UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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 each registrant's knowledge, in definitive proxy or information
statements incorporated by reference in PART III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes X . No .
Indicate by check mark whether Carolina Power & Light Company is an accelerated
filer (as defined in Rule 12b-2 of the Act). Yes . No X .
As of June 30, 2003, the aggregate market value of the voting and non-voting
common equity of Progress Energy, Inc. held by non-affiliates was
$10,586,386,401. As of June 30, 2003, the aggregate market value of the common
equity of Carolina Power & Light Company held by non-affiliates was $0. All of
the common stock of Carolina Power & Light Company is owned by Progress Energy,
Inc.
1
As of January 30, 2004, each registrant had the following shares of common stock
outstanding:
Registrant Description Shares
---------- ----------- ------
Progress Energy, Inc. Common Stock (Without Par Value) 245,640,831
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Progress Energy and PEC definitive proxy statements dated March
31, 2004 are incorporated into PART III, ITEMS 10, 11, 12 , 13 and 14 hereof.
This combined Form 10-K is filed separately by two registrants: Progress Energy,
Inc. (Progress Energy) and Carolina Power & Light Company d/b/a Progress Energy
Carolinas, Inc. (PEC). Information contained herein relating to either
individual registrant is filed by such registrant solely on its own behalf.
2
TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
PROGRESS ENERGY, INC. RISK FACTORS
CAROLINA POWER & LIGHT COMPANY RISK FACTORS
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GLOSSARY OF TERMS
The following abbreviations or acronyms used in the text of this combined Form
10-K are defined below:
TERM DEFINITION
401(k) Progress Energy 401(k) Savings and Stock Ownership Plan
AFUDC Allowance for funds used during construction
the Agreement Stipulation and Settlement Agreement related to retail rate matters
AHI Affordable Housing investment
ARO Asset Retirement Obligation
Bcf Billion cubic feet
Broad River Skygen Energy LLC's Broad River Facility
Btu British thermal units
Caronet Caronet, Inc.
CCO Competitive Commercial Operations business segment
CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended
Code Internal Revenue Code
Colona Colona Synfuel Limited Partnership, L.L.L.P.
the Company Progress Energy, Inc. and subsidiaries
CP&L Carolina Power & Light Company
CR3 Progress Energy Florida's nuclear generating plant, Crystal River Unit No. 3
CVO Contingent value obligation
DOE United States Department of Energy
DWM North Carolina Department of Environment and Natural Resources, Division of
Waste Management
ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as
EasternNC
EITF Emerging Issues Task Force
E&TW Engineering and Trackwork
EPA United States Environmental Protection Agency
EPA of 1992 Energy Policy Act of 1992
EPIK EPIK Communications, Inc.
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FDEP Florida Department of Environment and Protection
FIN No. 46 FASB Interpretation No. 46, "Consolidation of Variable Interest Entities -
an Interpretation of ARB No. 51"
FIN No. 46R December 2003 revision of FIN No. 46
Florida Progress or FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Fuels Fuels business segment
Funding Corp. Florida Progress Funding Corporation
Genco Progress Genco Ventures LLC
Georgia Power Georgia Power Company
Global U.S. Global LLC
Harris Plant Shearon Harris Nuclear Plant
Interpath Interpath Communications, Inc.
IBEW International Brotherhood of Electrical Workers
IRS Internal Revenue Service
ISO Independent System Operator
Jackson Jackson Electric Membership Corporation
kV Kilovolt
kVA Kilovolt-ampere
LIBOR London Inter Bank Offering Rate
LRS Locomotive and Railcar Services
LSEs Load-serving entities
MACT Maximum Achievable Control Technology
MDC Maximum Dependable Capability
MGP Manufactured Gas Plant
MW Megawatt
4
MWh Megawatt-hour
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NEIL Nuclear Electric Insurance Limited
NOx Nitrogen oxide
NOx SIP Call EPA rule which requires 22 states including North and South Carolina to
further reduce nitrogen oxide emissions.
NRC United States Nuclear Regulatory Commission
Nuclear Waste Act Nuclear Waste Policy Act of 1982
OPEB Postretirement benefits other than pensions
Odyssey Odyssey Telecorp, Inc.
P11 Intercession Unit P11
PEC Progress Energy Carolinas, Inc.
