States Constitutions.
On September 14, 2002, the Governor of North Carolina signed into law a
provision that prevents cities and counties from levying local franchise
taxes on electric utilities. This new legislation makes the lawsuit CP&L
filed in August against certain cities that were seeking to enforce local
franchise tax ordinances moot. As a result of the enactment of this
legislation, the parties have agreed to an Order of Dismissal by Consent,
which has been signed by the judge and filed with the Clerk of Court in
Caswell County.
3. 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.
122
In April 1995, the DOE issued a final interpretation that it did not have an
unconditional obligation to take spent nuclear fuel by January 31, 1998. In
Indiana & Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana & Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that their delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals found
that the delay was not unavoidable, but did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998,
a group of utilities filed a motion with the Court of Appeals to enforce the
mandate in NSP v. DOE. Specifically, this group of utilities asked the Court
to permit the utilities to escrow their waste fee payments, to order the DOE
not to use the waste fund to pay damages to the utilities, and to order the
DOE to establish a schedule for disposal of spent nuclear fuel. The Court
denied this motion based primarily on the grounds that a review of the
matter was premature, and that some of the requested remedies fell outside
of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. 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 the DOE. CP&L and Florida Power are in the process of evaluating
whether they should each file a similar action for damages.
CP&L and Florida Power also continue to monitor legislation that has been
introduced in Congress which might provide some limited relief. CP&L and
Florida Power cannot predict the outcome of this matter.
With certain modifications, CP&L's spent nuclear fuel storage facilities
will be sufficient to provide storage space for spent fuel generated on
CP&L's system through the expiration of the current operating licenses for
all of CP&L's nuclear generating units. Subsequent to the expiration of
these licenses, dry storage may be necessary. CP&L obtained approval from
the U.S. Nuclear Regulatory Commission to use additional storage space at
the Harris Plant in December 2000. Florida Power currently is storing spent
nuclear fuel onsite in spent fuel pools. If Florida Power does not seek
renewal of the CR3 operating license, CR3 will have sufficient storage
capacity in place for fuel consumed through the end of the expiration of the
license in 2016. If Florida Power extends the CR3 operating license, dry
storage may be necessary.
4. 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.
123
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, 2002 and 2001, and the related consolidated statements of
income and comprehensive income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2002. These financial
statements 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 at December 31, 2002 and
2001, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
124
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 3,538,957 $ 3,343,720 $ 3,308,215
Natural gas - - 147,448
Diversified business 14,863 16,441 72,783
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,553,820 3,360,161 3,528,446
- ---------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 761,379 647,263 627,463
Purchased power 347,420 353,551 325,366
Gas purchased for resale - - 103,734
Operation and maintenance 792,660 701,703 741,466
Depreciation and amortization 523,846 521,910 708,249
Taxes other than on income 157,568 149,719 148,037
Diversified business 115,733 9,985 135,258
- ---------------------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,698,606 2,384,131 2,789,573
- ---------------------------------------------------------------------------------------------------------------------
Operating Income 855,214 976,030 738,873
- ---------------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 6,868 13,728 17,420
Gain on sale of investment - - 200,000
Impairment of investment (25,011) (156,712) -
Other, net 12,757 (4,155) 17,089
- ---------------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (5,386) (147,139) 234,509
- ---------------------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 217,010 257,141 240,620
Allowance for borrowed funds used during construction (5,474) (15,714) (18,537)
- ---------------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 211,536 241,427 222,083
- ---------------------------------------------------------------------------------------------------------------------
Income before Income Taxes 638,292 587,464 751,299
Income Tax Expense 207,360 223,233 290,271
- ---------------------------------------------------------------------------------------------------------------------
Net Income 430,932 364,231 461,028
Preferred Stock Dividend Requirement 2,964 2,964 2,966
- ---------------------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 427,968 $ 361,267 $ 458,062
- ---------------------------------------------------------------------------------------------------------------------
Comprehensive Income, Net of Tax:
Net Income $ 430,932 $ 364,231 $ 461,028
SFAS No. 133 transition adjustment (net of tax of $474) - (738) -
Change in net unrealized losses on cash flow hedges (net of
tax of $9,080 and $7,565, respectively) (14,144) (11,784) -
Reclassification adjustment for amounts included in net
income (net of tax of $7,583 and $3,515, respectively) 11,811 5,476 -
Minimum pension liability adjustment (net of tax of $47,317) (73,390) - -
- ---------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 355,209 $ 357,185 $ 461,028
- ---------------------------------------------------------------------------------------------------------------------
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
125
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands) December 31
Assets 2002 2001
- --------------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 12,675,761 $ 12,024,291
Accumulated depreciation (6,356,933) (5,952,206)
- --------------------------------------------------------------------------------------------------------------------
Utility plant in service, net 6,318,828 6,072,085
Held for future use 7,188 7,105
Construction work in progress 325,695 711,129
Nuclear fuel, net of amortization 176,622 200,332
- --------------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 6,828,333 6,990,651
- --------------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 18,284 21,250
Accounts receivable 301,178 302,781
Unbilled accounts receivable 151,352 136,514
Receivables from affiliated companies 36,870 26,182
Notes receivable from affiliated companies 49,772 998
Taxes receivable 5,890 17,543
Inventory 342,886 372,725
Deferred fuel cost 146,015 131,505
Prepayments and other current assets 94,658 78,056
- --------------------------------------------------------------------------------------------------------------------
Total Current Assets 1,146,905 1,087,554
- --------------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 252,083 277,550
Nuclear decommissioning trust funds 423,293 416,721
Diversified business property, net 9,435 111,802
Miscellaneous other property and investments 209,657 224,101
Other assets and deferred debits 104,978 150,306
- --------------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 999,446 1,180,480
- --------------------------------------------------------------------------------------------------------------------
Total Assets $ 8,974,684 $ 9,258,685
- --------------------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- --------------------------------------------------------------------------------------------------------------------
Capitalization (see consolidated schedules of capitalization)
- --------------------------------------------------------------------------------------------------------------------
Common stock $ 3,089,115 $ 3,095,456
Preferred stock - not subject to mandatory redemption 59,334 59,334
Long-term debt, net 3,048,466 2,698,318
- --------------------------------------------------------------------------------------------------------------------
Total Capitalization 6,196,915 5,853,108
- --------------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt - 600,000
Accounts payable 259,217 300,829
Payables to affiliated companies 98,572 106,114
Notes payable to affiliated companies - 47,913
Interest accrued 58,791 61,124
Short-term obligations 437,750 260,535
Current portion of accumulated deferred income taxes 66,088 67,975
Other current liabilities 93,171 140,670
- --------------------------------------------------------------------------------------------------------------------
Total Current Liabilities 1,013,589 1,585,160
- --------------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,179,689 1,316,823
Accumulated deferred investment tax credits 158,308 170,302
Regulatory liabilities 7,774 7,494
Other liabilities and deferred credits 418,409 325,798
- --------------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 1,764,180 1,820,417
- --------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 18)
- --------------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 8,974,684 $ 9,258,685
- --------------------------------------------------------------------------------------------------------------------
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
126
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS of CASH FLOWS
Years ended December 31
(In thousands) 2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 430,932 $ 364,231 $ 461,028
Adjustments to reconcile net income to net cash provided by operating activities:
Impairment of long-lived assets and investments 126,262 156,712 -
Depreciation and amortization 631,401 616,206 803,211
Deferred income taxes (81,916) (149,895) (83,554)
Investment tax credit (11,994) (14,928) (4,511)
Gain on sale of assets - - (200,000)
Deferred fuel credit (14,510) (11,652) (40,763)
Net (increase) decrease in accounts receivable 222,293 304,106 (185,640)
Net (increase) decrease in inventories 9,998 (139,854) (3,699)
Net (increase) decrease in prepayments and other current assets (14,953) 21,679 87,575
Net increase (decrease) in accounts payable 20,490 (261,606) 314,267
Net increase (decrease) in other current liabilities (2,332) 52,704 146,802
Other 51,801 47,140 26,019
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,367,472 984,843 1,320,735
- ---------------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (624,202) (823,952) (821,991)
Nuclear fuel additions (80,515) (72,576) (59,752)
Proceeds from sale of assets - - 200,000
Contributions to nuclear decommissioning trust (30,708) (30,678) (30,727)
Diversified business property additions (11,836) (13,500) (56,489)
Investments in non-utility activities (17,053) (32,674) (111,516)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (764,314) (973,380) (880,475)
- ---------------------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 542,290 296,124 783,052
Net increase (decrease) in short-term obligations 177,215 (225,762) 123,697
Net increase (decrease) in intercompany notes (96,687) 187,560 (275,628)
Retirement of long-term debt (806,809) (134,611) (695,163)
Equity contribution from parent - 115,000 -
Dividends paid to parent (396,680) (255,630) -
Dividends paid on preferred stock (2,964) (2,964) (2,966)
Dividends paid on common stock - - (432,325)
Other (22,489) - 21,027
- ---------------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (606,124) (20,283) (478,306)
- ---------------------------------------------------------------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (2,966) (8,820) (38,046)
- ---------------------------------------------------------------------------------------------------------------------------------
Decrease in Cash from Stock Distribution (See Note 1A) - - (11,755)
Cash and Cash Equivalents at Beginning of Year 21,250 30,070 79,871
- ---------------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 18,284 $ 21,250 $ 30,070
- ---------------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $208,283 $230,828 $205,250
income taxes (net of refunds) $319,973 $395,433 $434,908
Noncash Investing and Financing Activities
o On June 28, 2000, Caronet, Inc., 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.
o On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas Corporation, Strategic Resource Solutions Corp.,
Monroe Power Company and Progress Ventures, Inc. to Progress Energy, Inc.
This resulted in a noncash dividend to its parent of approximately $556
million (See Note 1A).
o In January 2001, CP&L transferred certain assets, through a noncash
dividend to parent in the amount of $19 million, to Progress Energy Service
Company, LLC.
o In February 2002, CP&L transferred the Rowan plant to Progress Ventures,
Inc. The property and inventory transferred totaled approximately $245
million.
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
127
CAROLINA POWER & LIGHT COMPANY
CONSOLIDATED SCHEDULES of CAPITALIZATION
December 31
(In thousands except share data) 2002 2001
-------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, authorized 200,000,000 shares,
159,608,055 shares issued and outstanding at December 31 $ 1,929,515 $ 1,904,246
Unearned ESOP common stock (101,560) (114,385)
Accumulated other comprehensive loss (82,769) (7,046)
Retained earnings 1,343,929 1,312,641
-------------------------------------------------------------------------------------------------------------
Total Common Stock Equity $ 3,089,115 $ 3,095,456
-------------------------------------------------------------------------------------------------------------
Preferred Stock - not subject to mandatory redemption
Authorized - 300,000 shares, cumulative, $100 par value Preferred
Stock; 20,000,000 shares, cumulative, $100 par value Serial
Preferred Stock
$5.00 Preferred - 236,997 shares (redemption price $110.00) $ 24,349 $ 24,349
$4.20 Serial Preferred - 100,000 shares outstanding
redemption price $102.00) 10,000 10,000
$5.44 Serial Preferred -249,850 shares (redemption price
$101.00) 24,985 24,985
-------------------------------------------------------------------------------------------------------------
Total Preferred Stock $ 59,334 $ 59,334
-------------------------------------------------------------------------------------------------------------
Long-Term Debt (maturities and weighted-average interest rates as
of December 31, 2002)
First mortgage bonds, maturing 2004-2023 6.92% $ 1,550,000 $ 1,800,000
Pollution control obligations, maturing 2010-2024 1.86% 707,800 707,800
Unsecured notes, maturing 2012 6.50% 500,000 -
Extendible notes, maturing 2002 - - 500,000
Medium-term notes, maturing 2008 6.65% 300,000 300,000
Miscellaneous notes 6.44% 6,910 7,234
Unamortized premium and discount, net (16,244) (16,716)
Current portion of long-term debt - (600,000)
-------------------------------------------------------------------------------------------------------------
Total Long-Term Debt, Net 3,048,466 2,698,318
-------------------------------------------------------------------------------------------------------------
Total Capitalization $ 6,196,915 $ 5,853,108
-------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
Years ended December 31
(In thousands) 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year $ 1,312,641 $ 1,226,144 $ 1,807,345
Net income 430,932 364,231 461,028
Preferred stock dividends at stated rates (2,964) (2,964) (2,966)
Common stock dividends (396,680) (274,770) (1,039,263)
- --------------------------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,343,929 $ 1,312,641 $ 1,226,144
- --------------------------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In thousands) First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $ 814,871 $ 838,092 $ 1,049,484 $ 851,373
Operating income 193,185 210,022 240,051 211,956
Net income 85,119 131,152 94,139 120,522
- -----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2001
Operating revenues $ 826,603 $ 783,379 $ 976,891 $ 773,288
Operating income 231,641 184,390 322,477 237,522
Net income (loss) 120,845 84,879 167,874 (9,367)
o In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
o Fourth quarter 2001 includes impairment and other charges related to
Interpath Communications, Inc. of $156.7 million ($107.2 million, after
tax) (See Note 5).
o Third quarter 2002 includes impairment and other charges related to
Caronet, Inc. and Interpath Communications, Inc. of $133.3 million ($87.4
million, after tax) (See Note 5).
See Carolina Power & Light Company Notes to Consolidated Financial Statements.
128
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. Through its
wholly owned subsidiaries, CP&L is involved in several nonregulated business
activities, the most significant of which is its telecommunications
operation. CP&L is a wholly owned subsidiary of Progress Energy, Inc. (the
Company or Progress Energy), which was formed as a result of the
reorganization of CP&L into a holding company structure on June 19, 2000.
All shares of common stock of CP&L were exchanged for an equal number of
shares of CP&L Energy, Inc. 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 of
1935 (PUHCA). Both the Company and its subsidiaries are subject to the
regulatory provisions of PUHCA.
On July 1, 2000, CP&L distributed its ownership interest in the stock of
North Carolina Natural Gas Corporation (NCNG), Strategic Resource Solutions
Corp. (SRS), Monroe Power Company (Monroe Power) and Progress Ventures, Inc.
(PVI) to the Company. 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 subsequent to July 1, 2000.
Effective January 1, 2003, CP&L began doing business under the assumed name
Progress Energy Carolinas, Inc. The legal name has not changed and there is
no restructuring of any kind related to the name change. The current
corporate and business unit structure remains unchanged.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of 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 ratemaking 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).
Unconsolidated investments in companies over which CP&L does not have
control, but has the ability to exercise influence over operating and
financial policies (generally, 20% - 50% voting interest) are accounted for
under the equity method of accounting. Other investments are stated
principally at cost. These equity and cost investments, which total
approximately $95.0 million and $114.3 million at December 31, 2002 and
2001, respectively, are included as miscellaneous property and investments
in the Consolidated Balance Sheets. The primary component of this balance is
CP&L's investments in affordable housing of $63.4 million and $54.3 million
as of December 31, 2002 and 2001, respectively. Included in the December 31,
2001 investment balance is CP&L's investment in Interpath Communications,
Inc. of $27.0 million (See Note 5).
Certain amounts for 2001 and 2000 have been reclassified to conform to the
2002 presentation.
C. Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and amounts
of revenues and expenses reflected during the reporting period. Actual
results could differ from those estimates.
129
D. Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. CP&L capitalizes all construction-related direct labor and
material costs of units of property as well as indirect construction costs.
The costs of renewals and betterments are also capitalized. Maintenance and
repairs of property, and replacements and renewals of items determined to be
less than units of property, are charged to maintenance expense as incurred.
The cost of units of property replaced, 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 (See Note 6).
The balances of utility plant in service at December 31 are listed below (in
thousands), with a range of depreciable lives for each:
2002 2001
------------ ------------
Production plant (7-33 years) $ 7,629,539 $ 7,301,225
Transmission plant (30-75 years) 1,128,097 1,092,024
Distribution plant (12-50 years) 3,344,662 3,063,753
General plant and other (8-75 years) 573,463 567,289
------------ ------------
Utility plant in service $ 12,675,761 $ 12,024,291
============ ============
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The total
equity funds portion of AFUDC was $6.4 million, $8.8 million and $14.5
million in 2002, 2001 and 2000, respectively. The composite AFUDC rate for
CP&L's electric utility plant was 6.2% in both 2002 and 2001 and 8.2% in
2000.
E. Depreciation and Amortization - Utility Plant
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated 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 2002, 2001 and 2000. Depreciation
and decommissioning provisions, including accelerated cost recovery, totaled
$504.5 million, $504.9 million and $688.8 million in 2002, 2001 and 2000,
respectively.
With approval from the NCUC and the SCPSC, CP&L accelerated the cost
recovery of its nuclear generating assets beginning January 1, 2000. During
2002, the NCUC and the SCPSC approved modifications to CP&L's ongoing
accelerated cost recovery of its nuclear generating assets including
extension of the recovery period. Cumulative accelerated depreciation
ranging from $530 million to $750 million will be recorded by December 31,
2009. The accelerated cost recovery of these assets resulted in additional
depreciation expense of approximately $53 million, $75 million and $275
million in 2002, 2001 and 2000, respectively. Total accelerated depreciation
recorded through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction (See Note
9B).
Amortization of nuclear fuel costs, including disposal costs associated with
obligations to the U.S. Department of Energy (DOE), is computed primarily on
the units-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. The total of these
costs for the years ended December 31, 2002, 2001 and 2000 were $109.1
million, $101.0 million and $112.1 million, respectively.
130
F. Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If CP&L recognizes an impairment of an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis.
The following is a summary of diversified business property (in thousands)
as of December 31, with ranges of depreciable lives:
2002 2001
---------- ----------
Telecommunications equipment (5 - 20 years) $ 1,687 $ 94,164
Other equipment (3 - 10 years) 8,363 11,657
Construction work in progress 497 21,622
Accumulated depreciation (1,112) (15,641)
---------- ----------
Diversified business property, net $ 9,435 $ 111,802
========== ==========
The decrease from 2001 to 2002 is attributable to an impairment of assets
discussed in Note 5. Diversified business depreciation expense was $3.6
million, $6.4 million and $3.2 million in 2002, 2001 and 2000, respectively.
G. Decommissioning and Dismantlement 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 2002, 2001 and 2000.
Accumulated decommissioning costs, which are included in accumulated
depreciation, were $611.3 million and $604.8 million at December 31, 2002
and 2001, 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 years 2010 for Robinson Unit No. 2, 2016 for Brunswick
Unit No. 1, 2014 for Brunswick Unit No. 2 and 2026 for the Harris Plant. An
application to extend the Robinson license 20 years was submitted in 2002
and a similar application will be made for Brunswick in December 2004. An
extension will also be sought for the Harris Plant, tentatively in 2009.
Management believes that the decommissioning costs that have been and will
be recovered through rates will be sufficient to provide for the costs of
decommissioning.
The Financial Accounting Standards Board (FASB) has issued SFAS No. 143,
"Accounting for Asset Retirement Obligations," that will impact the
accounting for decommissioning and dismantlement provisions (See Note 1P).
131
H. Excise Taxes
CP&L, as an agent for a state or local government, collects from customers
certain excise taxes levied by the state or local government upon the
customer. CP&L accounts for excise taxes on a gross basis. Excise taxes are
included in CP&L's base rates. For the years ended December 31, 2002, 2001
and 2000, gross receipts tax and other excise taxes of approximately $79.3
million, $76.8 million and $75.1 million, respectively, are included in
taxes other than on income on the Consolidated Statements of Income and
Comprehensive Income. These approximate amounts are also included in
electric operating revenues.
I. Inventory
CP&L accounts for inventory using the average-cost method. As of December
31, inventory was comprised of (in thousands):
2002 2001
---------- ----------
Fuel $ 117,946 $ 137,236
Materials and supplies 224,940 235,489
---------- ----------
Total inventory $ 342,886 $ 372,725
========== ==========
J. Other Policies
CP&L recognizes electric utility revenue as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Revenues related to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by CP&L's regulators. These clauses allow CP&L to
recover fuel costs and portions of purchased power costs through surcharges
on customer rates.
CP&L maintains an allowance for doubtful accounts receivable, which totaled
approximately $11.3 million and $12.2 million at December 31, 2002 and 2001,
respectively.
Long-term debt premiums, discounts and issuance expenses for the utilities
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utilities are amortized over the remaining life of
the original debt using the straight-line method consistent with ratemaking
treatment.
CP&L considers all highly liquid investments with original maturities of
three months or less to be cash equivalents.
CP&L participates in a money pool arrangement with other Progress Energy
subsidiaries to better manage cash and working capital requirements. Under
this arrangement, subsidiaries with surplus short-term funds provide
short-term loans to participating affiliates (See Note 4).
The Company follows the guidance in SFAS No. 87, "Employers' Accounting for
Pensions," to account for its defined benefit retirement plans. In addition
to pension benefits, the Company provides other postretirement benefits
which are accounted for under SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." See Note 13 for related
disclosures for these plans.
K. Impairment of Long-Lived Assets and Investments
CP&L reviews the recoverability of long-lived and intangible assets whenever
indicators exist. Examples of these indicators include current period
losses, combined with a history of losses or a projection of continuing
losses, or a significant decrease in the market price of a long-lived asset
group. If an indicator exists, then the asset group is tested for
recoverability by comparing the carrying value to the sum of undiscounted
expected future cash flows directly attributable to the asset group. If the
asset group is not recoverable through undiscounted cash flows, then an
impairment loss is recognized for the difference between the carrying value
and the fair value of the asset group. The accounting for impairment of
assets is based on SFAS No. 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," which was adopted by CP&L effective January 1, 2002.
Prior to the adoption of this standard, impairments were accounted for under
132
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," which was superceded by SFAS No. 144.
See Note 5 for discussion of impairment evaluations performed and charges
taken.
L. Income Taxes
Progress Energy and its affiliates file a consolidated federal income tax
return. The consolidated income tax of Progress Energy is allocated to CP&L
in accordance with the Inter-company Income Tax Allocation Agreement. The
agreement provides an allocation that recognizes positive and negative
corporate taxable income. The agreement provides for an equitable method of
apportioning the carry over of uncompensated tax benefits. Progress Energy
Holding Company tax benefits not related to acquisition interest expense are
allocated to profitable subsidiaries, beginning in 2002, in accordance with
a PUHCA order. Income taxes are provided as if CP&L filed a separate return.
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between the book and tax carrying amounts
of assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties (See Note 14).
M. Derivatives
Effective January 1, 2001, CP&L adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS No. 138.
SFAS No. 133, as amended, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS No. 133 requires that an
entity recognize all derivatives as assets or liabilities in the balance
sheet and measure those instruments at fair value. See Note 10 for
information regarding risk management activities and derivative
transactions.
In connection with the January 2003 FASB Emerging Issues Task Force (EITF)
meeting, the FASB was requested to reconsider an interpretation of SFAS No.
133. The interpretation, which is contained in the Derivatives
Implementation Group's C11 guidance, relates to the pricing of contracts
that include broad market indices. In particular, that guidance discusses
whether the pricing in a contract that contains broad market indices (e.g.,
CPI) could qualify as a normal purchase or sale (the normal purchase or sale
term is a defined accounting term, and may not, in all cases, indicate
whether the contract would be "normal" from an operating entity viewpoint).
CP&L is currently reevaluating which contracts, if any, that have previously
been designated as normal purchases or sales would now not qualify for this
exception. CP&L is currently evaluating the effects that this guidance will
have on its results of operation and financial position.
N. Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
expenditures are expensed as incurred or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as additional
information develops or circumstances change. Costs of future expenditures
for environmental remediation obligations are not discounted to their
present value. Recoveries of environmental remediation costs from other
parties are recognized when their receipt is deemed probable (See Note 18D).
O. Cost-Based Regulation
CP&L's regulated operations are subject to SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." SFAS No. 71 allows a regulated
company to record costs that have been or are expected to be allowed in the
ratemaking process in a period different from the period in which the costs
would be charged to expense by a nonregulated enterprise. Accordingly, CP&L
records assets and liabilities that result from the regulated ratemaking
process that would not be recorded under GAAP for nonregulated entities.
These regulatory assets and liabilities represent expenses deferred for
future recovery from customers or obligations to be refunded to customers
and are primarily classified in the accompanying Consolidated Balance Sheets
as regulatory assets and regulatory liabilities (See Note 9A).
133
P. Impact of New Accounting Standards
SFAS No. 143, "Accounting for Asset Retirement Obligations"
The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations,"
in July 2001. This statement provides accounting and disclosure requirements
for retirement obligations associated with long-lived assets and is
effective January 1, 2003. This statement requires that the present value of
retirement costs for which CP&L has a legal obligation be recorded as
liabilities with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation will be recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of this
Statement. The cumulative effect of implementing this Statement is
recognized as a change in accounting principle. The adoption of this
statement will have no impact on CP&L's net income, as the effects are
expected to be offset by the establishment of regulatory assets and
liabilities pursuant to SFAS No. 71.
CP&L's review identified legal retirement obligations for nuclear
decommissioning of radiated plant. CP&L will record liabilities pursuant to
SFAS No. 143 beginning in 2003. CP&L used an expected cash flow approach to
measure the obligations. The proforma amounts for nuclear decommissioning of
radiated plant as if SFAS No. 143 had been applied during all periods are
$879.7 million and $830.5 million at December 31, 2002 and 2001,
respectively.
Nuclear decommissioning has previously-recorded liabilities. Amounts
recorded for nuclear decommissioning of radiated plant were $491.3 million
and $460.9 million at December 31, 2002 and 2001, respectively.
Proforma net income has not been presented for the years ended December 31,
2002, 2001 and 2000 because the proforma application of SFAS No. 143 to
prior periods would result in proforma net income not materially different
from the actual amounts reported for those periods in the accompanying
Consolidated Statements of Income and Comprehensive Income.
CP&L has identified but not recognized asset retirement obligation (ARO)
liabilities related to electric transmission and distribution and
telecommunications assets as the result of easements over property not owned
by CP&L. These easements are generally perpetual and only require retirement
action upon abandonment or cessation of use of the property for the
specified purpose. The ARO liability is not estimable for such easements as
CP&L intends to utilize these properties indefinitely. In the event CP&L
decides to abandon or cease the use of a particular easement, an ARO
liability would be recorded at that time.
CP&L has previously recognized removal costs as a component of depreciation
in accordance with regulatory treatment. To the extent these amounts do not
represent SFAS No. 143 legal retirement obligations, they will be disclosed
as regulatory liabilities upon adoption of the standard.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" In April 2002, the FASB
issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections." This newly
issued statement rescinds SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt (an amendment of APB Opinion No. 30)," which required
all gains and losses from the extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of related income tax
effect. As a result, the criteria set forth by APB Opinion 30 will now be
used to classify those gains and losses. Any gain or loss on extinguishment
will be recorded in the most appropriate line item to which it relates
within net income before extraordinary items. For CP&L, any expenses or call
premiums associated with the reacquisition of debt obligations are amortized
over the remaining life of the original debt using the straight-line method
consistent with ratemaking treatment. SFAS No. 145 also amends SFAS No. 13
to require that certain lease modifications that have economic effects
similar to sale-leaseback transactions be accounted for in the same manner
as sale-leaseback transactions. In addition, SFAS No. 145 amends other
existing authoritative pronouncements to make various technical corrections,
clarify meanings or describe their applicability under changed conditions.
For the provisions related to the rescission of SFAS No. 4, SFAS No. 145 is
effective for CP&L beginning in fiscal year 2004. The remaining provisions
of SFAS No. 145 are effective for CP&L in fiscal year 2003. CP&L is
currently evaluating the effects, if any, that this statement will have on
its results of operations and financial position.
134
SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure"
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure -- an Amendment of FASB Statement
No. 123," and provided alternative methods of transition for a voluntary
change to the fair value-based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements
of SFAS No. 123, "Accounting for Stock-Based Compensation," to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. This statement requires that
companies having a year-end after December 15, 2002 follow the prescribed
format and provide the additional disclosures in their annual reports. CP&L
applies the recognition and measurement principles of APB Opinion No. 25,
"Accounting for Stock Issued to Employees" as allowed by SFAS Nos. 123 and
148, and related interpretations in accounting for its stock-based
compensation plans as described in Note 12.
The following table illustrates the effect on CP&L's net income if CP&L had
applied the fair value recognition provisions of SFAS No. 123 to the stock
option plan. The stock option plan was not in effect in 2000.
(In thousands) 2002 2001 2000
--------- --------- ---------
Net income, as reported $ 430,932 $ 364,231 $ 461,028
Deduct: Total stock option expense
determined under fair value method
for all awards, net of related tax effects 4,704 1,200 -
--------- --------- ---------
Proforma net income $ 426,228 $ 363,031 $ 461,028
========= ========= =========
FIN No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others"
In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others - an Interpretation of FASB Statements
No. 5, 57 and 107 and Rescission of FASB Interpretation No. 34" (FIN No.
45). This interpretation clarifies the disclosures to be made by a guarantor
in its interim and annual financial statements about obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of certain guarantees, a liability
for the fair value of the obligation undertaken in issuing the guarantee.
The initial recognition and initial measurement provisions of this
interpretation are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure requirements are effective
for financial statements of interim or annual periods ending after December
15, 2002. The applicable disclosures required by FIN No. 45 have been made
in Note 18B. CP&L is currently evaluating the effects, if any, that this
interpretation will have on its results of operations and financial
position.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities (previously known as special purpose entities or SPEs) and
determining whether such entities should be consolidated. Certain
disclosures are required when FIN No. 46 becomes effective if it is
reasonably possible that a company will consolidate or disclose information
about a variable interest entity when it initially applies FIN No. 46. This
interpretation must be applied immediately to variable interest entities
created or obtained after January 31, 2003. For those variable interest
entities created or obtained on or before January 31, 2003, CP&L must apply
the provisions of FIN No. 46 in the third quarter of 2003. CP&L is currently
evaluating what effects, if any, this interpretation will have on its
results of operations and financial position.
EITF Issue 02-03, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities"
In June 2002, the EITF reached a consensus on a portion of Issue 02-03,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." EITF Issue 02-03 requires all gains and losses (realized or
unrealized) on energy trading contracts to be shown net in the income
statement. CP&L's policy already required the gains and losses to be
recorded on a net basis. The net of the gains and losses are recorded in
other, net on the Consolidated Statements of Income and Comprehensive
135
Income. CP&L does not recognize a dealer profit or unrealized gain or loss
at the inception of a derivative unless the fair value of that instrument,
in its entirety, is evidenced by quoted market prices or current market
transactions.
2. Divestitures
In September 2000, Caronet, Inc. (Caronet), 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 PVHI 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 subsequent to July 1, 2000.
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 consisted primarily of the CP&L Electric segment.
The financial information for the CP&L Electric segment for the years ended
December 31, 2002, 2001 and 2000 is as follows:
Year Ended Year Ended Year Ended
(In thousands) December 31, 2002 December 31, 2001 December 31, 2000
- ----------------------------------------------------------------------------------------------------
Revenues $3,538,957 $ 3,343,720 $ 3,308,215
Depreciation and amortization 523,846 521,910 698,633
Net interest charges 211,536 241,427 221,856
Income taxes 237,362 264,078 227,705
Net income 513,115 468,328 373,764
Total segment assets 8,659,297 8,884,385 8,840,736
Capital and investment expenditures 624,202 823,952 821,991
====================================================================================================
The primary differences between the CP&L Electric segment and the CP&L
consolidated financial information relate to other non-electric operations
and elimination entries. CP&L's non-electric operations had combined revenue
of $14.9 million in 2002 and assets of $315.4 million at December 31, 2002.
Included in the 2002 operations of the telecommunications subsidiary,
Caronet, is an impairment of assets and investments of $87.4 million,
after-tax (See Note 5A). Excluding this impairment, the earnings of CP&L's
non-electric operations are negligible.
4. Related Party Transactions
CP&L participates in an internal money pool, operated by Progress Energy, 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, 2002, CP&L had $49.8 million of amounts receivable from the
money pool that are included in notes receivable from affiliated companies
on the Consolidated Balance Sheets. At December 31, 2001, CP&L had $47.9
million of amounts payable to the money pool that are included in notes
payable to affiliated companies on the Consolidated Balance Sheets. The
weighted-average interest rates associated with such money pool balances
were 2.18% and 4.47% at December 31, 2002 and 2001, respectively. CP&L
recorded $0.3 million and $1.6 million of interest income and $1.6 million
and $1.7 million of interest expense related to the money pool for 2002 and
2001, respectively. Amounts recorded for interest income and interest
expense related to the money pool for 2000 were not significant.
During 2000, the Company formed Progress Energy Service Company, LLC (PESC)
to provide specialized services, at cost, to the Company and its
subsidiaries, as approved by the U.S. Securities and Exchange Commission
(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
136
services during 2002, 2001 and 2000 amounted to $260.5 million, $173.9
million and $52.4 million, respectively. At December 31, 2002 and 2001, CP&L
had net payables of $63.2 million and $46.0 million, respectively, to PESC
that are included in payables to affiliated companies on the Consolidated
Balance Sheets. Subsidiaries of CP&L had amounts payable to PESC of $0.5
million at December 31, 2002 and amounts receivable from PESC of $13.7
million at December 31, 2001. During 2002, the Office of Public Utility
Regulation within the SEC completed an audit examination of the Company's
books and records. This examination is a standard process for all PUHCA
registrants. Based on the review, the method for allocating PESC costs to
the Company and its affiliates will change in 2003. CP&L does not anticipate
the reallocation of costs will have a material impact on the results of
operations.
During the years ended December 31, 2002, 2001 and 2000, gas sales from NCNG
to CP&L amounted to $18.2 million, $14.7 million and $5.9 million,
respectively.
In August 2002, CP&L transferred reservation payments for the manufacture of
two combustion turbines to Florida Power at CP&L's original cost of $20
million.
For the year ended December 31, 2001 and the period from July 1, 2000 to
December 31, 2000, the Consolidated Statements of Income and Comprehensive
Income contain interest income received from NCNG in the amount of $4.8
million and $4.1 million, respectively, related to a note that was
outstanding between the two companies. Prior to July 1, 2000, the interest
income received from NCNG was eliminated in consolidation. There were no
balances outstanding on the note at December 31, 2002 and 2001.
At December 31, 2001, CP&L had a payable to Progress Energy in the amount of
$40.2 million related to a short-term cash advance. This amount was repaid
during February 2002. The remaining receivables from and payables to
affiliated companies at December 31, 2002 and 2001 represent intercompany
amounts generated through CP&L's normal course of operations.
5. Impairments of Long-Lived Assets and Investments
Effective January 1, 2002, CP&L adopted SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 provides guidance
for the accounting and reporting of impairment or disposal of long-lived
assets. The statement supersedes SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of." In 2002 and 2001, CP&L recorded pre-tax asset and investment
impairments of approximately $133.3 million and $156.7 million,
respectively. There were no impairments recorded in 2000.
A. Long-Lived Assets
Due to the decline of the telecommunications industry and continued
operating losses, CP&L initiated an independent valuation study to assess
the recoverability of Caronet's long-lived assets. Based on this assessment,
CP&L recorded asset impairments of $101.2 million on a pre-tax basis and
other charges of $7.1 million on a pre-tax basis primarily related to
inventory adjustments in the third quarter of 2002. These amounts are
included in diversified business expenses on the Consolidated Statements of
Income and Comprehensive Income. This write-down constitutes a significant
reduction in the book value of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, while using market approaches as supporting
information.
B. Investments
CP&L continually reviews its investments to determine whether a decline in
fair value below the cost basis is other than temporary. Effective June 28,
2000, Caronet entered into an agreement with Bain Capital whereby it
contributed the net assets used in its application service provider business
to a newly formed company, named Interpath Communications, Inc. (Interpath),
in exchange for a 35% ownership interest (15% voting interest) in Interpath.
137
CP&L obtained a valuation study to assess its investment in Interpath based
on current valuations in the technology sector during 2001. As a result,
CP&L recorded investment impairments for other-than-temporary declines in
the fair value of its investment in Interpath. The investment write-down was
$156.7 million on a pre-tax basis for the year ended December 31, 2001. In
May 2002, Interpath merged with a third party. Pursuant to the terms of the
merger agreement and due to additional funds being contributed by Bain
Capital, CP&L's ownership was diluted to approximately 19% of Interpath (7%
voting interest). As a result, CP&L reviewed the Interpath investment for
impairment and wrote off the remaining amount of its cost-basis investment
in Interpath, recording a pre-tax impairment of $25.0 million in the third
quarter of 2002. In the fourth quarter of 2002, CP&L sold its remaining
interest in Interpath for a nominal amount.
6. Debt and Credit Facilities
A. Lines of Credit
At December 31, 2002, CP&L had committed lines of credit totaling $570
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 Total
----------------------------------------------------------------------
364-Day (expiring 7/30/03) $ 285
3-Year (expiring 7/31/05) 285
-----------------
$ 570
=================
There were no loans outstanding under these facilities at December 31, 2002.
As of December 31, 2002 and 2001, CP&L had $437.8 million and $260.5
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, 2002 and 2001 were
1.74% and 3.07%, respectively. CP&L no longer reclassifies commercial paper
to long term debt. Certain amounts for 2001 have been reclassified to
conform to 2002 presentation, with no effect on previously reported net
income or common stock equity.
The combined aggregate maturities of long-term debt for 2004, 2005 and 2007
are approximately $300 million, $307 million and $200 million, respectively.
There are no maturities of debt scheduled for 2003 or 2006.
B. Covenants and Default Provisions
Financial Covenants
CP&L's credit line contains various terms and conditions that could affect
CP&L's ability to borrow under these facilities. These include a maximum
debt to total capital ratio, a material adverse change clause and a
cross-default provision.
CP&L's credit line requires a maximum total debt to total capital ratio of
65%. Indebtedness as defined by the bank agreement includes certain letters
of credit and guarantees which are not recorded on the Consolidated Balance
Sheets. As of December 31, 2002, CP&L's total debt to total capital ratio
was 52.7%.
Material adverse change clause
The credit facility of CP&L includes a provision under which lenders could
refuse to advance funds in the event of a material adverse change in the
borrower's financial condition.
Default provisions
CP&L's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. CP&L's cross-default provisions only
apply to defaults of indebtedness by CP&L and its subsidiaries,
respectively, and not to other affiliates of CP&L. In addition, the credit
lines of the Company include a similar provision. Progress Energy's
cross-default provisions only apply to defaults of indebtedness by Progress
Energy and its significant subsidiaries, which includes CP&L.
138
The lenders may accelerate payment of any outstanding debt if cross-default
provisions are triggered. Any such acceleration would cause a material
adverse change in the respective company's financial condition. Certain
agreements underlying CP&L's indebtedness also limit CP&L's ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
Other restrictions
CP&L's mortgage indenture provides that so long as any first mortgage bonds
are outstanding, cash dividends and distributions on CP&L's common stock,
and purchases of CP&L's common stock, are restricted to aggregate net income
available for CP&L, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2002, none of
CP&L's retained earnings of $1.3 billion was restricted.
Refer to Note 11 for additional dividend restrictions related to CP&L's
Articles of Incorporation.
C. Secured Obligations
CP&L's first mortgage bonds are secured by their respective mortgage
indentures. CP&L's mortgage constitutes a first lien on substantially all of
its fixed properties, subject to certain permitted encumbrances and
exceptions. The CP&L mortgage also constitutes a lien on subsequently
acquired property. At December 31, 2002, CP&L had approximately $2.3 billion
in first mortgage bonds outstanding including those related to pollution
control obligations. The CP&L mortgage allows the issuance of additional
mortgage bonds upon the satisfaction of certain conditions.
D. Hedging Activities
CP&L uses interest rate derivatives to adjust the fixed and variable rate
components of its debt portfolio and to hedge cash flow risk of fixed rate
debt to be issued in the future. See discussion of risk management and
derivative transactions at Note 10.
7. 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 $9.5 million, $21.7 million and $13.8
million for 2002, 2001 and 2000, respectively.