PESC Progress Energy Service Company, LLC
PFA IRS Prefiling Agreement
the Plan Revenue Sharing Incentive Plan
PLR Private Letter Ruling
Power Agency North Carolina Eastern Municipal Power Agency
PCH Progress Capital Holdings, Inc.
Progress Energy Progress Energy, Inc.
Progress Fuels Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail Progress Rail Services Corporation
Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy
generation and marketing activities, as well as gas, coal and synthetic
fuel operations
Preferred Securities FPC-obligated mandatorily redeemable preferred securities of FPC Capital I
PRP Potentially responsible party, as defined in CERCLA
PSSP Performance Share Sub-Plan
PTC Progress Telecommunications Corporation
PTC LLC Progress Telecom, LLC
PUHCA Public Utility Holding Company Act of 1935, as amended
PURPA Public Utilities Regulatory Policies Act of 1978
PVI Progress Ventures, Inc. (formerly referred to as CPL Energy Ventures, Inc.)
PWR Pressurized water reactor
QF Qualifying facilities
Rail Services Rail Services business segment
Rockport Indiana Michigan Power Company's Rockport Unit No. 2
RSA Restricted Stock Awards program
RTO Regional Transmission Organization
SCPSC Public Service Commission of South Carolina
SEC United States Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
SFAS Statement of Financial Accounting Standards
SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for
Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation"
SFAS No. 87 Statement of Financial Accounting Standards No. 87, "Employers' Accounting
for Pensions"
SFAS No. 121 Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of"
SFAS No. 123 Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation"
SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative and Hedging Activities"
SFAS No. 138 Statement of Financial Accounting Standards No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities - an
Amendment of FASB Statement No. 133"
SFAS No. 142 Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets"
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SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations"
SFAS No. 144 Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets"
SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB
Statement No. 123"
SFAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission and Standard Market Design
SO2 Sulfur dioxide
SRS Strategic Resource Solutions Corp.
Tax Agreement Intercompany Income Tax Allocation Agreement
the Trust FPC Capital I
Westchester Westchester Gas Company
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SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The matters discussed throughout this Form 10-K that are not historical facts
are forward-looking and, accordingly, involve estimates, projections, goals,
forecasts, assumptions, risks and uncertainties that could cause actual results
or outcomes to differ materially from those expressed in the forward-looking
statements.
In addition, examples of forward-looking statements discussed in this Form 10-K,
include a) PART II, ITEM 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" including, but not limited to, statements
under the following headings: 1) "Liquidity and Capital Resources" about
operating cash flows, estimated capital requirements through the year 2006 and
future financing plans 2) "Strategy" about Progress Energy's strategy and 3)
"Other Matters" about the effects of new environmental regulations, nuclear
decommissioning costs and the effect of electric utility industry restructuring,
and b) statements made in the "Risk Factors" sections.
Any forward-looking statement speaks only as of the date on which such statement
is made, and neither Progress Energy nor PEC undertakes any obligation to update
any forward-looking statement or statements to reflect events or circumstances
after the date on which such statement is made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; the impact of recent events in the
energy markets that have increased the level of public and regulatory scrutiny
in the energy industry and in the capital markets; deregulation or restructuring
in the electric industry that may result in increased competition and
unrecovered (stranded) costs; the uncertainty regarding the timing, creation and
structure of regional transmission organizations; weather conditions that
directly influence the demand for electricity; recurring seasonal fluctuations
in demand for electricity; fluctuations in the price of energy commodities and
purchased power; economic fluctuations and the corresponding impact on Progress
Energy, Inc. and subsidiaries' (the Company) commercial and industrial
customers; the ability of the Company's subsidiaries to pay upstream dividends
or distributions to it; the impact on the facilities and the businesses of the
Company from a terrorist attack; the inherent risks associated with the
operation of nuclear facilities, including environmental, health, regulatory and
financial risks; the ability to successfully access capital markets on favorable
terms; the impact that increases in leverage may have on the Company; the
ability of the Company to maintain its current credit ratings; the impact of
derivative contracts used in the normal course of business by the Company;
investment performance of pension and benefit plans and the ability to control
costs; the availability and use of Internal Revenue Code Section 29 (Section 29)
tax credits by synthetic fuel producers, and the Company's continued ability to
use Section 29 tax credits related to its coal and synthetic fuel businesses;
the Company's ability to successfully integrate newly acquired assets,
properties or businesses into its operations as quickly or as profitably as
expected; the Company's ability to manage the risks involved with the operation
of its nonregulated plants, including dependence on third parties and related
counter-party risks, and a lack of operating history; the Company's ability to
manage the risks associated with its energy marketing operations; and
unanticipated changes in operating expenses and capital expenditures. Many of
these risks similarly impact the Company's subsidiaries.