Assets recorded under capital leases consist of (in thousands):
2002 2001
-------- --------
Buildings $ 27,633 $ 27,626
Less: Accumulated amortization (9,329) (8,752)
-------- --------
$ 18,304 $ 18,874
======== ========
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases as of
December 31, 2002 are (in thousands):
Capital Operating
Leases Leases
2003 $ 2,189 $ 9,557
2004 2,189 7,695
2005 2,189 6,302
2006 2,189 3,835
2007 2,189 3,829
Thereafter 20,274 13,142
------- --------
$31,219 $44,360
=======
Less amount representing imputed interest (12,214)
--------
Present value of net minimum lease payments
under capital leases $19,005
=======
139
CP&L is the lessor of electric poles and streetlights. Rents received are
contingent upon usage and totaled $28.4 million, $30.9 million and $23.3
million for 2002, 2001 and 2000, respectively.
8. 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, 2002 and 2001, there were miscellaneous investments consisting
primarily of investments in company-owned life insurance and other benefit
plan assets with carrying amounts totaling approximately $54.2 million and
$50.0 million, respectively, included in miscellaneous other property and
investments. The carrying amount of these investments approximates fair
value due to the short maturity of certain instruments. Other instruments
are presented at fair value in accordance with GAAP. The carrying amount of
CP&L's long-term debt, including current maturities, was $3.1 billion at
December 31, 2002 and $3.3 billion at December 31, 2001. The estimated fair
value of this debt, as obtained from quoted market prices for the same or
similar issues, was $3.3 billion and $3.4 billion at December 31, 2002 and
2001, 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.
9. 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 GAAP for
nonregulated 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 was provided. Additionally, these
factors could result in an impairment of utility plant assets as determined
pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (See Note 5).
At December 31, 2002 and 2001, the balances of CP&L's regulatory assets
(liabilities) were as follows (in thousands):
2002 2001
--------- ---------
Deferred fuel (included in current assets) $ 146,015 $ 131,505
--------- ---------
Income taxes recoverable through future rates 197,402 208,702
Harris Plant deferred costs 16,888 32,476
Loss on reacquired debt 13,223 5,801
Deferred DOE enrichment facilities-related costs 24,570 30,571
--------- ---------
Total long-term regulatory assets 252,083 277,550
--------- ---------
Emission allowance gains (7,774) (7,494)
--------- ---------
Net regulatory assets $ 390,324 $ 401,561
========= =========
Except for portions of deferred fuel, all regulatory assets earn a return or
the cash has not yet been expended, in which case, the assets are offset by
liabilities that do not incur a carrying cost.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of CP&L's
nuclear generating assets beginning January 1, 2000, and continuing through
2004. On June 14, 2002, the NCUC approved modification of CP&L's ongoing
accelerated cost recovery of its nuclear generating assets. Effective
January 1, 2003, the NCUC will no longer require a minimum annual
depreciation. The aggregate minimum and maximum amounts of accelerated
140
depreciation, $415 million and $585 million respectively, are unchanged from
the original NCUC order. The date by which the minimum amount must be
depreciated was extended from December 31, 2004 to December 31, 2009. On
October 29, 2002, the SCPSC approved similar modifications. The order was
effective November 1, 2002, and the aggregate minimum and maximum of $115
million and $165 million established for accelerated cost recovery by the
SCPSC is unchanged. The accelerated cost recovery of these assets resulted
in additional depreciation expense of approximately $53 million, $75 million
and $275 million in 2002, 2001 and 2000, respectively. Recovering the costs
of its nuclear generating assets on an accelerated basis will better
position CP&L for the uncertainties associated with potential restructuring
of the electric utility industry. Total accelerated depreciation recorded
through December 31, 2002 was $326 million for the North Carolina
jurisdiction and $77 million for the South Carolina jurisdiction.
On May 30, 2001, the NCUC issued an order allowing CP&L to offset a portion
of its annual accelerated cost recovery of nuclear generating assets by the
amount of sulfur dioxide (SO2) emission allowance expense. CP&L offset
accelerated depreciation expense against emission allowance expense by
approximately $5.8 million in 2002. CP&L did not offset accelerated
depreciation expense against emission allowance expense in 2001. 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. In North Carolina, legislation enacted pursuant to the North
Carolina Clean Air Act in June of 2002 freezes CP&L's base rates for five
years, subject to certain conditions. See Note 18D for further discussion of
this matter.
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 $3.0
million in 2002, $4.5 million in 2003, $6.0 million in 2004 and $6.0 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.
10. Risk Management Activities and Derivatives Transactions
Under its risk management policy, CP&L may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments
contain credit risk if the counterparty fails to perform under the contract.
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 Contracts - General
Most of CP&L's commodity contracts either are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
B. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity forward contracts, are entered
into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations
in commodity prices, these instruments are not designated as hedges for
accounting purposes and are monitored consistent with trading positions.
CP&L manages open positions with strict policies that limit its exposure to
market risk and require daily reporting to management of potential financial
exposures. Gains and losses from such contracts were not material during
2002, 2001 or 2000, and CP&L did not have material outstanding positions in
such contracts at December 31, 2002 or 2001.
C. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
CP&L manages its interest rate exposure in part by maintaining its
variable-rate and fixed-rate exposures within defined limits. In addition,
CP&L also enters into financial derivative instruments including, but not
limited to, interest rate swaps and lock agreements to manage and mitigate
interest rate risk exposure.
141
CP&L uses cash flow hedging strategies to hedge variable interest rates on
long-term debt and to hedge interest rates with regard to future fixed-rate
debt issuances. At December 31, 2002, CP&L held no interest rate cash flow
hedges. As of December 31, 2002, $0.8 million of net after-tax deferred
losses in accumulated other comprehensive income, related to terminated
hedges, will be reclassified to earnings during the next 12 months as the
hedged interest payments occur. At December 31, 2001, CP&L held interest
rate cash flow hedges with notional amounts totaling $500.0 million and a
total fair value of $18.5 million liability position.
CP&L uses fair value hedging strategies to manage its exposure to fixed
interest rates on long-term debt. At December 31, 2002 and 2001, CP&L had no
open interest rate fair value hedges.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
11. Capitalization
As of December 31, 2002, CP&L was authorized to issue up to 200,000,000
shares of common stock. 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, 2002,
there were no significant restrictions on the use of retained earnings.
CP&L's Articles of Incorporation provide that cash dividends on common stock
shall be limited to 75% of net income available for dividends if common
stock equity falls below 25% of total capitalization, and to 50% if common
stock equity falls below 20%. On December 31, 2002, CP&L's common stock
equity was approximately 46.6% of total capitalization.
Refer to Note 6 for additional dividend restrictions related to CP&L's
mortgage.
12. Stock-Based Compensation Plans
CP&L accounts for stock-based compensation in accordance with the provisions
of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees," and related interpretations as permitted under SFAS No. 123,
"Accounting for Stock-Based Compensation."
A. Employee Stock Ownership Plan
Progress Energy sponsors the Progress Energy 401(k) Savings and Stock
Ownership Plan (401(k)) for which substantially all full-time non-bargaining
unit employees and certain part-time non-bargaining employees within
participating subsidiaries are eligible. CP&L is a participating subsidiary
of the 401(k), which has matching and incentive goal features, encourages
systematic savings by employees and provides a method of acquiring Progress
Energy common stock and other diverse investments. The 401(k), as amended in
1989, is an Employee Stock Ownership Plan (ESOP) that can enter into
acquisition loans to acquire Progress Energy common stock to satisfy 401(k)
common stock needs. Qualification as an ESOP did not change the level of
benefits received by employees under the 401(k). Common stock acquired with
the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense
account. The common stock is released from the suspense account and made
available for allocation to participants as the ESOP loan is repaid. Such
allocations are used to partially meet common stock needs related to
Progress Energy matching and incentive contributions and/or reinvested
dividends.
There were 4,616,400 and 5,199,388 ESOP suspense shares at December 31, 2002
and 2001, respectively, with a fair value of $200.1 million and $234.1
million, respectively. CP&L's matching and incentive goal compensation cost
under the 401(k) is determined based on matching percentages and incentive
goal attainment as defined in the plan. Such compensation cost is allocated
to participants' accounts in the form of Progress Energy common stock, with
the number of shares determined by dividing compensation cost by the common
stock market value at the time of allocation. The 401(k) common stock share
needs are met with open market purchases, with shares released from the ESOP
142
suspense account and with newly issued shares. CP&L's matching and incentive
cost met with shares released from the suspense account totaled
approximately $13.3 million, $12.7 million and $14.7 million for the years
ended December 31, 2002, 2001 and 2000, respectively. CP&L has a long-term
note receivable from the 401(k) Trustee related to the purchase of common
stock from CP&L in 1989 (now Progress Energy common stock). The balance of
the note receivable from the 401(k) Trustee is included in the determination
of unearned ESOP common stock, which reduces common stock equity. Interest
income on the note receivable is not recognized for financial statement
purposes.
B. Stock Option Agreements
Pursuant to Progress Energy's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002, Progress Energy
may grant options to purchase shares of common stock to directors, officers
and eligible employees. During 2002 and 2001, approximately 2.9 million and
2.4 million common stock options were granted. Of these amounts,
approximately 1.2 million and 1.0 million were granted to officers and
eligible employees of CP&L in 2002 and 2001, respectively. No compensation
expense was recognized under the provisions of Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. For purposes of the proforma disclosures required by SFAS
No. 123, the estimated fair value of the options is amortized to expense
over the options' vesting period. Under SFAS No. 148, compensation expense
would have been $7.9 million and $2.0 million in 2002 and 2001,
respectively.
C. Other Stock-Based Compensation Plans
Progress Energy has additional compensation plans for officers and key
employees that are stock-based in whole or in part. CP&L participates in
these plans. The two primary active stock-based compensation programs are
the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards
program (RSA), both of which were established pursuant to Progress Energy's
1997 Equity Incentive Plan and were continued under the 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees are granted
performance shares on an annual basis that vest over a three-year
consecutive period. Each performance share has a value that is equal to, and
changes with, the value of a share of Progress Energy's common stock, and
dividend equivalents are accrued on, and reinvested in, the performance
shares. The PSSP has two equally weighted performance measures, both of
which are based on Progress Energy's results as compared to a peer group of
utilities. Compensation expense is recognized over the vesting period based
on the expected ultimate cash payout and is reduced by any forfeitures.
The RSA allows the Company to grant shares of restricted common stock to
officers and key employees of the Company. The restricted shares generally
vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period and is
reduced by any forfeitures.
The total amount expensed by CP&L for other stock-based compensation plans
was $6.9 million, $5.9 million and $9.8 million in 2002, 2001 and 2000,
respectively.
13. Postretirement Benefit Plans
CP&L and some of its subsidiaries have a non-contributory defined benefit
retirement (pension) plan for substantially all eligible 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):
2002 2001 2000
---------- ---------- ---------
Expected return on plan assets $ (72,876) $ (71,955) $(76,508)
Service cost 19,343 16,960 18,804
Interest cost 50,717 46,729 49,821
Amortization of transition obligation 97 116 121
Amortization of prior service (benefit) cost 195 (1,230) (1,282)
Amortization of actuarial (gain) loss 440 (4,352) (5,607)
---------- ---------- ----------
Net periodic pension benefit $ (2,084) $ (13,732) $ (14,651)
========== ========== ==========
143
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 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):
2002 2001
---------- ----------
Projected benefit obligation at January 1 $ 681,989 $ 638,067
Interest cost 50,717 46,729
Service cost 19,343 16,960
Benefit payments (46,059) (43,636)
Actuarial loss 96,929 5,621
Transfers (635) -
Plan amendments - 18,248
----------- ----------
Projected benefit obligation at December 31 $ 802,284 $ 681,989
Fair value of plan assets at December 31 574,367 716,799
----------- ----------
Funded status $ (227,917) $ 34,810
Unrecognized transition obligation 241 338
Unrecognized prior service cost 3,928 4,123
Unrecognized actuarial (gain) loss 237,864 (28,416)
Minimum pension liability adjustment (124,867) -
----------- ----------
Prepaid (accrued) pension cost at December 31, net $ (110,751) $ 10,855
=========== ==========
The accrued pension cost at December 31, 2002 is included in other
liabilities and deferred credits in the accompanying Consolidated Balance
Sheets. The net prepaid pension cost of $10.9 million at December 31, 2001
is included in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $25.7 million, which is included in other assets and
deferred debits, and accrued benefit cost of $14.8 million, which is
included in other liabilities and deferred credits. The defined benefit
plans with accumulated benefit obligations in excess of plan assets had
projected benefit obligations totaling $802.3 million and $16.0 million at
December 31, 2002 and 2001, respectively. Those plans had accumulated
benefit obligations totaling $685.1 million and $15.4 million, respectively,
plan assets totaling $574.4 million at December 31, 2002, and no plan assets
at December 31, 2001.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $124.9 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $4.2 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, and a pre-tax charge of $120.7
million to accumulated other comprehensive loss, a component of common stock
equity.
144
Reconciliations of the fair value of pension plan assets are (in thousands):
2002 2001
---------- ----------
Fair value of plan assets at January 1 $ 716,799 $ 777,435
Actual return on plan assets (96,915) (18,160)
Benefit payments (46,059) (43,636)
Employer contributions 1,177 1,160
Transfers (635) -
---------- ----------
Fair value of plan assets at December 31 $ 574,367 $ 716,799
========== ==========
The weighted-average discount rate used to measure the pension obligation
was 6.6% in 2002 and 7.5% in 2001. The assumed rate of increase in future
compensation used to measure the pension obligation was 4.0% in 2002 and
2001. The expected long-term rate of return on pension plan assets used in
determining the net periodic pension cost was 9.25% in 2002, 2001 and 2000.
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):
2002 2001 2000
--------- --------- --------
Expected return on plan assets $ (3,532) $ (3,676) $(3,852)
Service cost 6,301 7,374 8,868
Interest cost 14,308 14,191 13,677
Amortization of prior service cost - - 54
Amortization of transition obligation 2,708 4,298 5,551
Amortization of actuarial gain (851) (531) (779)
--------- --------- --------
Net periodic OPEB cost $ 18,934 $ 21,656 $23,519
========= ========= ========
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):
2002 2001
---------- ----------
OPEB obligation at January 1 $ 192,088 $ 187,563
Interest cost 14,308 14,191
Service cost 6,301 7,374
Benefit payments (9,003) (7,137)
Actuarial loss 30,222 19,242
Transfers (179) -
Plan amendment - (29,145)
---------- ----------
OPEB obligation at December 31 $ 233,737 $ 192,088
Fair value of plan assets at December 31 32,890 38,182
---------- ----------
Funded status $(200,847) $(153,906)
Unrecognized transition obligation 25,555 28,263
Unrecognized actuarial (gain) loss 38,434 (1,284)
--------- ----------
Accrued OPEB cost at December 31 $(136,858) $(126,927)
========== ==========
The accrued OPEB cost is included in other liabilities and deferred credits
in the accompanying Consolidated Balance Sheets. The plan amendment in 2001,
which resulted in a 15.5% reduction in the OPEB liability, implemented a cap
on CP&L's contributions toward future medical cost increases.
145
Reconciliations of the fair value of OPEB plan assets are (in thousands):
2002 2001
--------- ---------
Fair value of plan assets at January 1 $ 38,182 $ 39,048
Actual return on plan assets (5,292) (866)
Employer contributions 9,003 7,137
Benefits paid (9,003) (7,137)
--------- ---------
Fair value of plan assets at December 31 $ 32,890 $ 38,182
========= =========
The assumptions used to measure the OPEB obligation are:
2002 2001
------ ------
Weighted-average discount rate 6.60% 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% 7.50%
Ultimate medical cost trend rate 5.25% 5.00%
Year ultimate medical cost trend rate is achieved 2009 2008
The expected weighted-average long-term rate of return on plan assets used
in determining the net periodic OPEB cost was 9.25% in 2002, 2001 and 2000.
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 2002 would increase by $3.2 million, and
the OPEB obligation at December 31, 2002, would increase by $23.1 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 2002
would decrease by $2.8 million and the OPEB obligation at December 31, 2002,
would decrease by $21.0 million.
14. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. 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):
2002 2001
Accelerated depreciation and property
cost differences $ 1,313,604 $ 1,359,083
Minimum pension liability (47,317) -
Deferred costs, net (9,771) 42,688
Income tax credit carryforward (10,384) (640)
Valuation allowance 8,167 3,767
Miscellaneous other temporary differences, net (8,522) (20,100)
------------ ------------
Net accumulated deferred income tax liability $ 1,245,777 $ 1,384,798
============ ============
Total deferred income tax liabilities were $1.952 billion and $2.046 billion
at December 31, 2002 and 2001, respectively. Total deferred income tax
assets were $706 million and $661 million at December 31, 2002 and 2001,
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.
CP&L had a valuation allowance of $3.8 million at December 31, 2001 and
established additional valuation allowances of $4.4 million during 2002 due
to the uncertainty of realizing certain future state income tax benefits.
CP&L believes that it is more likely than not that the results of future
operations will generate sufficient taxable income to allow for the
utilization of the remaining deferred tax assets.
146
Reconciliations of CP&L's effective income tax rate to the statutory federal
income tax rate are:
2002 2001 2000
---------- ---------- ----------
Effective income tax rate 32.5% 38.0% 38.6%
State income taxes, net of federal benefit (3.1) (3.2) (4.5)
Investment tax credit amortization 1.9 2.5 3.7
Progress Energy tax benefit allocation (Note 1L) 5.0 - -
Other differences, net (1.3) (2.3) (2.8)
---------- ---------- ----------
Statutory federal income tax rate 35.0% 35.0% 35.0%
========== ========= ==========
The provisions for income tax expense are comprised of (in thousands):
2002 2001 2000
---------- ---------- ----------
Income tax expense (credit):
Current - federal $ 265,231 $ 348,921 $ 328,982
state 36,039 39,135 62,228
Deferred - federal (75,784) (140,486) (71,929)
state (6,132) (9,409) (11,625)
Investment tax credit (11,994) (14,928) (17,385)
---------- ---------- ----------
Total income tax expense $ 207,360 $ 223,233 $ 290,271
========== ========== ==========
15. Joint Ownership of Generating Facilities
CP&L holds undivided ownership interests in certain jointly owned generating
facilities. 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, 2002 and 2001
(dollars in thousands):
2002
Company Construction
Megawatt Ownership Plant Accumulated Accumulated Work in
Facility Capability Interest Investment Depreciation Decommissioning Progress
-------- ---------- -------- ---------- ------------ --------------- --------
Mayo Plant 745 83.83% $ 464,202 $ 239,971 $ - $14,089
Harris Plant 900 83.83% 3,159,946 1,432,245 95,643 6,117
Brunswick Plant 1,683 81.67% 1,476,534 867,530 339,521 26,436
Roxboro Unit No. 4 700 87.06% 316,491 138,408 - 8,079
2001
Company Construction
Megawatt Ownership Plant Accumulated Accumulated Work in
Facility Capability Interest Investment Depreciation Decommissioning Progress
-------- ---------- -------- ---------- ------------ --------------- --------
Mayo Plant 745 83.83% $ 460,026 $ 230,630 $ - $ 7,116
Harris Plant 860 83.83% 3,154,183 1,321,694 93,637 14,416
Brunswick Plant 1,631 81.67% 1,427,842 828,480 339,945 41,455
Roxboro Unit No. 4 700 87.06% 309,032 126,007 - 7,881
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Harris Plant.
147
16. Other Income and Other Expense
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items as
discussed below. The components of other, net as shown on the Consolidated
Statements of Income and Comprehensive Income for years ended December 31,
are as follows (in thousands):
2002 2001 2000
--------- --------- ---------
Other income
Net financial trading gain (loss) $ (1,942) $ 3,262 $ 15,603
Net energy purchased for resale gain 1,248 3,074 2,132
Nonregulated energy and delivery services income 11,816 11,528 23,996
Investment gains 22,218 2,500 6,722
AFUDC equity 6,432 8,764 14,502
Other 19,891 12,963 11,594
--------- --------- ---------
Total other income $ 59,663 $ 42,091 $ 74,549
--------- --------- ---------
Other expense
Nonregulated energy and delivery services expenses 13,625 21,352 23,554
Donations 7,594 11,045 9,219
Investment losses 14,389 4,365 6,672
Other 11,298 9,484 18,015
--------- --------- --------
Total other expense $ 46,906 $ 46,246 $ 57,460
--------- --------- ---------
Other, net $ 12,757 $(4,155) $ 17,089
========= ========= =========
Net financial trading gain (loss) represents non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include power
protection services and mass market programs (surge protection, appliance
services and area light sales) and delivery, transmission and substation
work for other utilities.
17. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows (in
thousands):
2002 2001
---------- ---------
Loss on cash flow hedges $ (9,379) $ (7,046)
Minimum pension liability adjustments (73,390) -
---------- ---------
Total accumulated other comprehensive loss $ (82,769) $ (7,046)
========== =========
18. Commitments and Contingencies
A. Fuel and Purchased Power
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between CP&L and Power Agency, CP&L is obligated to purchase a percentage of
Power Agency's ownership capacity of, and energy from, the Harris Plant. In
1993, CP&L and Power Agency entered into an agreement to restructure
portions of their contracts covering power supplies and interests in jointly
owned units. Under the terms of the 1993 agreement, CP&L increased the
amount of capacity and energy purchased from Power Agency's ownership
interest in the Harris Plant, and the buyback period was extended six years
through 2007. The estimated minimum annual payments for these purchases,
which reflect capacity costs, total approximately $32 million. These
contractual purchases totaled $35.9 million, $33.3 million and $33.9 million
for 2002, 2001 and 2000, 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, 2002 and 2001, CP&L had deferred
purchased capacity costs, including carrying costs accrued on the deferred
balances, of $16.9 million and $32.5 million, respectively. Increased
purchases (which are not being deferred for future recovery) resulting from
the 1993 agreement with Power Agency were approximately $32.2 million, $28.6
million and $26.0 million for 2002, 2001 and 2000, respectively.
148
CP&L has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 megawatts
of capacity through 2009 with estimated minimum annual payments of
approximately $31 million, representing capital-related capacity costs.
Total purchases (including transmission use charges) under the Rockport
agreement amounted to $58.6 million, $62.8 million and $61.0 million for
2002, 2001 and 2000, respectively.
Effective June 1, 2001, CP&L executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 megawatts of
capacity through 2021 with an original minimum annual payment of
approximately $16 million, primarily representing capital-related capacity
costs. A separate long-term agreement for additional power from Broad River
commenced June 1, 2002. This agreement provided for the additional purchase
of approximately 300 megawatts of capacity through 2022 with an original
minimum annual payment of approximately $16 million representing
capital-related capacity costs. Total purchases under the Broad River
agreements amounted to $37.7 million and $21.2 million in 2002 and 2001,
respectively.
CP&L has various pay-for-performance purchased power contracts with certain
cogenerators (qualifying facilities) for approximately 300 megawatts of
capacity expiring at various times through 2009. These purchased power
contracts generally provide for capacity and energy payments. Payments for
both capacity and energy are contingent upon the qualifying facilities'
ability to generate. Payments made under these contracts were $144.5 million
in 2002, $145.1 million in 2001 and $168.4 million in 2000.
CP&L has entered into various long-term contracts for coal, gas and oil
requirements of its generating plants. Total payments under these
commitments were $694.0 million, $675.2 million and $558.9 million in 2002,
2001 and 2000, respectively. Estimated annual payments for firm commitments
of fuel purchases and transportation costs under these contracts are
approximately $499.7 million, $434.0 million, $351.1 million, $312.1 million
and $199.0 million for 2003 through 2007, respectively.
B. Guarantees
As a part of normal business, CP&L enters into various agreements providing
financial or performance assessments to third parties. Such agreements
include, for example, guarantees, stand-by letters of credit and surety
bonds. These agreements are entered into primarily to support or enhance the
creditworthiness otherwise attributed to a subsidiary on a stand-alone
basis, thereby facilitating the extension of sufficient credit to accomplish
the subsidiaries' intended commercial purposes.
At December 31, 2002 and 2001, outstanding guarantees consisted of the
following (in millions):
December 31, 2002 December 31, 2001
----------------- -----------------
Standby letters of credit $ 4.7 $ 4.9
Surety bonds 0.6 2.0
----------------- -----------------
Total $ 5.3 $ 6.9
================= =================
Stand-by Letters of Credit
CP&L has issued stand-by letters of credit to financial institutions for the
benefit of third parties that have extended credit to CP&L and certain
subsidiaries. These letters of credit have been issued primarily for the
purpose of supporting payments of trade payables, securing performance under
contracts and interest payments on outstanding debt obligations. If a
subsidiary does not pay amounts when due under a covered contract, the
counterparty may present its claim for payment to the financial institution,
which will in turn request payment from CP&L. Any amounts owed by its
subsidiaries are reflected in the Consolidated Balance Sheets.
Surety Bonds
At December 31, 2002, CP&L had $0.6 million in surety bonds purchased
primarily for purposes such as providing worker compensation coverage and
obtaining licenses, permits and rights-of-way. To the extent liabilities are
incurred, as a result of the activities covered by the surety bonds, such
liabilities are included in the Consolidated Balance Sheets.
149
As of December 31, 2002, management does not believe conditions are likely
for performance under these agreements.
C. 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 $2.0 billion on
the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. CP&L is insured thereunder, following a
twelve-week deductible period, for 52 weeks in the amount of $3.5 million
per week at each of the nuclear units. An additional 110 weeks of coverage
is provided at 80% of the above weekly amount. For the current policy
period, CP&L is subject to retrospective premium assessments of up to
approximately $24.1 million with respect to the primary coverage, $25.7
million with respect to the decontamination, decommissioning and excess
property coverage, and $17.4 million for the incremental replacement power
costs coverage, in the event covered losses at insured facilities exceed
premiums, reserves, reinsurance and other NEIL resources. Pursuant to
regulations of the Nuclear Regulatory Commission (NRC), 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 decontaminate, 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 $9.55
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear power plants, CP&L, as
an owner of nuclear units, can be assessed for a portion of any third-party
liability claims arising from an accident at any commercial nuclear power
plant in the United States. In the event that public liability claims from
an insured nuclear incident exceed $300 million (currently available through
commercial insurers), CP&L would be subject to pro rata assessments of up to
$88.1 million for each reactor owned per occurrence. Payment of such
assessments would be made over time as necessary to limit the payment in any
one year to no more than $10 million per reactor owned. Congress is expected
to approve revisions to the Price Anderson Act in the first quarter of 2003,
that will include increased limits and assessments per reactor owned. The
final outcome of this matter cannot be predicted at this time.
There have been recent revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were
multiple terrorism losses occurring within one year after the first loss
from terrorism, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant. If
terrorism losses occurred beyond the one-year period, a new set of limits
and resources would apply. For nuclear liability claims arising out of
terrorist acts, the primary level available through commercial insurers is
now subject to an industry aggregate limit of $300 million. The second level
of coverage obtained through the assessments discussed above would continue
to apply to losses exceeding $300 million and would provide coverage in
excess of any diminished primary limits due to the terrorist acts aggregate.
CP&L self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters.
D. Claims and Uncertainties
1. CP&L is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
150
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
CP&L has some connection. In this regard, CP&L and other potentially
responsible parties, are participating in investigating and, if necessary,
remediating former MGP sites with several regulatory agencies, including,
but not limited to, the U.S. Environmental Protection Agency (EPA) and the
North Carolina Department of Environment and Natural Resources, Division of
Waste Management (DWM). In addition, 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.
There are 12 former MGP sites and 14 other sites associated with CP&L that
have required or are anticipated to require investigation and/or remediation
costs. CP&L received insurance proceeds to address costs associated with
CP&L environmental liabilities related to its involvement with MGP sites.
All eligible expenses related to these are charged against a specific fund
containing these proceeds. As of December 31, 2002, approximately $8.0
million remains in this centralized fund with a related accrual of $8.0
million recorded for the associated expenses of environmental issues. As
CP&L's share of costs for investigating and remediating these sites become
known, the fund is assessed to determine if additional accruals will be
required. CP&L does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what remains in the
environmental insurance recovery fund. This is due to the fact that the
sites are at different stages: investigation has not begun at 15 sites,
investigation has begun but remediation cannot be estimated at seven sites
and four sites have begun remediation. CP&L measures its liability for these
sites based on available evidence including its experience in investigating
and remediating environmentally impaired sites. The process often involves
assessing and developing cost-sharing arrangements with other potentially
responsible parties. Once the environmental insurance recovery fund is
depleted, CP&L will accrue costs for the sites to the extent its liability
is probable and the costs can be reasonably estimated. Presently, CP&L
cannot determine the total costs that may be incurred in connection with the
remediation of all sites. According to current information, these future
costs at the CP&L sites are not expected to be material to CP&L's financial
condition or results of operations. A rollforward of the balance in this
fund is not provided due to the immateriality of this activity in the
periods presented.
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.
CP&L is also currently in the process of assessing potential costs and
exposures at other environmentally impaired sites. As the assessments are
developed and analyzed, CP&L will accrue costs for the sites to the extent
the costs are probable and can be reasonably estimated.
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for nitrogen oxides, sulfur dioxide, carbon
dioxide and mercury. Some of these proposals establish nation-wide caps and
emission rates over an extended period of time. This national
multi-pollutant approach to air pollution control could involve significant
capital costs which could be material to CP&L's consolidated financial
position or results of operations. Some companies may seek recovery of the
related cost through rate adjustments or similar mechanisms. Control
equipment that will be installed on North Carolina fossil generating
facilities as part of the North Carolina legislation discussed below may
address some of the issues outlined above. However, CP&L cannot predict the
outcome of this matter.
151
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
CP&L was asked to provide information to the EPA as part of this initiative
and cooperated in providing the requested information. The EPA initiated
civil enforcement actions against other unaffiliated utilities as part of
this initiative. Some of these actions resulted in settlement agreements
calling for expenditures, ranging from $1.0 billion to $1.4 billion. A
utility that was not subject to a civil enforcement action settled its New
Source Review issues with the EPA for $300 million. These settlement
agreements have generally called for expenditures to be made over extended
time periods, and some of the companies may seek recovery of the related
cost through rate adjustments or similar mechanisms. CP&L cannot predict the
outcome of this matter.
In 1998, the EPA published a final rule addressing the regional transport of
ozone. This rule is commonly known as the NOx SIP Call. The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, to further reduce nitrogen oxide emissions in order to attain a
pre-set state NOx emission levels by May 31, 2004. CP&L is currently
installing controls necessary to comply with the rule. Capital expenditures
needed to meet these measures in North and South Carolina could reach
approximately $370 million, which has not been adjusted for inflation.
Increased operation and maintenance costs relating to the NOx SIP Call are
not expected to be material to 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. Designation of areas that do not
attain the standard is proceeding, and further litigation and rulemaking on
this and other aspects of the standard are anticipated. North Carolina
adopted the federal eight-hour ozone standard and is proceeding with the
implementation process. North Carolina has promulgated final regulations,
which will require CP&L to install nitrogen oxide controls under the State's
eight-hour standard. The costs of those controls are included in the $370
million cost estimate set forth above. However, further technical analysis
and rulemaking may result in a requirement for additional controls at some
units. CP&L cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated required certain sources
to make reductions in nitrogen oxide emissions by May 1, 2003. The final
rule also includes a set of regulations that affect nitrogen oxide emissions
from sources included in the petitions. The North Carolina coal-fired
electric generating plants are included in these petitions. Acceptable state
plans under the NOx SIP Call can be approved in lieu of the final rules the
EPA approved as part of the 126 petitions. CP&L, other utilities, trade
organizations and other states participated in litigation challenging the
EPA's action. On May 15, 2001, the District of Columbia Circuit Court of
Appeals ruled in favor of the EPA, which will require North Carolina to make
reductions in nitrogen oxide emissions by May 1, 2003. However, the Court in
its May 15th decision rejected the EPA's methodology for estimating the
future growth factors the EPA used in calculating the emissions limits for
utilities. In August 2001, the Court granted a request by CP&L and other
utilities to delay the implementation of the 126 Rule for electric
generating units pending resolution by the EPA of the growth factor issue.
The Court's order tolls the three-year compliance period (originally set to
end on May 1, 2003) for electric generating units as of May 15, 2001. On
April 30, 2002, the EPA published a final rule harmonizing the dates for the
Section 126 Rule and the NOx SIP Call. In addition, the EPA determined in
this rule that the future growth factor estimation methodology was
appropriate. The new compliance date for all affected sources is now May 31,
2004, rather than May 1, 2003. The EPA has approved North Carolina's NOx SIP
Call rule and has indicated it will rescind the Section 126 rule in a future
rule making. CP&L expects a favorable outcome of this matter.
On June 20, 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of nitrogen oxide and
sulfur dioxide from coal-fired power plants. CP&L expects its capital costs
to meet these emission targets will be approximately $813 million by 2013.
CP&L currently has approximately 5,100 MW of coal-fired generation in North
Carolina that is affected by this legislation. The legislation requires the
emissions reductions to be completed in phases by 2013, and applies to each
utility's total system rather than setting requirements for individual power
plants. The legislation also freezes the utilities' base rates for five
years unless there are extraordinary events beyond the control of the
utilities or unless the utilities persistently earn a return substantially
in excess of the rate of return established and found reasonable by the NCUC
in the utilities' last general rate case. Further, the legislation allows
the utilities to recover from their retail customers the projected capital
costs during the first seven years of the 10-year compliance period
beginning on January 1, 2003. The utilities must recover at least 70% of
their projected capital costs during the five-year rate freeze period.
Pursuant to the new law, CP&L entered into an agreement with the state of
North Carolina to transfer to the state all future emissions allowances it
generates from over-complying with the new federal emission limits when
these units are completed. The new law also requires the state to undertake
a study of mercury and carbon dioxide emissions in North Carolina. CP&L
cannot predict the future regulatory interpretation, implementation or
impact of this new law.
152
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol,
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush administration
favors voluntary programs. Reductions in carbon dioxide emissions to the
levels specified by the Kyoto Protocol and some legislative proposals could
be materially adverse to CP&L's financials and operations if associated
costs cannot be recovered from customers. CP&L favors the voluntary program
approach recommended by the administration, and is evaluating options for
the reduction, avoidance, and sequestration of greenhouse gases. However,
CP&L cannot predict the outcome of this matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, EPA determined in
2000 that regulation of mercury emissions from coal-fired power plants was
appropriate. EPA is currently developing a Maximum Available Control
Technology (MACT) standard, which is expected to become final in December
2004, with compliance in 2008. Achieving compliance with the MACT standard
could be materially adverse to CP&L's financials and operations. However,
CP&L cannot predict the outcome of this matter.
2. CP&L, like other electric power companies in North Carolina, pays a
franchise tax levied by the state pursuant to North Carolina General
Statutes ss. 105-116, a state-level annual franchise tax (State Franchise
Tax). Part of the revenue generated by the State Franchise Tax is required
by North Carolina General Statutes ss. 105-116.1(b) to be distributed to
North Carolina cities in which CP&L maintains facilities. CP&L has paid and
continues to pay the State Franchise Tax to the state when such taxes are
due. However, pursuant to an Executive Order issued on February 5, 2002, by
the Governor of North Carolina, the Secretary of Revenue withheld
distributions of State Franchise Tax revenues to cities for two quarters of
fiscal year 2001-2002 in an effort to balance the state's budget.
In response to the state's failure to distribute the State Franchise Tax
proceeds, certain cities in which CP&L maintains facilities adopted
municipal franchise tax ordinances purporting to impose on CP&L a local
franchise tax. The local taxes are intended to be collected for as long as
the state withholds distribution of the State Franchise Tax proceeds from
the cities. The first local tax payments were due August 15, 2002. On August
2, 2002, CP&L filed a lawsuit against the cities seeking to enjoin the
enforcement of the local taxes and to have the local ordinances struck down
because the ordinances are beyond the cities' statutory authority and
violate provisions of the North Carolina and United States Constitutions.
On September 14, 2002, the Governor of North Carolina signed into law a
provision that prevents cities and counties from levying local franchise
taxes on electric utilities. This new legislation makes the lawsuit CP&L
filed in August against certain cities that were seeking to enforce local
franchise tax ordinances moot. As a result of the enactment of this
legislation, the parties have agreed to an Order of Dismissal by Consent,
which has been signed by the judge and filed with the Clerk of Court in
Caswell County.
3. 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.
153
After the DOE failed to comply with the decision in Indiana & Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that its delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals did not
order the DOE to begin taking spent nuclear fuel, stating that the utilities
had a potentially adequate remedy by filing a claim for damages under the
contract.
After the DOE failed to begin taking spent nuclear fuel by January 31, 1998,
a group of utilities filed a motion with the Court of Appeals to enforce the
mandate in NSP v. DOE. Specifically, this group of utilities asked the Court
to permit the utilities to escrow their waste fee payments, to order the DOE
not to use the waste fund to pay damages to the utilities, and to order the
DOE to establish a schedule for disposal of spent nuclear fuel. The Court
denied this motion based primarily on the grounds that a review of the
matter was premature, and that some of the requested remedies fell outside
of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. 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 it 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.
4. 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.
154
INDEPDENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the consolidated balance sheets of Progress Energy, Inc. and its
subsidiaries as of December 31, 2002 and 2001, and the related consolidated
statements of income, changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2002 and have issued our report
thereon dated February 12, 2003 (which expresses an unqualified opinion and
includes an explanatory paragraph referring to the Company's change in 2002 in
its method of accounting for goodwill); such consolidated financial statements
and report are included herein. Our audits also included the consolidated
financial statement schedule of the Company, listed in Item 8. This consolidated
financial statement schedule is the responsibility of the Company's management.
Our responsibility is to express an opinion based on our audits. In our opinion,
such consolidated financial statement schedule, when considered in relation to
the basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
155
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY:
We have audited the consolidated balance sheets and schedules of capitalization
of Carolina Power & Light Company and its subsidiaries (CP&L) as of December 31,
2002 and 2001, and the related consolidated statements of income and
comprehensive income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2002 and have issued our report thereon
dated February 12, 2003 such consolidated financial statements and report are
included herein. Our audits also included the consolidated financial statement
schedule of CP&L listed in Item 8. This consolidated financial statement
schedule is the responsibility of CP&L's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such consolidated
financial statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 12, 2003
156
PROGRESS ENERGY, INC.
Schedule II - Valuation and Qualifying Accounts
For the Years Ended December 31, 2002, 2001 and 2000
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expenses Additions Deductions Period
- ---------------------------------------------------------------------------------------------------------------
Year Ended
December 31, 2002
Uncollectible accounts $ 38,661,474 $ 14,862,349 $ - $ (13,925,249) (a) $ 39,598,574
Fossil dismantlement
reserve 140,515,975 1,104,008 - - 141,619,983
Nuclear refueling
outage reserve 346,000 9,735,000 - (480,000) (b) 9,601,000
Year Ended
December 31, 2001
Uncollectible accounts $ 26,292,093 $ 11,986,565 $ 19,443,822 (c) $ (19,061,006) (a) $ 38,661,474
Fossil dismantlement
reserve 134,622,258 5,899,357 - (5,640) 140,515,975
Nuclear refueling
outage reserve 10,835,000 17,281,000 - (27,770,000) (b) 346,000
Year Ended
December 31, 2000
Uncollectible accounts $ 13,926,483 $ 13,799,022 $ 8,254,368 (d) $ (9,687,780) (a) $ 26,292,093
Fossil dismantlement
reserve - 189,497 134,432,761 (d) - 134,622,258
Nuclear refueling
outage reserve - 884,000 10,591,000 (d) (640,000) (b) 10,835,000
(a) Represents write-off of uncollectible accounts, net of recoveries.
(b) Represents payments of actual expenditures related to the outages.
(c) Represents the reclassification of Rail Services' uncollectible accounts
from Net Assets Held for Sale.
(d) Represents acquisition of FPC on November 30, 2000.
157
CAROLINA POWER & LIGHT COMPANY
Schedule II - Valuation and Qualifying
Accounts For the Years Ended December 31, 2002, 2001 and 2000
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expense Additions Deductions Period
- -----------------------------------------------------------------------------------------------------------------
Year Ended
December 31, 2002
Uncollectible accounts $ 12,246,049 $ 8,203,215 $ - $ (9,156,225) (a) $ 11,293,039
Year Ended
December 31, 2001
Uncollectible accounts $ 16,976,093 $ 3,921,255 $ - $ (8,651,299) (a) $ 12,246,049
Year Ended
December 31, 2000
Uncollectible accounts $ 16,809,765 $ 12,450,000 $ - $ (12,283,672) (b) $ 16,976,093
(a) Represents write-off of uncollectible accounts, net of recoveries.
(b) Represents transfer of uncollectible account balances for SRS, NCNG, Monroe
Power and PVI 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.
158
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
As a result of the acquisition of Florida Progress and Florida Power by 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.
KPMG furnished a letter addressed to the Securities and Exchange Commission
stating that it agreed with the above statements made by Progress Energy in 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 2002 definitive proxy statement dated March 31, 2003,
and incorporated by reference herein. Information CP&L's directors is
set forth in the CP&L 2002 definitive proxy statement dated March 31,
2003, 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.
c) The Company has adopted a Code of Ethics that applies to all of its
employees, including its Chief Executive Officer, Chief Financial
Officer and Controller (or persons performing similar functions). The
Company's Code of Ethics is posted on its Internet website and can be
accessed at www.progress-energy.com. With respect to any amendment to,
or a waiver from, any provision of its Code of Ethics that applies to
the officers noted above and that relates to any standards that are
reasonably designed to deter wrongdoing and to promote:
- honest and ethical conduct, including the ethical handling of
actual or apparent conflicts of interest between personal and
professional relationships;
- full, fair, accurate, timely and understandable disclosure in
reports and documents that a registrant files with, or submits
to, the SEC and in other public communications made by the
Company;
- compliance with applicable governmental laws, rules and
regulations;
- the prompt internal reporting of violations of the code to an
appropriate person or persons identified in the Code of Ethics;
and
- accountability for adherence to the Code of Ethics,
the Company intends to post information about such amendment or waiver
on its Internet website.
159
ITEM 11. EXECUTIVE COMPENSATION
Information on Progress Energy, Inc.'s executive compensation is set forth
in the Progress Energy 2002 definitive proxy statement dated March 31,
2003, and incorporated by reference herein. Information on Carolina Power &
Light Company's executive compensation is set forth in the CP&L 2002
definitive proxy statement dated March 31, 2003, and incorporated by
reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
a) Information regarding any person Progress Energy, Inc. knows to
be the beneficial owner of more than five (5%) percent of any
class of its voting securities is set forth in its 2002
definitive proxy statement, dated March 31, 2003, and
incorporated herein by reference.
Information regarding any person Carolina Power & Light Company
knows to be the beneficial owner of more than five (5%) percent
of any class of its voting securities is set forth in its 2002
definitive proxy statement, dated March 31, 2003, and
incorporated herein by reference.
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 CP&L 2002 definitive proxy statements dated
March 31, 2003, and incorporated by reference herein.
c) Information on the equity compensation plans of Progress Energy
is set forth under the heading "Equity Compensation Plan
Information" in the Progress Energy 2002 definitive proxy
statement dated March 31, 2002 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 2002 definitive proxy statements
dated March 31, 2003, and incorporated by reference herein.
ITEM 14. CONTROLS AND PROCEDURES
Progress Energy, Inc.
Within the 90 days prior to the filing date of this report, Progress Energy
carried out an evaluation, under the supervision and with the participation of
its management, including Progress Energy's chief executive officer and chief
financial officer, of the effectiveness of the design and operation of Progress
Energy's disclosure controls and procedures pursuant to Rule 13a-14 under the
Securities Exchange Act of 1934. Based upon that evaluation, Progress Energy's
chief executive officer and chief financial officer concluded that its
disclosure controls and procedures are effective in timely alerting them to
material information relating to Progress Energy (including its consolidated
subsidiaries) required to be included in its periodic SEC filings.
Since the date of the evaluation, there have been no significant changes in
Progress Energy's internal controls or in other factors that could significantly
affect these controls.
Carolina Power & Light Company
Within the 90 days prior to the filing date of this report, CP&L carried out an
evaluation, under the supervision and with the participation of its management,
including CP&L's chief executive officer and chief financial officer, of the
effectiveness of the design and operation of CP&L's disclosure controls and
procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934.
Based upon that evaluation, CP&L's chief executive officer and chief financial
officer concluded that its disclosure controls and procedures are effective in
timely alerting them to material information relating to CP&L (including its
consolidated subsidiaries) required to be included in its periodic SEC filings.
Since the date of the evaluation, there have been no significant changes in
CP&L's internal controls or in other factors that could significantly affect
these controls.
160
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data
3. Exhibits Filed:
See EXHIBIT INDEX
b) Reports on Form 8-K or Form 8-K/A filed during or with respect to
the last quarter of 2002 and the portion of the first quarter of
2003 prior to the filing of this Form 10-K:
Progress Energy, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed
-------- -------- ------------- ----------
5 No October 16, 2002 November 6, 2002
5 No November 7, 2002 November 7, 2002
5 No November 6, 2002 November 13, 2002
9 No December 2, 2002 December 2, 2002
5 No February 7, 2003 February 12, 2003
7 Yes February 18, 2003 February 18, 2003
Carolina Power & Light Company
Financial
Item Statements
Reported Included Date of Event Date Filed
-------- -------- ------------- ----------
5 No January 1, 2003 January 3, 2003
7 Yes February 18, 2003 February 18, 2003
161
PROGRESS ENERGY, INC. RISK FACTORS
In this section, unless the context indicates otherwise, references to "our,"
"we," "us" or similar terms refer to Progress Energy, Inc. and its consolidated
subsidiaries. Investing in our securities involves risks, including the risks
described below, that could affect the energy industry, as well as us and our
business. Although we have tried to discuss key factors, please be aware that
other risks may prove to be important in the future. New risks may emerge at any
time and we cannot predict such risks or estimate the extent to which they may
affect our financial performance. Before purchasing our securities, you should
carefully consider the following risks and the other information in this Annual
Report, as well as the documents we file with the SEC from time to time. Each of
the risks described below could result in a decrease in the value of our
securities and your investment therein.
Risks Related to the Energy Industry
- ------------------------------------
We are subject to fluid and complex government regulations that may have a
negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal, state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are required
to have numerous permits, approvals and certificates from the agencies that
regulate our business. We believe the necessary permits, approvals and
certificates have been obtained for our existing operations and that our
business is conducted in accordance with applicable laws; however, we are unable
to predict the impact on our operating results from the future regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional regulations could have an adverse impact on our results of
operations.
The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North
Carolina Utilities Commission ("NCUC"), the Florida Public Service Commission
("FPSC"), and the Public Service Commission of South Carolina ("SCPSC") regulate
many aspects of our utility operations, including siting and construction of
facilities, customer service and the rates that we can charge customers. Our
system is also subject to the jurisdiction of the SEC under the Public Utility
Holding Company Act of 1935 ("PUHCA"). The rules and regulations promulgated
under PUHCA impose a number of restrictions on the operations of registered
utility holding companies and their subsidiaries. These restrictions include a
requirement that, subject to a number of exceptions, the SEC approve in advance
securities issuances, acquisitions and dispositions of utility assets or of
securities of utility companies, and acquisitions of other businesses. PUHCA
also generally limits the operations of a registered holding company like ours
to a single integrated public utility system, plus additional energy-related
businesses. Furthermore, PUHCA rules require that transactions between
affiliated companies in a registered holding company system be performed at
cost, with limited exceptions.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.
We are subject to numerous environmental laws and regulations that may increase
our cost of operations, impact or limit our business plans, or expose us to
environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount or
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all potentially responsible parties.
162
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
Recent events in the energy markets that are beyond our control have increased
the level of public and regulatory scrutiny in our industry and in the capital
markets and have resulted in increased regulation and new accounting standards.
The reaction to these events may have negative impacts on our business,
financial condition and access to capital.
As a result of the energy crisis in California during the summer of 2001, the
recent volatility of natural gas prices in North America, the bankruptcy filing
by the Enron Corporation, recently discovered accounting irregularities of
certain public companies, and investigations by governmental authorities into
energy trading activities, companies in the regulated and nonregulated utility
businesses have been under a generally increased amount of public and regulatory
scrutiny. Recently discovered accounting irregularities have caused regulators
and legislators to review current accounting practices, financial disclosures
and companies' relationships with their independent auditors. The capital
markets and ratings agencies also have increased their level of scrutiny.
Additionally, allegations against various energy trading companies of "round
trip" or "wash" transactions, which involve the simultaneous buying and selling
of the same amount of power at the same price and provide no true economic
benefit, may have a negative effect on the industry. We believe that we are
complying with all applicable laws, and we have taken steps to avoid these
events, but it is difficult or impossible to predict or control what effect
these types of disruptions in the energy markets may have on our business,
financial condition or our access to the capital markets.
Additionally, it is unclear what laws or regulations may develop, and we cannot
predict the ultimate impact of any future changes in accounting regulations or
practices in general with respect to public companies, the energy industry or in
our operations specifically. Any such new accounting standards could impact the
way we are required to record revenues, expenses, assets and liabilities. These
changes in accounting standards could lead to negative impacts on reported
earnings or increases in liabilities that could, in turn, affect our reported
results of operations.
Deregulation or restructuring in the electric industry may result in increased
competition and unrecovered costs that could adversely affect the financial
condition, results of operations or cash flows of us and our utilities'
businesses.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on us and our utility subsidiaries
and consequently on our results of operations and cash flows. Increased
competition could also result in increased pressure to lower costs, including
the cost of electricity. Retail competition and the unbundling of regulated
energy and gas service could have a significant adverse financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower profit margins or increased costs of capital. Because we have not
previously operated in a competitive retail environment, we cannot predict the
extent and timing of entry by additional competitors into the electric markets.
Movement toward deregulation in North Carolina, South Carolina and Florida has
slowed as a result of recent developments, including developments related to
electric deregulation in California and other states. We cannot predict when we
will be subject to changes in legislation or regulation, nor can we predict the
impact of these changes on our financial condition, results of operations or
cash flows.
One of the major issues to be resolved from deregulation 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 we 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
our electric utilities and our gas utility are no longer subject to cost-based
regulation and it is not possible to recover stranded costs, our financial
condition and results of operations could be adversely affected.
Additionally, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. As a result of the Public Utilities Regulatory Policies
Act of 1978 and the Energy Policy Act of 1992, competition in the wholesale
electricity market has greatly increased due to a greater participation by
traditional electricity suppliers, non-utility generators, independent power
producers, wholesale power marketers and brokers, as well as the trading of
energy futures contracts on various commodities exchanges. This increased
competition could affect our 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 us to expand our wholesale load, or
current wholesale customers elect to purchase from other suppliers after
existing contracts expire. In 1996, the FERC issued new rules on transmission
service to facilitate competition in the wholesale market on a nationwide basis.
The rules give greater flexibility and more choices to wholesale power
customers. As a result of the changing regulatory environment and the relatively
low barriers to entry, we expect competition to steadily increase. As
competition continues to increase, our financial condition and results of
operations could be adversely affected.
163
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
On December 20, 1999, the FERC issued Order No. 2000 on RTOs. This order
required public utilities that own, operate or control interstate electricity
transmission facilities to file either a proposal to participate in an RTO or an
alternative filing describing efforts and plans to participate in an RTO. To
date, our electric utilities have responded to the order as follows:
o CP&L and other investor-owned utilities filed applications with the
FERC, the NCUC and the SCPSC for approval of an RTO, currently named
GridSouth.
o Florida Power and other investor-owned utilities filed applications
with the FERC and the FPSC for approval of an RTO, currently named
GridFlorida.
On November 7, 2001, the FERC issued an order providing guidance on continued
processing of RTO filings. In this order, FERC recognized that it would not be
possible for all RTOs to be operational by December 15, 2001 as set forth in
Order No. 2000; therefore, the FERC stated that its future orders would address
the establishment of a timeline for the RTO progress in each region of the
country.
On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design ("SMD NOPR"). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC-regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. We filed comments on November 15, 2002 and supplemental comments on January
10, 2003. On January 15, 2003, the FERC announced the issuance of a White Paper
on SMD NOPR to be released in April 2003. We plan to file comments to the White
Paper. The FERC also has indicated that it expects to issue final rules during
the third quarter of 2003.
Florida Power is continuing to make progress towards the development of the
GridFlorida RTO. CP&L and the other GridSouth participants withdrew their RTO
application before the NCUC and the SCPSC pending the review of the FERC's SMD
NOPR. A determination about refiling will be made at a later date. The actual
structure of GridSouth, GridFlorida or any alternative combined transmission
structure, as well as the date it may become operational, depends upon the
resolution of all regulatory approvals and technical issues. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, GridFlorida or an alternate combined transmission structure, we
cannot predict whether their creation will have any material adverse effect on
our future consolidated results of operations, cash flows or financial
condition.
Furthermore, the SMD NOPR presents several uncertainties, including what
percentage of our investments in GridSouth and GridFlorida will be recovered,
how the elimination of transmission charges, as proposed in the SMD NOPR, will
impact us, and what amount of capital expenditures will be necessary to create a
new wholesale market.
Since weather conditions directly influence the demand for electricity and
natural gas, as well as the price of energy commodities, our results of
operations, financial condition, cash flows and ability to pay dividends on our
common stock can be negatively affected by changes in weather conditions and
severe weather.
Our results of operations, financial condition, cash flows and ability to pay
dividends on our common stock may be affected by changing weather conditions.
Weather conditions in our service territories, primarily North Carolina, South
Carolina, and Florida, directly influence the demand for electricity and natural
gas and affect the price of energy commodities. Furthermore, severe weather in
these states, such as hurricanes, tornadoes, severe thunderstorms and snow and
ice storms, can be destructive, causing outages, downed power lines and property
damage, requiring us to incur additional and unexpected expenses and causing us
to lose generating revenues.
164
In 2002, drought conditions and related water restrictions affected numerous
electric utilities in the southeast United States. Drought conditions and any
mandated water restrictions that could be implemented in response thereto, could
impact a small percentage of our generating facilities, including our
hydroelectric generating facilities. This may result in additional expenses,
such as higher fuel costs and/or purchased power expenses. We continue to
monitor weather patterns and will develop contingency plans, as necessary, to
mitigate the impact of drought conditions. We do not have any reliability
concerns with our generating facilities currently and do not expect these
developments to have a material impact on our results of operations.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers,
and may also fluctuate on a seasonal or quarterly basis.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2002, commercial and industrial customers represented approximately
36.6% of our electric revenues. As a result, changes in the macroeconomy can
have negative impacts on our revenues. As our commercial and industrial
customers experience economic hardships, our revenues can be negatively
impacted.
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
As a result, our overall operating results in the future may fluctuate
substantially on a seasonal basis. The pattern of this fluctuation may change
depending on the nature and location of facilities we acquire and the terms of
power sale contracts into which we enter. In addition, we have historically sold
less power, and consequently earned less income, when weather conditions are
milder. While we believe that our North Carolina, South Carolina, and Florida
markets complement each other during normal seasonal fluctuations, unusually
mild weather could diminish our results of operations and harm our financial
condition.
Risks Related to Us and Our Business
- ------------------------------------
As a holding company, we are dependent on upstream cash flows from our
subsidiaries. As a result, our ability to meet our ongoing and future financial
obligations and to pay dividends on our common stock is primarily dependent on
the earnings and cash flows of our operating subsidiaries and their ability to
pay upstream dividends or to repay funds to us.
We are a holding company. As such, we have no operations of our own. Our ability
to meet our financial obligations and to pay dividends on our common stock at
the current rate is primarily dependent on the earnings and cash flows of our
operating subsidiaries and their ability to pay upstream dividends or to repay
funds to us. Prior to funding us, our subsidiaries have financial obligations
that must be satisfied, including among others, debt service, preferred stock
dividends and obligations to trade creditors.
The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators. Accordingly, our profit
margins could be adversely affected if we or our utility subsidiaries do not
control operating costs.
The NCUC, the SCPSC and the FPSC each exercises regulatory authority for review
and approval of the retail electric power rates charged within its respective
state. State regulators may not allow our utility subsidiaries to increase
retail rates in the manner or to the extent requested by those subsidiaries.
State regulators may also seek to reduce retail rates. For example, in March
2002, Florida Power entered into a Stipulation and Settlement Agreement that
required Florida Power, among other things, to reduce its retail rates and to
operate under a revenue sharing plan through 2005 which provides for possible
rate refunds to its retail customers. The Agreement will also require increased
capital expenditures for Florida Power's Commitment to Excellence program.
However, if Florida Power's base rate earnings fall below a 10% return on
equity, Florida Power may petition the FPSC to amend its base rates.
Additionally, a North Carolina law passed in 2002 froze CP&L's base retail rates
for five years unless there are significant cost changes due to governmental
action, significant expenditures due to force majeure or other extraordinary
events beyond the control of CP&L. The same legislation required a significant
increase in capital expenditures over the next several years for clean air
improvements. The cash costs incurred by our utility subsidiaries are generally
not subject to being fixed or reduced by state regulators. Our utility
subsidiaries will also require dedicated capital expenditures. Thus, our ability
to maintain our profit margins depends upon stable demand for electricity and
our efforts to manage our costs.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
165
We own and operate five nuclear units through our subsidiaries, CP&L (four
units) and Florida Power (one unit), that represent approximately 4,100
megawatts, or 19%, of our generation capacity. Our nuclear facilities are
subject to environmental, health and financial risks such as the ability to
dispose of spent nuclear fuel, the ability to maintain adequate capital reserves
for decommissioning, potential liabilities arising out of the operation of these
facilities, and the costs of securing the facilities against possible terrorist
attacks. We maintain decommissioning trusts and external insurance coverage to
minimize the financial exposure to these risks; however, it is possible that
damages could exceed the amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could require us to make substantial capital expenditures at our
nuclear plants. In addition, although we have no reason to anticipate a serious
nuclear incident at our plants, if an incident did occur, it could materially
and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.
Our facilities require licenses that need to be renewed or extended in order to
continue operating. We do not anticipate any problems renewing these licenses.
However, as a result of potential terrorist threats and increased public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.
Our financial performance depends on the successful operation of electric
generating facilities by our subsidiaries.
Operating electric generating facilities involves many risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as fires, earthquakes, explosions, floods,
terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated by our subsidiaries' electric
generating facilities or an increase in the cost of operating the facilities
could have an adverse effect on our business and results of operations.
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
We rely on access to both short-term money markets and long-term capital markets
as a significant source of liquidity for capital requirements not satisfied by
the cash flow from our operations. If we are not able to access capital at
competitive rates, our ability to implement our strategy will be adversely
affected. We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings. However, certain market disruptions
or a downgrade of our credit rating may increase our cost of borrowing or
adversely affect our ability to access one or more financial markets. Such
disruptions could include:
o an economic downturn;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o market prices for electricity and gas;
o terrorist attacks or threatened attacks on our facilities or unrelated
energy companies; or
o the overall health of the utility industry.
166
Restrictions on our ability to access financial markets may affect our ability
to execute our business plan as scheduled. An inability to access capital may
limit our ability to pursue improvements or acquisitions that we may otherwise
rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
electric utilities, as well as the expansion of our diversified businesses,
primarily those of Progress Ventures. In addition to operating cash flows, we
rely heavily on our commercial paper and long-term debt. As of December 31,
2002, commercial paper and bank borrowings and long-term debt balances for
Progress Energy and its subsidiaries were as follows (in millions):
Outstanding Commercial Total Long-Term
Company Paper and Bank Borrowings Debt, Net
----------------- ------------------------- --------------------
Progress Energy, unconsolidated (a) $ 0.0 $ 4,802.4
CP&L 437.8 3,048.5
Florida Power 257.1 1,244.4 (b)
Other Subsidiaries 0.0 652.0 (c)
------------------------- --------------------
Progress Energy, consolidated $ 694.9 (d) $ 9,747.3 (b)(e)
(a) Represents solely the outstanding indebtedness of the holding company.
(b) On February 21, 2003, Florida Power issued $650.0 million aggregate
principal amount of its first mortgage bonds, the proceeds from which were
or will be used to reduce, redeem, or retire our outstanding long-term and
short-term, secured and unsecured, indebtedness.