These and other risk factors are detailed from time to time in the Company's
United States Securities and Exchange Commission (SEC) reports. Many, but not
all of the factors that may impact actual results are discussed in the "Risk
Factors" sections of this report. You should carefully read the "Risk Factors"
sections of this report. All such factors are difficult to predict, contain
uncertainties that may materially affect actual results and may be beyond the
control of Progress Energy and PEC. New factors emerge from time to time, and it
is not possible for management to predict all such factors, nor can it assess
the effect of each such factor on Progress Energy and PEC.
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PART I
ITEM 1. BUSINESS
GENERAL
COMPANY
Progress Energy, Inc. (Progress Energy or the Company, which includes
consolidated subsidiaries unless otherwise indicated) is a registered holding
company under the Public Utility Holding Company Act of 1935 (PUHCA) and is an
integrated energy company located principally in the southeast region of the
United States. Both the Company and its subsidiaries are subject to the
regulatory provisions of PUHCA. Progress Energy was incorporated on August 19,
1999. The Company was initially formed as CP&L Energy, Inc. (CP&L Energy), which
became the holding company for Carolina Power & Light Company (CP&L) on June 19,
2000. All shares of common stock of CP&L were exchanged for an equal number of
shares of CP&L Energy common stock.
Effective January 1, 2003, CP&L, Florida Power Corporation and Progress
Ventures, Inc. began doing business under the names Progress Energy Carolinas,
Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy Ventures,
Inc. (Progress Ventures), respectively. The legal names of these entities have
not changed and there was no restructuring of any kind related to the name
change. The current corporate and business unit structure remains unchanged.
Through its wholly-owned regulated subsidiaries PEC and PEF, Progress Energy is
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina, South Carolina and Florida. Through
its Competitive Commercial Operations (CCO) business segment, Progress Energy is
involved in nonregulated electricity generation operations. Through its Fuels
business segment (Fuels), Progress Energy is involved in natural gas drilling
and production, coal terminal services, coal mining, synthetic fuel production,
fuel transportation and delivery. Both CCO and Fuels are involved in limited
energy trading activities. Through its Rail Services business segment (Rail
Services), Progress Energy engages in various rail and railcar related services.
The Other Businesses segment primarily includes telecommunication services,
miscellaneous nonregulated activities, and holding company operations. For
information regarding the revenues, income and assets attributable to the
Company's business segments, see PART II, ITEM 8, Note 19 to the Progress Energy
Consolidated Financial Statements.
The Company has more than 24,000 megawatts (MW) of electric generation capacity
and serves more than 2.8 million retail electric customers in portions of North
Carolina, South Carolina and Florida. PEC's and PEF's utility operations are
complementary: PEC has a summer peaking demand, while PEF has a winter peaking
demand. In addition, PEC's greater proportion of commercial and industrial
customers combined with PEF's greater proportion of residential customers
creates a balanced customer base. The Company is dedicated to expanding the
region's electric generation capacity and delivering reliable, competitively
priced energy.
Progress Energy revenues for the year ended December 31, 2003 were $8.7 billion
and assets at year-end were $26.2 billion. Its principal executive offices are
located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone
number (919) 546-6111. The Progress Energy home page on the Internet is located
at http://www.progress-energy.com, the contents of which are not and shall not
be deemed a part of this document or any other U.S. Securities and Exchange
Commission (SEC) filing. The Company makes available free of charge on its
website its annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with or furnished to the
SEC.
SIGNIFICANT TRANSACTIONS
Progress Telecommunications Corporation Business Combination
In December 2003, Progress Telecommunications Corporation (PTC) and Caronet,
Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy, and EPIK
Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey Telecorp, Inc.