(c) Includes the following subsidiaries: Progress Genco Ventures, LLC ($225.0
million), Florida Progress Funding Corporation ($261.0 million) and
Progress Capital Holdings, Inc. ($166.0 million).
(d) We no longer reclassify any of our commercial paper as long-term debt.
Prior to quarter ended September 30, 2002, portions of our outstanding
commercial paper backed by our multi-year credit facilities were
reclassified as long-term debt.
(e) Net of current portion, which at December 31, 2002, was $275.4 million on a
consolidated basis.
Progress Energy and its subsidiaries have an aggregate of six committed credit
lines that support our commercial paper programs totaling $1.74 billion. While
our financial policy precludes us from issuing commercial paper in excess of our
credit lines, as of December 31, 2002, we had an aggregate of approximately $1.0
billion available for future borrowing under our credit lines. Progress Energy
has an uncommitted credit line for up to $300 million and Florida Power has an
uncommitted credit line for up to $100 million. As of December 31, 2002,
Progress Energy had no outstanding borrowing under its uncommitted line of
credit. In addition, as of December 31, 2002, Progress Energy, CP&L and Florida
Power each had shelf registration statements on file with the SEC that permit
the issuance of various debt and equity securities up to an additional $1.1
billion, $500 million, and $700 million ($50 million after giving effect to
Florida Power's first mortgage bond issuance in February 2003), respectively.
These amounts may be increased from time to time, and each of CP&L and Florida
Power expects to increase its shelf capacity in the second or third quarter of
2003.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital ratios. As
of December 31, 2002, the maximum and actual ratios were as follows:
Company Maximum Ratio Actual Ratio
--------- ----------------- ---------------
Progress Energy 70% 62.4%
CP&L 65% 52.7%
Florida Power 65% 48.6%
We expect that in connection with the proposed renewal of Progress Energy's
364-day credit facility, the facility will be reduced in size from $550 million
to approximately $480 million and the permitted debt to capital ratio under that
facility will be 68% after June 30, 2003. In addition, we anticipate that the
facility will contain a requirement that Progress Energy maintain a ratio of
EBITDA to interest expense of at least 2.5x to 1. For the year ended December
31, 2002, Progress Energy's ratio of EBITDA to interest expense was 3.43x to 1.
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In the event our capital structure changes such that we approach the permitted
ratios, our access to capital and additional liquidity could decrease. A
limitation in our liquidity could have a material adverse impact on our business
strategy and our ongoing financing needs. Furthermore, the credit lines of
Progress Energy, CP&L and Florida Power each include provisions that preclude
each company from borrowing under their respective credit lines in the event of
a material adverse change in the respective company's financial condition.
Our indebtedness also includes several cross-default provisions which could
significantly impact our financial condition. Progress Energy's, CP&L's and
Florida Power's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. Progress Energy's cross default
provisions only apply to defaults of indebtedness by Progress Energy and its
significant subsidiaries (i.e., CP&L, Florida Progress, Florida Power and
Progress Capital Holdings, Inc.). CP&L's and Florida Power's cross-default
provisions only apply to defaults of indebtedness by CP&L and Florida Power and
their subsidiaries, respectively, not other affiliates of CP&L and Florida
Power.
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, not its
subsidiaries. In the event that either of these cross-default provisions were
triggered, the lenders could accelerate payment of any outstanding debt. Any
such acceleration would cause a material adverse change in the respective
company's financial condition. Certain agreements underlying our indebtedness
also limit our ability to incur additional liens or engage in certain types of
sale and leaseback transactions.
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o impacting our ability to pay dividends on our common stock at the
current rate;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it,
for working capital, acquisitions, debt service requirements or other
purposes;
o increasing our vulnerability to adverse economic and industry
conditions;
o requiring us to dedicate a substantial portion of our cash flow from
operations to payments on our debt, which would reduce funds available
to us for operations, future business opportunities or other purposes;
o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors
who have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings could increase our borrowing costs, limit
our access to additional capital and require posting of collateral, all of which
could materially and adversely affect our business, results of operations and
financial condition.
Progress Energy's senior unsecured debt has been assigned a rating by Standard &
Poor's Ratings Group (S&P), a division of The McGraw-Hill Companies, Inc., of
"BBB" (negative outlook) and by Moody's Investors Service, Inc. (Moody's) of
"Baa2" (stable outlook). On February 7, 2003, Moody's announced that it was
lowering Progress Energy's senior unsecured debt rating from "Baa1" to "Baa2,"
and changing the outlook of the rating from negative to stable. Moody's cited
the slower than planned pace of the Company's efforts to pay down debt from its
acquisition of Florida Progress as the primary reason for the ratings change.
Moody's also changed the outlook of Florida Power's senior secured debt from
stable to negative. CP&L's senior unsecured debt has been assigned a rating by
S&P of "BBB+" (negative outlook) and by Moody's of "Baa1" (stable outlook).
Florida Power's senior unsecured debt has been assigned a rating by S&P of
"BBB+" (negative outlook) and by Moody's of "A-2" (stable outlook). While our
nonregulated operations, including those conducted through our Progress Ventures
business unit, have a higher level of risk than our regulated utility
operations, we will seek to maintain a solid investment grade rating through
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prudent capital management and financing structures. We cannot, however, assure
you that any of Progress Energy's current ratings, or those of CP&L and Florida
Power, will remain in effect for any given period of time or that a rating will
not be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances in the future so warrant. Any downgrade could increase our
borrowing costs and adversely affect our access to capital, which could
negatively impact our financial results. Further, we may be required to pay a
higher interest rate in future financings, and our potential pool of investors
and funding sources could decrease. Although we would have access to liquidity
under our committed and uncommitted credit lines, if our short-term rating were
to fall below A-2 or P-2, the current ratings assigned by S&P and Moody's,
respectively, it could significantly limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy, sell or hold our securities or those of CP&L or Florida Power and that each
rating should be evaluated independently of any other rating.
Our energy trading and marketing business relies on Progress Energy's investment
grade ratings to stand behind transactions in that business. As of December 31,
2002, Progress Energy has issued guarantees with a notional amount of
approximately $172 million to support Progress Ventures' energy trading and
marketing businesses. Based upon the amount of trading positions outstanding at
December 31, 2002, if Progress Energy's ratings were to decline below investment
grade, we would have to deposit cash or provide letters of credit or other cash
collateral for approximately $13.7 million for the benefit of our
counterparties. Additionally, the power supply agreement with Jackson Electric
Membership Corporation that PVI expects to acquire from Williams Energy
Marketing and Trading Company includes a performance guarantee that Progress
Energy will assume. In the event that Progress Energy's credit ratings fall
below investment grade, Progress Energy will be required to provide additional
security for its guarantee in form and amount acceptable to Jackson, but not to
exceed the coverage amount. The coverage amount at the inception of PVI's power
sale to Jackson is $285 million and will decline over the life of the
transaction. These collateral requirements could adversely affect our
profitability on energy trading and marketing transactions and limit our overall
liquidity.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
We could incur a significant tax liability, and our results of operations and
cash flows may be materially and adversely affected if the Internal Revenue
Service denies or otherwise makes unusable the Section 29 tax credits related to
our coal and synthetic fuels businesses.
Through Progress Ventures, we produce synthetic fuel from coal. The production
and sale of the synthetic fuel qualifies for tax credits under Section 29 of the
Internal Revenue Code (Section 29) if certain requirements are satisfied,
including a requirement that the synthetic fuel differs significantly in
chemical composition from the coal used to produce such synthetic fuel. Total
Section 29 credits generated through December 31, 2002 are approximately $897.2
million. All of our synthetic fuel facilities have received favorable private
letter rulings from the Internal Revenue Service (IRS) with respect to their
operations. These tax credits are subject to review by the IRS, and if we failed
to prevail through the administrative or legal process, there could be a
significant tax liability owed for previously taken Section 29 credits, which
would significantly impact on earnings and cash flows. Tax credits for the year
ended December 31, 2002, were $291 million and were offset by operating losses,
net of tax, of $101 million, for the same period. One synthetic fuel entity,
Colona Synfuel Limited Partnership, L.L.L.P., from which we (and Florida
Progress prior to our acquisition) have been allocated approximately $251
million in tax credits to date, is being audited by the IRS. In September 2002,
all of our majority-owned synthetic fuel entities were accepted into the IRS'
Pre-Filing Agreement (PFA) program. The PFA program allows taxpayers to
accelerate the IRS examination process in order to seek resolution of specific
issues. Either we or the IRS can withdraw from the program at any time, and
issues not resolved through the program may proceed to the next level of the IRS
examination process. While the ultimate outcome is uncertain, we believe that
participation in the PFA program will likely shorten the tax examination
process. We believe that we are complying with all the requirements, including
the private letter rulings, necessary to be allowed such credits under Section
29. We believe it is likely, although we cannot be certain, that we will prevail
if challenged by the IRS on any credits taken. The current Section 29 tax credit
program will expire in 2007.
Changes in the telecommunications industry may affect the future returns we
expected from our Progress Telecom and Caronet, Inc. venture. Furthermore, in
addition to an impairment charge we recorded in the third quarter of 2002, if
the current depressed market conditions in the telecommunications industry
continue, we may need to evaluate further the recoverability of our
telecommunications assets.
169
Our current strategy in the telecommunications business is based upon our
ability to deliver broadband telecommunication services to our customers in
markets from Miami, Florida to New York City. The market for these services,
like the telecommunications industry in general, is rapidly changing, and a
number of participants in this segment have had substantial financial problems.
Due to the recent decline of the telecommunications industry and continued
operating losses, we initiated a valuation study to assess the recoverability of
Progress Telecom's and Caronet's long-lived assets. Based on this assessment, we
recorded an after-tax write down and other one-time charges of approximately
$208.6 million related to these assets in 2002. In the future, we cannot assure
that growth in demand for these services will occur as expected. If the market
for these services fails to recover as quickly as desired or becomes saturated
with competitors, our telecommunications business and telecommunications asset
valuations may be further adversely affected.
There is a risk that we will not successfully integrate newly acquired
businesses into our operations as quickly or as profitably as expected, thus
resulting in unexpected and increased costs and losses on our investments.
Our ability to successfully make strategic acquisitions and investments will
depend on:
o the extent to which acquisitions and investment opportunities become
available;
o our success in bidding for the opportunities that do become available;
o regulatory approval of the acquisitions on favorable terms; and
o our access to capital and the terms upon which we obtain capital.
If we are unable to make strategic investments and acquisitions, we may be
unable to realize the growth that we anticipate. Our ability to successfully
integrate acquired businesses into our operations will depend on the adequacy of
our implementation plans and our ability to achieve desired operating
efficiencies. If we are unable to successfully integrate new businesses into our
operations, we could experience increased costs and losses on our investments.
There are risks involved with the construction and operation of our wholesale
plants, including construction delays, dependence on third parties and related
counter-party risks, and a lack of operating history, all of which may make our
wholesale generation and overall operations less profitable and more unstable.
As of December 31, 2002, we had approximately 1,500 megawatts of wholesale
generation in commercial operation. We intend to expand our wholesale generation
to approximately 3,100 megawatts by the end of 2003.
The construction and operation of wholesale generation facilities is subject to
many risks, including those listed below. During the execution and completion of
our wholesale generation strategy, these risks will intensify. These risks
include:
o Construction delays may impact our ability to generate sufficient cash
flow and may have an adverse o effect on our operations. If we
encounter significant construction delays, any liquidated damages,
contingency funds, or insurance proceeds may not be sufficient to
service our related project debt.
o We may enter into or otherwise acquire long-term contracts that take
effect at a future date based upon our current expectations of our
future wholesale generation capacity. If our expected future capacity
does not come to fruition as expected, we may not be able to meet our
obligations under any such long-term contracts and may have to
purchase power in the spot market at then prevailing prices.
Accordingly, we may lose current and future customers, impair our
ability to implement our wholesale strategy, and suffer reputational
harm. Additionally, if we are unable to secure favorable pricing in
the spot market, our results of operations may be diminished. Progress
Energy may also become liable under any related performance guarantees
then in existence.
o Our wholesale facilities depend on third parties through construction
agreements, power purchase agreements, fuel supply and transportation
agreements, and transmission grid connection agreements. If such third
parties breach their obligations to us, our revenues, financial
condition, cash flow and ability to make payments of interest and
principal on our outstanding debts may be impaired. Any material
breach by any of these parties of their obligations under the project
contracts could adversely affect our cash flows and could impair our
ability to make payments of principal of and interest on our
indebtedness.
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o We depend on transmission and distribution facilities owned and
operated by utilities and other energy companies to deliver the
electricity and natural gas that we sell to the wholesale market. If
transmission is disrupted, or if capacity is inadequate, our ability
to sell and deliver products and satisfy our contractual obligations
may be hindered. Although FERC has issued regulations designed to
encourage competition in wholesale market transactions for
electricity, there is the potential that fair and equal access to
transmission systems will not be available or that sufficient
transmission capacity will not be available to transmit electric power
as we desire. We cannot predict the timing of industry changes as a
result of these initiatives or the adequacy of transmission facilities
in specific markets.
o Agreements with our counter-parties frequently will include the right
to terminate and/or withhold payments or performance under the
contracts if specific events occur. If a project contract were to be
terminated due to nonperformance by us or by the other party to the
contract, our ability to enter into a substitute agreement having
substantially equivalent terms and conditions is uncertain.
o Because many of our facilities are new construction and have no
operating history, various unexpected events may increase our expenses
or reduce our revenues and impair our ability to service the related
project debt. As with any new business venture of this size and
nature, operation of our facility could be affected by many factors,
including start-up problems, the breakdown or failure of equipment or
processes, the performance of our facility below expected levels of
output or efficiency, failure to operate at design specifications,
labor disputes, changes in law, failure to obtain necessary permits or
to meet permit conditions, government exercise of eminent domain power
or similar events and catastrophic events including fires, explosions,
earthquakes and droughts.
o Our facilities seek to enter into long-term power purchase agreements
to sell all or a portion of their generating capacity. Currently, the
percentage of our anticipated nonregulated capacity that will be under
contract is as follows: 2003--63%, 2004--69% and 2005--25%. Following
the expiration or early termination of our power purchase agreements,
or to the extent we cannot otherwise secure contracts for our current
and future generation capacity, our facilities will generally become
merchant facilities. Our merchant facilities may not be able to find
adequate purchasers, attain favorable pricing, or otherwise compete
effectively in the wholesale market. Additionally, numerous legal and
regulatory limitations restrict our ability to operate a facility on a
wholesale basis.
Our energy marketing and trading operations are subject to risks that may reduce
our revenues and adversely impact our results of operations and financial
condition, many of which are beyond our control.
Our fleet of wholesale nonregulated plants may sell energy into the spot market
or other competitive power markets or on a contractual basis. We may also enter
into contracts to purchase and sell electricity, natural gas and coal as part of
our power marketing and energy trading operations. Our business may also include
entering into long-term contracts that supply customers' full electric
requirements. These contracts do not guarantee us any rate of return on our
capital investments through mandated rates, and our revenues and results of
operations from these contracts are likely to depend, in large part, upon
prevailing market prices for power in our regional markets and other competitive
markets. These market prices can fluctuate substantially over relatively short
periods of time. Trading margins may erode as markets mature, and should
volatility decline, we may have diminished opportunities for gain.
In addition, the Enron Corporation bankruptcy and enhanced regulatory scrutiny
have contributed to more rigorous credit rating review of participants in the
energy marketing and trading business. Credit downgrades of certain other market
participants have significantly reduced such participants' participation in the
wholesale power markets. These events are causing a decrease in the number of
significant participants in the wholesale power markets, which could result in a
decrease in the volume and liquidity in the wholesale power markets. We are
unable to predict the impact of such developments on our power marketing and
trading business.
Furthermore, the FERC, which has jurisdiction over wholesale power rates, as
well as independent system operators that oversee some of these markets, may
impose price limitations, bidding rules and other mechanisms to address some of
the volatility in these markets. Fuel prices also may be volatile, and the price
we can obtain for power sales may not change at the same rate as fuel costs
changes. These factors could reduce our margins and therefore diminish our
revenues and results of operations.
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Volatility in market prices for fuel and power may result from:
o weather conditions;
o seasonality;
o power usage;
o illiquid markets;
o transmission or transportation constraints or inefficiencies;
o availability of competitively priced alternative energy sources;
o demand for energy commodities;
o natural gas, crude oil and refined products, and coal production
levels;
o natural disasters, wars, embargoes and other catastrophic events; and
o federal, state and foreign energy and environmental regulation and
legislation.
We actively manage the market risk inherent in our energy marketing and trading
operations. Nonetheless, adverse changes in energy and fuel prices may result in
losses in our earnings or cash flows and adversely affect our balance sheet. Our
marketing and risk management procedures may not work as planned. As a result,
we cannot predict with precision the impact that our marketing, trading and risk
management decisions may have on our business, operating results or financial
position. In addition, to the extent that we do not cover the entire exposure of
our assets or our positions to market price volatility, or our hedging
procedures do not work as planned, fluctuating commodity prices could cause our
sales and net income to be volatile.
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CAROLINA POWER & LIGHT COMPANY RISK FACTORS
In this section, references to "we," "our," "us" or similar terms are to
Carolina Power & Light Company and its consolidated subsidiaries. Investing in
our securities involves risks, including the risks described below, that could
affect the energy industry, as well as us and our business. Although we have
tried to discuss key factors, please be aware that other risks may prove to be
important in the future. New risks may emerge at any time and we cannot predict
such risks or estimate the extent to which they may affect our financial
performance. Before purchasing our securities, you should carefully consider the
following risks and the other information in this Annual Report, as well as
documents we file with the SEC from time to time. Each of the risks described
below could result in a decrease in the value of our securities and your
investment therein.
Risks Related to the Energy Industry
- ------------------------------------
We are subject to fluid and complex government regulations that may have a
negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal and state
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are required
to have numerous permits, approvals and certificates from the agencies that
regulate our business. We believe the necessary permits, approvals and
certificates have been obtained for our existing operations and that our
business is conducted in accordance with applicable laws; however, we are unable
to predict the impact on our operating results from the future regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional regulations could have an adverse impact on our results of
operations.
The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North
Carolina Utilities Commission ("NCUC") and the Public Service Commission of
South Carolina ("SCPSC") regulate many aspects of our utility operations,
including siting and construction of facilities, customer service and the rates
that we can charge customers. Although we are not a registered holding company
under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), we
are subject to many of the regulatory provisions of PUHCA.
We are a wholly-owned subsidiary of Progress Energy, Inc., a registered public
utility holding company under PUHCA. Repeal of PUHCA has been proposed, but it
is unclear whether or when such a repeal would occur. It is also unclear to what
extent repeal of PUHCA would result in additional or new regulatory oversight or
action at the federal or state levels, or what the impact of those developments
might be on our business.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal and state agencies. Changes in
regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.
We are subject to numerous environmental laws and regulations that may increase
our cost of operations, impact or limit our business plans, or expose us to
environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste, and hazardous waste. These laws and
regulations can result in increased capital, operating and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
financial or operational outcome of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount and
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all potentially responsible parties.
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
173
Recent events in the energy markets that are beyond our control have increased
the level of public and regulatory scrutiny in our industry and in the capital
markets and have resulted in increased regulation and new accounting standards.
The reaction to these events may have negative impacts on our business,
financial condition and access to capital.
As a result of the energy crisis in California during the summer of 2001, the
recent volatility of natural gas prices in North America, the bankruptcy filing
by the Enron Corporation and Worldcom, Inc., recently discovered accounting
irregularities of several public companies, and investigations by governmental
authorities into energy trading activities, companies in the regulated and
non-regulated utility businesses have been under a generally increased amount of
public and regulatory scrutiny. Recently discovered accounting irregularities
have caused regulators and legislators to review current accounting practices,
financial disclosures and companies' relationships with their independent
auditors. The capital markets and ratings agencies also have increased their
level of scrutiny. We believe that we are complying with all applicable laws,
and we have taken steps to avoid the occurrence of such events, but it is
difficult or impossible to predict or control what effect these types of
disruptions in the energy markets may have on our business, financial condition
or our access to the capital markets.
Additionally, it is unclear what laws or regulations may develop, and we cannot
predict the ultimate impact of any future changes in accounting regulations or
practices in general on public companies, the energy industry or our operations
specifically. Any such new accounting standards could impact the way we are
required to record revenues, expenses, assets and liabilities. These changes in
accounting standards could lead to negative impacts on reported earnings or
increases in liabilities that could, in turn, affect our reported results of
operations.
Deregulation or restructuring in the electric utility industry may result in
increased competition and unrecovered costs that could adversely affect our
financial condition, results of operations and cash flows.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on our results of operations and
cash flows. Increased competition could also result in increased pressure to
lower rates. Retail competition and the unbundling of regulated energy and gas
service could have a significant adverse financial impact on us due to an
impairment of assets, a loss of retail customers, lower profit margins or
increased costs of capital. Because we have not previously operated in a
competitive retail environment, we cannot predict the extent and timing of entry
by additional competitors into the electric markets. Movement toward
deregulation in North Carolina and South Carolina has slowed as a result of
recent developments, including developments related to electric deregulation in
California and other states. We cannot predict when we will be subject to
changes in legislation or regulation, nor can we predict the impact of these
changes on our financial condition, results of operations or cash flows.
One of the major issues to be resolved from deregulation 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 we 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 we
were no longer subject to cost-based regulation and it was not possible to
recover stranded costs, our financial condition and results of operations could
be adversely affected.
Additionally, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. As a result of the Public Utilities Regulatory Policies
Act of 1978 and the Energy Policy Act of 1992, competition in the wholesale
electricity market has greatly increased due to a greater participation by
traditional electricity suppliers, non-utility generators, independent power
producers, wholesale power marketers and brokers, as well as the trading of
energy futures contracts on various commodities exchanges. This increased
competition could affect our 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 us to expand our wholesale load, or
current wholesale customers elect to purchase from other suppliers after
existing contracts expire. In 1996, the FERC issued new rules on transmission
service to facilitate competition in the wholesale market on a nationwide basis.
The rules give greater flexibility and more choices to wholesale power
customers. As a result of the changing regulatory environment and the relatively
low barriers to entry, we expect competition to steadily increase. As
competition continues to increase, our financial condition, results of
operations and cash flows could be adversely affected.
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
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On December 20, 1999, the FERC issued Order No. 2000 on RTOs. This order
required public utilities that own, operate or control interstate electricity
transmission facilities to file either a proposal to participate in an RTO or an
alternative filing describing efforts and plans to participate in an RTO. We,
along with other investor-owned utilities, filed applications with the FERC, the
NCUC, and the SCPSC for approval of an RTO, currently named GridSouth.
On November 7, 2001, the FERC issued an order providing guidance on continued
processing of RTO filings. In this order, the FERC recognized that it would not
be possible for all RTOs to be operational by December 15, 2001 as set forth in
Order No. 2000; therefore, the FERC stated that its future orders would address
the establishment of a timeline for the RTO progress in each region of the
country.
On July 31, 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000, Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design ("SMD NOPR"). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC- regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. Progress Energy, Inc. filed comments on the SMD NOPR on November 15, 2002
and January 10, 2003. On January 15, 2003, the FERC announced the issuance of a
White Paper on SMD to be released in April 2003. Progress Energy, Inc. plans to
file comments on the White Paper, as appropriate. The FERC has also indicated
that it expects to issue the final rules during the summer of 2003.
The SMD NOPR presents several uncertainties, including what percentage of our
investments in GridSouth will be recovered, how the elimination of transmission
charges, as proposed in the SMD NOPR, will impact us, and what amount of capital
expenditures will be necessary to create a new wholesale market. We and other
GridSouth participants withdrew our RTO applications before the NCUC and the
SCPSC pending further review of FERC's SMD NOPR and the related White Paper.
Since weather conditions directly influence the demand for electricity, as well
as the price of energy commodities, our results of operations, financial
condition and cash flows can be negatively affected by changes in weather
conditions and severe weather.
Our results of operations, financial condition and cash flows may be affected by
changing weather conditions. Weather conditions in our service territories
directly influence the demand for electricity and affect the price of energy
commodities. Furthermore, severe weather, such as hurricanes, tornadoes, severe
thunder storms, and snow and ice storms can be destructive, causing outages,
downed power lines and property damage, requiring us to incur additional and
unexpected expenses and causing us to lose generating revenues.
In 2002, drought conditions and related water restrictions affected numerous
electric utilities in the southeast United States. Drought conditions and any
mandated water restrictions that could be implemented in response thereto, could
impact a small percentage of our generating facilities, including our
hydroelectric generating facilities. This may result in additional expenses,
such as higher fuel costs and/or purchased power expenses. We continue to
monitor weather patterns and will develop contingency plans, as necessary, to
mitigate the impact of drought conditions. We do not have any reliability
concerns with our generating facilities currently and do not expect these
developments to have a material impact on our results of operations.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers,
and may also fluctuate on a seasonal or quarterly basis.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2002, commercial and industrial customers represented approximately
23.5% and 18.2% of our electric revenues, respectively. As a result, changes in
the macroeconomy can have negative impacts on our revenues. As our commercial
and industrial customers experience economic hardships, our revenues can be
negatively impacted.
175
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change depending on the nature and location
of facilities we acquire and the terms of power sale contracts into which we
enter. In addition, we have historically sold less power, and consequently
earned less income, when weather conditions are milder. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.
Risks Related to Us and Our Business
- ------------------------------------
Under a North Carolina law passed in 2002, our base rates are frozen for five
years and we are required to increase capital expenditures for clean air
improvements. Accordingly, our profit margin could be adversely affected if we
do not control operating costs.
The NCUC and the SCPSC each exercises regulatory authority for review and
approval of the retail electric power rates charged within its respective state.
State regulators may not allow us to increase retail rates in the manner or to
the extent we request. State regulators may also seek to reduce retail rates. A
North Carolina law passed in 2002 froze our base retail rates for five years
unless there are significant cost changes due to governmental action,
significant expenditures due to force majeure or other extraordinary events
beyond our control. That same legislation required a significant increase in
capital expenditures over the next several years for clean air improvements. The
cash costs incurred by us are generally not subject to being fixed or reduced by
state regulators. We will also require dedicated capital expenditures. Thus, our
ability to maintain our profit margins depends upon stable demand for
electricity and our efforts to manage our costs.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
We own and operate four nuclear units that represent approximately 3,293
megawatts, or approximately 27%, of our generation capacity. Our nuclear
facilities are subject to environmental, health and financial risks such as the
ability to dispose of spent nuclear fuel, the ability to maintain adequate
capital reserves for decommissioning, potential liabilities arising out of the
operation of these facilities, and the costs of securing the facilities against
possible terrorist attacks. We maintain a decommissioning trust and external
insurance coverage to minimize the financial exposure to these risks; however,
it is possible that damages could exceed the amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down any of our units, or both, depending upon its assessment of the
severity of the situation, until compliance is achieved. Revised safety
requirements promulgated by the NRC could require us to make substantial capital
expenditures at our nuclear plants. In addition, although we have no reason to
anticipate a serious nuclear incident at any of our plants, if an incident did
occur, it could materially and adversely affect our results of operations or
financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.
Our facilities require licenses that need to be renewed or extended in order to
continue operating. We do not anticipate any problems renewing these licenses.
However, as a result of potential terrorist threats and increased public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.
Our financial performance depends on the successful operation of our electric
generating facilities.
Operating electric generating facilities involves many risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as fires, earthquakes, explosions, floods,
terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated by our electric generating
facilities or an increase in the cost of operating the facilities could have an
adverse effect on our business and results of operations.
176
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
We rely on access to both short-term money markets and long-term capital markets
as a significant source of liquidity for capital requirements not satisfied by
the cash flow from our operations. Our net cash flow from operations funded
approximately 192% of our capital requirements for the year ended December 31,
2002. If we are not able to access capital at competitive rates, our ability to
implement our business operations will be adversely affected. We believe that we
will maintain sufficient access to these financial markets based upon current
credit ratings. However, certain market disruptions or a downgrade of our credit
rating may increase our cost of borrowing or adversely affect our ability to
access one or more financial markets. Such disruptions could include:
o an economic downturn;
o a ratings downgrade of Progress Energy, Inc.;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o market prices for electricity;
o terrorist attacks or threatened attacks on our facilities or those of
unrelated energy companies; or
o the overall health of the utility industry.
Restrictions on our ability to access financial markets may affect our ability
to execute our business plan as scheduled. An inability to access capital may
limit our ability to pursue improvements or acquisitions that we may otherwise
rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and ability to access capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
business. In addition to operating cash flows, we rely heavily on our commercial
paper and long-term debt. As of December 31, 2002, our commercial paper balance
was approximately $437.8 million, we had no notes payable to affiliated
companies and our long-term debt balances were approximately $3.0 billion (with
no current portion of long-term debt at December 31, 2002).
We have two committed credit lines, each totals $285 million, that support our
commercial paper programs and mature in July 2003 and July 2005, respectively.
As of December 31, 2002, we had no outstanding borrowings under these lines. If
we are unable to extend or renew these credit lines on favorable terms, or at
all, we may experience a liquidity shortfall that could have a material adverse
impact on us and our financial condition. In addition, we have a shelf
registration statement on file with the SEC that permits the issuance of various
secured and unsecured debt securities up to an additional $500 million. This
amount may be increased from time to time, and we expect to increase our shelf
capacity in the first or second quarter of 2003.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital ratios. As
of December 31, 2002, the maximum and actual ratios, pursuant to the terms of
the credit facilities, were 65% and 52.7%, respectively. Indebtedness, as
defined under the credit facility agreements, includes certain letters of credit
and guarantees that are not recorded on our balance sheets.
In the event our capital structure changes such that we approach the permitted
ratios, our access to capital and additional liquidity could decrease. A
limitation in our liquidity could have a material adverse impact on our business
strategy and our ongoing financing needs. Furthermore, our credit lines include
provisions that preclude us from borrowing additional funds in the event of a
material adverse change in our financial condition.
177
Our indebtedness also includes cross-default provisions which could
significantly impact our financial condition. Our credit lines include
cross-default provisions for defaults of indebtedness in excess of $10 million.
Our cross-default provisions only apply to defaults on our indebtedness, but not
defaults by our affiliates. In the event that a cross-default provision was
triggered, our lenders could accelerate payment of any outstanding debt. Any
such acceleration would cause a material adverse change in our financial
condition.
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it,
for working capital, acquisitions, debt service requirements or other
purposes;
o increasing our vulnerability to adverse economic and industry
conditions;
o requiring us to dedicate a substantial portion of our cash flow from
operations to payments on our debt, which would reduce funds available
to us for operations, future business opportunities or other purposes;
o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors
who have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings could increase our borrowing costs and limit
our access to additional capital, which could materially and adversely affect
our business, results of operations and financial condition.
Our senior secured debt has been assigned a rating by Standard & Poor's Ratings
Group, a division of The McGraw Hill Companies, Inc., of "BBB+" (negative
outlook) and by Moody's Investors Service, Inc. of "A3" (stable outlook). Our
senior unsecured debt rating has been assigned a rating by S&P of "BBB+"
(negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's
rating philosophy links the ratings of a utility subsidiary to the credit rating
of its parent corporation. Accordingly, if S&P were to downgrade Progress
Energy, Inc.'s credit ratings, our credit rating would also likely be
downgraded, regardless of whether or not we had experienced any change in our
business operations or financial conditions.
We will seek to maintain a solid investment grade rating through prudent capital
management and financing structures. We cannot, however, assure you that our
current ratings will remain in effect for any given period of time or that our
ratings will not be lowered or withdrawn entirely by a rating agency if, in its
judgment, circumstances in the future so warrant. Any downgrade could increase
our borrowing costs and adversely affect our access to capital, which could
negatively impact our financial results. Further, we may be required to pay a
higher interest rate in future financings, and our potential pool of investors
and funding sources could decrease. Although we would have access to liquidity
under our committed and uncommitted credit lines, if our short-term rating were
to fall below "A-2" or "P-2," the current ratings assigned by S&P and Moody's,
respectively, it could significantly limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy, sell or hold our securities and that each rating should be evaluated
independently of any other rating.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
178
Changes in the telecommunications industry may affect the future returns we
expected from our Caronet, Inc. venture. Furthermore, in addition to an
impairment charge we recorded in 2002, if the current depressed market
conditions in the telecommunications industry continue, we may need to evaluate
further the recoverability of our telecommunications assets.
Our current strategy in the telecommunications business is based upon our
ability to deliver broadband telecommunication services to our customers. The
market for these services, like the telecommunications industry in general, is
rapidly changing, and a number of participants in this segment have had
substantial financial problems. Due to the recent decline of the
telecommunications industry and continued operating losses, we initiated a
valuation study to assess the recoverability of Caronet's long-lived assets.
Based on this assessment, we recorded an after-tax write down and other one-time
charges of approximately $71.1million related to these assets in 2002. In the
future, we cannot assure that growth in demand for these services will occur as
expected. If the market for these services fails to recover as quickly as
desired or becomes saturated with competitors, our telecommunications business
and telecommunications asset valuations may be further adversely affected.
179
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 21, 2003 (Registrants)
By: /s/ Peter M. Scott III
Peter M. Scott III
Executive Vice President and
Chief Financial Officer
By: /s/ Robert H. Bazemore, Jr.
Robert H. Bazemore, Jr.
Vice President and Controller
(Chief Accounting Officer)
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 19, 2003
(William Cavanaugh III, Officer and Director
Chairman and Chief Executive Officer)
/s/ Edwin B. Borden Director March 19, 2003
(Edwin B. Borden)
/s/ James E. Bostic, Jr. Director March 19, 2003
(James E. Bostic, Jr.)
/s/ David L. Burner Director March 19, 2003
(David L. Burner)
/s/ Charles W. Coker Director March 19, 2003
(Charles W. Coker)
/s/ Richard L. Daugherty Director March 19, 2003
(Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 19, 2003
(W.D. Frederick, Jr.)
180
/s/ William O. McCoy Director March 19, 2003
(William O. McCoy)
/s/ E. Marie McKee Director March 19, 2003
(E. Marie McKee)
/s/ John H. Mullin, III Director March 19, 2003
(John H. Mullin, III)
/s/ Richard A. Nunis Director March 19, 2003
(Richard A. Nunis)
/s/ Carlos A. Saladrigas Director March 19, 2003
(Carlos A. Saladrigas)
/s/ J. Tylee Wilson Director March 19, 2003
(J. Tylee Wilson)
/s/ Jean Giles Wittner Director March 19, 2003
(Jean Giles Wittner)
181
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, William Cavanaugh III, certify that:
1. I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 21, 2003 /s/ William Cavanaugh III
William Cavanaugh III
Chairman and Chief Executive Officer
182
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Peter M. Scott III, certify that:
1. I have reviewed this annual report on Form 10-K of Progress Energy, Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 21, 2003 /s/ Peter M. Scott III
Peter M. Scott III
Executive Vice President and
Chief Financial Officer
183
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, William Cavanaugh III, certify that:
1. I have reviewed this annual report on Form 10-K of Carolina Power & Light
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 21, 2003 /s/ William Cavanaugh III
William Cavanaugh III
Chairman and Chief Executive Officer
184
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Peter M. Scott III, certify that:
1. I have reviewed this annual report on Form 10-K of Carolina Power & Light
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 21, 2003 /s/ Peter M. Scott III
Peter M. Scott III
Executive Vice President and
Chief Financial Officer
185
EXHIBIT INDEX
Progress
Number Exhibit Energy, Inc. CP&L
------------ ----
*2(a) Agreement and Plan of Merger By and Among Carolina Power X
& Light Company, North Carolina Natural Gas Corporation and
Carolina Acquisition Corporation, dated as of November 10,
1998 (filed as Exhibit No. 2(b) to Quarterly Report on Form
10-Q for the quarterly period ended September 30, 1998, File
No. 1-3382.)
*2(b) Agreement and Plan of Merger by and among Carolina Power X
& Light Company, North Carolina Natural Gas Corporation
and Carolina Acquisition Corporation, Dated as of
November 10, 1998, as Amended and Restated as of April
22, 1999 (filed as Exhibit 2 to Quarterly Report on Form
10-Q for the quarterly period ended March 31, 1999, File
No. 1-3382).
*2(c) Agreement and Plan of Exchange, dated as of August 22, X X
1999, by and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Holdings, Inc.
(filed as Exhibit 2.1 to Current Report on Form 8-K dated
August 22, 1999, File No. 1-3382).
*2(d) Amended and Restated Agreement and Plan of Exchange, by X X
and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Energy, Inc., dated as of
August 22, 1999, amended and restated as of March 3, 2000
(filed as Annex A to Joint Preliminary Proxy Statement of
Carolina Power & Light Company and Florida Progress
Corporation dated March 6, 2000, File No. 1-3382).
*3a(1) Restated Charter of Carolina Power & Light Company, as X
amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
*3a(2) Restated Charter of Carolina Power & Light Company as X
amended on May 10, 1996 (filed as Exhibit No. 3(i) to
Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1997, File No. 1-3382).
*3a(3) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on June 15, 2000
(filed as Exhibit No. 3a(1) to Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000, File
No. 1-15929 and No. 1-3382).
186
*3b(1) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on December 4, 2000
(filed as Exhibit 3b(1) to Annual Report on Form 10-K dated
March 28, 2002, File No. 1-3392 and 1-15929).
*3b(2) By-Laws of Carolina Power & Light Company, as amended on X
December 12, 2001 (filed as Exhibit 3b(2) to Annual Report on
Form 10-K dated March 28, 2002, File No. 1-3392 and 1-15929).
*3b(3) By-Laws of Progress Energy, Inc., as amended and restated X
December 12, 2001 (filed as Exhibit No. 3 to Current Report on
Form 8-K dated January 17, 2002, File No. 1-15929).
*4a(1) Resolution of Board of Directors, dated December 8, 1954, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
CP&L's Serial Preferred Stock, $4.20 Series (filed as
Exhibit 3(c), File No. 33-25560).
*4a(2) Resolution of Board of Directors, dated January 17, 1967, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
CP&L's Serial Preferred Stock, $5.44 Series (filed as
Exhibit 3(d), File No. 33-25560).
*4a(3) Statement of Classification of Shares dated January 13, X
1971, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for CP&L's Serial Preferred Stock, $7.95 Series
(filed as Exhibit 3(f), File No. 33-25560).
*4a(4) Statement of Classification of Shares dated September 7, X
1972, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for CP&L's Serial Preferred Stock, $7.72 Series
(filed as Exhibit 3(g), File No. 33-25560).
*4b(1) Mortgage and Deed of Trust dated as of May 1, 1940 between X
CP&L and The Bank of New York (formerly, Irving Trust Company)
and Frederick G. Herbst (Douglas J.
MacInnes, Successor), Trustees and the First through
Fifth Supplemental Indentures thereto (Exhibit 2(b), File
No. 2-64189); the Sixth through Sixty-sixth Supplemental
Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit
2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No.
2-19118; Exhibit 4(b)-2, File No. 2-22439; Exhibit
4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297;
Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No.
2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c),
File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit
2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751;
Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File
No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit
187
2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611;
Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File
No. 2-65514; Exhibits 2(c) and 2(d), File No. 2-66851;
Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299;
Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505;
Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits
4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c),
File No. 33-38298; Exhibits 4(h) and 4(i), File No.
33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits
4(e) and 4(f), File No. 33-55060; Exhibits 4(e) and 4(f),
File No. 33-60014; Exhibits 4(a) and 4(b) to
Post-Effective Amendment No. 1, File No. 33-38349;
Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f),
File No. 33-57835; Exhibit to Current Report on Form 8-K
dated August 28, 1997, File No. 1-3382; Form of Carolina
Power & Light Company First Mortgage Bond, 6.80% Series
Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for
the period ended September 30, 1998, File No. 1-3382;
Exhibit 4(b), File No. 333-69237; and Exhibit 4(c) to
Current Report on Form 8-K dated March 19, 1999, File No.
1-3382.); and the Sixty-eighth Supplemental Indenture
(Exhibit No. 4(b) to Current Report on Form 8-K dated
April 20, 2000, File No. 1-3382; and the Sixty-ninth
Supplemental Indenture (Exhibit No. 4b(2) to Annual
Report on Form 10-K dated March 29, 2001, File No.
1-3382); and the Seventieth Supplemental Indenture,
(Exhibit 4b(3) to Annual Report on Form 10-K dated March
29, 2001, File No. 1-3382); and the Seventy-first
Supplemental Indenture (Exhibit 4b(2) to Annual Report
on Form 10-K dated March 28, 2002).
*4c(1) Indenture, dated as of February 15, 2001, between X
Progress Energy, Inc. and Bank One Trust Company, N.A.,
as Trustee, with respect to Senior Notes (filed as
Exhibit 4(a) to Form 8-K dated February 27, 2001, File
No. 1-15929).
*4c(2) Indenture, dated as of March 1, 1995, between CP&L and X
Bankers Trust Company, as Trustee, with respect to
Unsecured Subordinated Debt Securities (filed as Exhibit
No. 4(c) to Current Report on Form 8-K dated April 13,
1995, File No. 1-3382).
*4c(3) Resolutions adopted by the Executive Committee of the X
Board of Directors at a meeting held on April 13, 1995,
establishing the terms of the 8.55% Quarterly Income
Capital Securities (Series A Subordinated Deferrable
Interest Debentures) (filed as Exhibit 4(b) to Current
Report on Form 8-K dated April 13, 1995, File No. 1-3382).
188
*4d Indenture (for Senior Notes), dated as of March 1, 1999 X
between Carolina Power & Light Company and The Bank of New
York, as Trustee, (filed as Exhibit No. 4(a) to Current Report
on Form 8-K dated March 19, 1999, File No.
1-3382), and the First and Second Supplemental Senior
Note Indentures thereto (Exhibit No. 4(b) to Current
Report on Form 8-K dated March 19, 1999, File No.
1-3382); Exhibit No. 4(a) to Current Report on Form 8-K
dated April 20, 2000, File No. 1-3382).
*4e Indenture (For Debt Securities), dated as of October 28, X
1999 between Carolina Power & Light Company and The Chase
Manhattan Bank, as Trustee (filed as Exhibit 4(a) to
Current Report on Form 8-K dated November 5, 1999, File
No. 1-3382), and an Officer's Certificate issued pursuant
thereto, dated as of October 28, 1999, authorizing the
issuance and sale of Extendible Notes due October 28,
2009 (Exhibit 4(b) to Current Report on Form 8-K dated
November 5, 1999, File No. 1-3382).
*4f Contingent Value Obligation Agreement, dated as of X
November 30, 2000, between CP&L Energy, Inc. and The
Chase Manhattan Bank, as Trustee (Exhibit 4.1 to Current
Report on Form 8-K dated December 12, 2000, File No.
1-3382).
*10a(1) Purchase, Construction and Ownership Agreement dated July X
30, 1981 between Carolina Power & Light Company and North
Carolina Municipal Power Agency Number 3 and Exhibits,
together with resolution dated December 16, 1981 changing
name to North Carolina Eastern Municipal Power Agency,
amending letter dated February 18, 1982, and amendment
dated February 24, 1982 (filed as Exhibit 10(a),
File No. 33-25560).
*10a(2) Operating and Fuel Agreement dated July 30, 1981 between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981 changing name to
North Carolina Eastern Municipal Power Agency, amending
letters dated August 21, 1981 and December 15, 1981, and
amendment dated February 24, 1982 (filed as
Exhibit 10(b), File No. 33-25560).
*10a(3) Power Coordination Agreement dated July 30, 1981 between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981 changing name to
North Carolina Eastern Municipal Power Agency and
amending letter dated January 29, 1982 (filed as
Exhibit 10(c), File No. 33-25560).
189
*10a(4) Amendment dated December 16, 1982 to Purchase, X
Construction and Ownership Agreement dated July 30, 1981
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency (filed as Exhibit 10(d),
File No. 33-25560).
*10a(5) Agreement Regarding New Resources and Interim Capacity X
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency dated October 13, 1987 (filed
as Exhibit 10(e), File No. 33-25560).
*10a(6) Power Coordination Agreement - 1987A between North X
Carolina Eastern Municipal Power Agency and Carolina
Power & Light Company for Contract Power From New
Resources Period 1987-1993 dated October 13, 1987 (filed
as Exhibit 10(f), File No. 33-25560).
*10b(1) Carolina Power & Light Company $272,500,000 364-Day X
Revolving Credit Agreement dated as of July 31, 2002 (filed as
Exhibit 10(iii) to Quarterly Report on Form 10-Q for the
period ended September 30, 2002, File No.
1-3382).
*10b(2) Carolina Power & Light Company $272,500,000 3-Year Revolving X
Credit Agreement dated as of July 31, 2002 (filed as Exhibit
10(iv) to Quarterly Report on Form 10-Q for the period ended
September 30, 2002, File No. 1-3382).
*10b(3) Assumption Agreement from The Bank of New York dated X
August 5, 2002 for a total commitment of $25 million,
increasing the amount of the CP&L 364-Day and 3-Year
Revolving Credit Agreements dated as of July 31, 2002, to
$285,000,000 each (filed as exhibit 10(v) to Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 2002, File No. 1-3382).
*10b(4) Amendment and Restatement dated July 26, 2002 to Progress X
Energy, Inc.'s $450,000,000 3-Year Revolving Credit
Agreement dated November 13, 2001 as amended February 13,
2002 (filed as Exhibit 10(i) to Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2002,
File No. 1-3382 and 1-15929).
*10b(5) Assumption Agreement from Barclays Bank PLC dated X
December 17, 2001 for an additional commitment of $50
million, increasing the amount of the Progress Energy,
Inc. 364-Day Revolving Credit Agreement, dated November
13, 2001, to $550 million (filed as Exhibit 10(ii) to
Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2002, File No. 1-3382 and 1-15929).
190
*10b(6) Progress Energy, Inc. $500,000,000 364-Day Revolving Credit X
Agreement dated as of November 13, 2001 (filed as Exhibit
10b(5) to Annual Report on Form 10-K dated March 28, 2002,
File No. 1-3392 and 1-15929).
*10b(7) Progress Energy, Inc. $450,000,000 3-Year Revolving Credit X
Agreement dated as of November 13, 2001 (filed as Exhibit
10b(6) to Annual Report on Form 10-K dated March 28, 2002,
File No. 1-3392 and 1-15929).
*10b(8) Amendment, dated February 13, 2002, to Progress Energy, X
Inc. $500,000,000 364-Day Revolving Credit Agreement
dated as of November 13, 2001 (filed as Exhibit 10b(7) to
Annual Report on Form 10-K dated March 28, 2002, File No.
1-3392 and 1-15929).
*10b(9) Amendment, dated February 13, 2002, to Progress Energy, X
Inc. $450,000,000 3-Year Revolving Credit Agreement dated
November 13, 2001 (filed as Exhibit 10b(8) to Annual
Report on Form 10-K dated March 28, 2002, File No. 1-3392
and 1-15929).
- -+*10c(1) Directors Deferred Compensation Plan effective January 1, X
1982 as amended (filed as Exhibit 10(g), File No. 33-25560).
- -+*10c(2) Retirement Plan for Outside Directors (filed as Exhibit X
10(i), File No. 33-25560).
- -+*10c(3) Key Management Deferred Compensation Plan (filed as Exhibit X
10(k), File No. 33-25560).
+*10c(4) Resolutions of the Board of Directors, dated March 15, X
1989, amending the Key Management Deferred Compensation Plan
(filed as Exhibit 10(a), File No. 33-48607).
- -+*10c(5) Resolutions of the Board of Directors dated May 8, 1991, X X
amending the CP&L Directors Deferred Compensation Plan (filed
as Exhibit 10(b), File No. 33-48607).
+*10c(6) Resolutions of Board of Directors dated July 9, 1997, X
amending the Deferred Compensation Plan for Key Management
Employees of Carolina Power & Light Company.
+*10c(7) Carolina Power & Light Company Non-Employee Director Stock X X
Unit Plan, effective January 1, 1998.
- -+*10c(8) Carolina Power & Light Company Restricted Stock X X
Agreement, as approved January 7, 1998, pursuant to the
Company's 1997 Equity Incentive Plan (filed as Exhibit
No. 10 to Quarterly Report on Form 10-Q for the quarterly
period ended March 31, 1998, File No. 1-3382.)
191
- -+*10c(9) Carolina Power & Light Company Restoration Retirement X X
Plan, as amended January 1, 2000 (filed as Exhibit 10c(9)
to Annual Report on Form 10-K dated March 28, 2002,
File No. 1-3382 and 1-15929).
- -+*10c(10) Amended and Restated Supplemental Senior Executive X X
Retirement Plan of Carolina Power & Light Company,
effective January 1, 1984, as last amended March 15, 2000
(filed as Exhibit 10b(24) to Annual Report on Form 10-K
for the fiscal year ended December 31, 1999, File No.
1-3382).
- -+*10c(11) Performance Share Sub-Plan of the 2002 Progress Energy, X X
Inc. Equity Incentive Plan, dated July 9, 2002 (filed as
Exhibit 10(vii) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2002, File No.
1-3382 and 1-15929).
- -+*10c(12) Performance Share Sub-Plan of the 1997 Equity Incentive X X
Plan, as amended January 1, 2001 (filed as Exhibit
10c(11) to Annual Report on Form 10-K dated March 28,
2002, File No. 1-3382 and 1-15929).
+*10c(13) 2002 Progress Energy, Inc. Equity Incentive Plan, amended and X X
restated July 10, 2002 (filed as Exhibit 10(vi) to Quarterly
Report on Form 10-Q for the quarterly period ended September
30, 2002, File No. 1-3382 and 1-15929).
+*10c(14) 1997 Equity Incentive Plan, Amended and Restated as of X X
September 26, 2001 (filed as Exhibit 4.3 to Progress Energy
Form S-8 dated September 27, 2001, File No.
1-3382).
+*10c(15) Progress Energy, Inc. Form of Stock Option Agreement (filed X X
as Exhibit 4.4 to Form S-8 dated September 27, 2001, File No.
333-70332).
+*10c(16) Progress Energy, Inc. Form of Stock Option Award (filed as X X
Exhibit 4.5 to Form S-8 dated September 27, 2001, File No.
333-70332).
- -+*10c(17) Amended Management Incentive Compensation Plan of X X
Progress Energy, Inc., as amended and restated January 1,
2002 (filed as Exhibit 10c(15) to Annual Report on Form
10-K dated March 28, 2002, File No. 1-3382 and 1-15929).
- -+*10c(18) Progress Energy, Inc. Management Deferred X X
Compensation Plan, amended and restated as of January 1,
2002 (filed as Exhibit 10c(16) to Annual Report on Form
10-K dated March 28, 2002, File No. 1-3382 and 1-15929).
192
+*10c(19) Agreement dated April 27, 1999 between Carolina Power & X
Light Company and Sherwood H. Smith, Jr. (filed as Exhibit
10b, File No. 1-3382).
+*10c(20) Employment Agreement dated August 1, 2000 between CP&L X
Service Company LLC and William Cavanaugh III (filed as
Exhibit 10(i) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(21) Employment Agreement dated August 1, 2000 between X
Carolina Power & Light Company and William S. "Skip"
Orser (filed as Exhibit 10(ii) to Quarterly Report on
Form 10-Q for the quarterly period ended September 30,
2000, File No. 1-15929 and No. 1-3382).
+*10c(22) Employment Agreement dated August 1, 2000 between Carolina X
Power & Light Company and Tom Kilgore (filed as Exhibit
10(iii) to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(23) Employment Agreement dated August 1, 2000 between CP&L X
Service Company LLC and Robert McGehee (filed as Exhibit
10(iv) to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(24) Form of Employment Agreement dated August 1, 2000 (i) X X
between Carolina Power & Light Company and Don K. Davis; and
(ii) between CP&L Service Company LLC and Peter M.
Scott III and William D. Johnson (filed as Exhibit 10(v)
to Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(25) Form of Employment Agreement dated August 1, 2000 (i) X X
between Carolina Power & Light Company and Fred Day IV,
C.S. "Scotty" Hinnant and E. Michael Williams; and (ii)
between CP&L Service Company LLC and Bonnie V. Hancock
and Cecil L. Goodnight (filed as Exhibit 10(vi) to
Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(26) Employment Agreement dated November 30, 2000 between X
Carolina Power & Light Company, Florida Power Corporation
and H. William Habermeyer, Jr. (filed as Exhibit
10.(b)(32) to Florida Progress Corporation and Florida
Power Corporation Annual Reports on Form 10-K for the
year ended December 31, 2000).
193
+10c(27) Form of Employment Agreement between (i) Progress Energy X
Service Company, LLC and Brenda F. Castonguay, effective
September 2002; and (ii) Progress Energy Service Company and
John R. McArthur, effective January 2003.
12 Computation of Ratio of Earnings to Fixed Charges and X X
Ratio of Earnings to Fixed Charges Preferred Dividends
Combined.
21 Subsidiaries of Progress Energy, Inc. X
23(a) Consent of Deloitte & Touche LLP. X X
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement required to be filed as
an exhibit to this report pursuant to Item 14 (c) of Form 10-K.
- -Sponsorship of this management contract or compensation plan or arrangement was
transferred from Carolina Power & Light Company to Progress Energy, Inc.,
effective August 1, 2000.
194
PROGRESS ENERGY, INC.
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
--------------------------------------------------------------------------
Years Ended December 31,
--------------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(Thousands of Dollars)
Earnings, as defined:
Income from continuing operations $ 552,169 $ 540,396 $ 477,922 $ 383,299 $ 396,271
Fixed charges, as below 676,517 717,772 275,155 196,947 196,445
Capitalized interest (38,240) - - - -
Income taxes, as below (165,957) (162,487) 188,353 249,867 249,180
-------------- ----------- -------------- ------------ -----------
Total earnings, as defined $ 1,024,489 $ 1,095,681 $ 941,430 $ 830,113 $ 841,896
============== =========== ============== ============ ===========
Fixed Charges, as defined:
Interest on long-term debt $ 599,919 $ 577,987 $ 223,914 $ 173,978 $ 169,901
Other interest 41,655 111,707 37,656 6,733 11,156
Imputed interest factor in rentals-charged
principally to operating expenses 28,278 20,897 8,756 11,517 10,775
Preferred dividend requirements of subsidiaries (a) 6,665 7,181 4,710 4,719 4,613
-------------- ----------- -------------- ------------ -----------
Total fixed charges, as defined $ 676,517 $ 717,772 $ 275,036 $ 196,947 $ 196,445
============== =========== ============== ============ ===========
Income Taxes:
Income tax expense (benefit) $ (157,808) $ (154,338) $ 196,502 $ 258,018 $ 257,494
Included in AFUDC - deferred taxes in
book depreciation (8,149) (8,149) (8,149) (8,149) (8,314)
-------------- ----------- -------------- ------------ -----------
Total income taxes $ (165,957) $ (162,487) $ 188,353 $ 249,869 $ 249,180
============== =========== ============== ============ ===========
Ratio of Earnings to Fixed Charges 1.51 1.53 3.42 4.21 4.29
(a) Presented on a pretax basis based on effective income tax rate
195
CAROLINA POWER & LIGHT COMPANY
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
----------------------------------------------------------------------
Years Ended December 31,
----------------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(Thousands of Dollars)
Earnings, as defined:
Net income $ 430,932 $ 364,231 $ 461,028 $ 382,255 $ 399,238
Fixed charges, as below 235,026 270,305 248,759 202,491 191,832
Income taxes, as below 199,211 215,084 282,122 250,272 249,180
-------------- ----------- ------------- ------------- -------------
Total earnings, as defined $ 865,169 $ 849,620 $ 991,909 $ 835,018 $ 840,250
============== =========== ============= ============= =============
Fixed Charges, as defined:
Interest on long-term debt $ 204,672 $ 245,808 $ 223,562 $ 180,676 $ 169,901
Other interest 12,338 11,333 16,441 10,298 11,156
Imputed interest factor in rentals-charged
principally to operating expenses 18,016 13,163 8,756 11,517 10,775
-------------- ----------- ------------- ------------- -------------
Total fixed charges, as defined $ 235,026 $ 270,304 $ 248,759 $ 202,491 $ 191,832
============== =========== ============= ============= =============
Earnings Before Income Taxes $ 630,143 $ 579,315 $ 743,150 $ 632,527 $ 648,418
============== =========== ============= ============= =============
Ratio of Earnings Before Income Taxes to Net Income 1.46 1.59 1.61 1.65 1.62
Income Taxes:
Income tax expense $ 207,360 $ 223,233 $ 290,271 $ 258,421 $ 257,494
Included in AFUDC - deferred taxes in
book depreciation (8,149) (8,149) (8,149) (8,149) (8,314)
-------------- ----------- ------------- ------------- -------------
Total income taxes $ 199,211 $ 215,084 $ 282,122 $ 250,272 $ 249,180
============== =========== ============= ============= =============
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements $ 2,964 $ 2,964 $ 2,966 $ 2,967 $ 2,967
Portion deductible for income tax purposes (312) (312) (312) (312) (312)
-------------- ----------- ------------- ------------- -------------
Preferred dividend requirements not deductible $ 2,652 $ 2,652 $ 2,654 $ 2,655 $ 2,655
============== =========== ============= ============= =============
Preferred dividend factor:
Preferred dividends not deductible times ratio of
Earnings before income taxes to net income $ 3,872 $ 4,217 $ 4,273 $ 4,407 $ 4,301
Preferred dividends deductible for income taxes 312 312 312 312 312
Fixed charges, as above 235,026 270,305 248,759 202,491 191,832
-------------- ----------- ------------- ------------- -------------
Total fixed charges and preferred dividends $ 239,210 $ 274,834 $ 253,344 $ 207,210 $ 196,445
combined ============== =========== ============= ============= =============
Ratio of Earnings to Fixed Charges 3.68 3.14 3.99 4.12 4.38
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined 3.62 3.09 3.92 4.03 4.28
196
Exhibit 21
SUBSIDIARIES OF PROGRESS ENERGY, INC.
AT DECEMBER 31, 2002
The following is a list of certain direct and indirect subsidiaries of Progress
Energy, Inc. and their respective states of incorporation:
Carolina Power & Light Company North Carolina
Caronet, Inc. North Carolina
Florida Progress Corporation Florida
Florida Power Corporation Florida
Progress Telecommunications Corporation Florida
Progress Capital Holdings, Inc. Florida
Progress Fuels Corporation Florida
Progress Rail Services Corporation Alabama
North Carolina Natural Gas Corporation Delaware
Progress Ventures, Inc. North Carolina
Strategic Resource Solutions Corp. North Carolina
Progress Energy Service Company, LLC North Carolina
197
Exhibit 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-33520 on Form S-8, Post-Effective Amendment 1 to Registration Statement No.
33-38349 on Form S-3, Registration Statement No. 333-81278 on Form S-3,
Registration Statement No. 333-81278-01 on Form S-3, Registration Statement No.
333-81278-02 on Form S-3, Registration Statement No. 333-81278-03 on Form S-3,
Post-Effective Amendment 1 to Registration Statement No. 333-69738 on Form S-3,
Registration Statement No. 333-70332 on Form S-8, Registration Statement No.
333-87274 on Form S-3, Post-Effective Amendment 1 to Registration Statement No.
333-47910 on Form S-3, Registration Statement No. 333-52328 on Form S-8,
Post-Effective Amendment 1 to Registration Statement No. 333-89685 on Form S-8,
and Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of
our reports dated February 12, 2003 (which express an unqualified opinion and
include an explanatory paragraph referring to the Company's change in 2002 in
its method of accounting for goodwill); appearing in this Annual Report on Form
10-K of Progress Energy, Inc. for the year ended December 31, 2002.
We also consent to the incorporation by reference in Registration Statement No.
333-58800 on Form S-3 of Carolina Power & Light Company of our reports dated
February 12, 2003, appearing in this Annual Report on Form 10-K of Carolina
Power & Light Company for the year ended December 31, 2002.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 19, 2003
198