(Odyssey), contributed substantially all of their assets and transferred certain
liabilities to Progress Telecom, LLC (PTC LLC), a subsidiary of PTC.
Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2
million in cash and Caronet became a wholly-owned subsidiary of Odyssey.
Following consummation of all the transactions described above, PTC holds a 55
percent ownership interest in, and is the parent of PTC LLC. See PART II, ITEM
8, Note 4A to the Progress Energy Consolidated Financial Statements.
8
Mesa Hydrocarbons, Inc. Divestiture
In October 2003, the Company sold certain gas-producing properties owned by Mesa
Hydrocarbons, LLC, a wholly-owned subsidiary of Progress Fuels Corporation
(Progress Fuels), which is included in the Fuels segment. Net proceeds of
approximately $97 million were used to reduce debt. See PART II, ITEM 8, Note 3C
to the Progress Energy Consolidated Financial Statements.
NCNG Divestiture
On September 30, 2003, the Company completed the sale of North Carolina Natural
Gas Corporation (NCNG) and the Company's equity investment in Eastern North
Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. As a
result of this action, the operating results of NCNG were reclassified to
discontinued operations for all reportable periods. Net proceeds from the sale
of NCNG and ENCNG of approximately $450 million were used to reduce debt. See
PART II, ITEM 8, Note 3A to the Progress Energy Consolidated Financial
Statements.
Natural Gas Reserves Acquisition
During 2003, Progress Fuels entered into several independent transactions to
acquire approximately 200 natural gas-producing wells with proven reserves of
approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc. and three
other privately-owned companies, all headquartered in Texas. The total cash
purchase price for the transactions was approximately $168 million. See PART II,
ITEM 8, Note 4B to the Progress Energy Consolidated Financial Statements.
Wholesale Energy Contract Acquisition
In May 2003, PVI entered into a definitive agreement with Williams Energy
Marketing and Trading, a subsidiary of The Williams Companies, Inc., to acquire
a long-term full-requirements power supply agreement at fixed prices with
Jackson Electric Membership Corporation (Jackson), for $188 million. See PART
II, ITEM 8, Note 4C to the Progress Energy Consolidated Financial Statements.
Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a resolution
approving the sale of the majority of the assets of Railcar Ltd., a leasing
subsidiary included in the Rail Services segment. An estimated impairment on
assets held for sale was recognized in December 2002 to write-down the assets to
fair value less the costs to sell.
In March 2003, the Company signed a letter of intent to sell the majority of
Railcar Ltd. assets to The Andersons, Inc. The asset purchase agreement was
signed in November 2003, and the transaction closed on February 12, 2004. Net
proceeds from the sale were approximately $82 million. See PART II, ITEM 8, Note
3B to the Progress Energy Consolidated Financial Statements.
Westchester Acquisition
In April 2002, Progress Fuels acquired 100% of Westchester Gas Company
(Westchester). The acquisition included approximately 215 natural gas-producing
wells, 52 miles of intrastate gas pipeline and 170 miles of gas-gathering
systems. The aggregate purchase price was approximately $153 million. See PART
II, ITEM 8, Note 4E to the Progress Energy Consolidated Financial Statements.
Generation Acquisition
In February 2002, PVI acquired 100% of two electric generating projects in
Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. for a total cash
purchase price of approximately $348 million. The transaction included tolling
agreements and two power purchase agreements with LG&E Energy Marketing, Inc.
See PART II, ITEM 8, Note 4D to the Progress Energy Consolidated Financial
Statements.
9
COMPETITION
GENERAL
In recent years, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. Several states have also decided to restructure aspects
of retail electric service. The issue of retail restructuring and competition is
being reviewed by a number of states and bills have been introduced in past
sessions of Congress that sought to introduce such restructuring in all states.
The 108th Congress spent much of 2003 working on a comprehensive energy bill.
While that legislation passed the House, the Senate failed to pass the
legislation in 2003. There will probably be an effort to resurrect the
legislation in 2004. The legislation would have further clarified the Federal
Energy Regulatory Commission's (FERC) role with respect to Standard Market
Design and mandatory Regional Transmission Organizations (RTOs) and would have
repealed PUHCA. The Company cannot predict the outcome of this matter.
As a result of the Public Utilities Regulatory Policies Act of 1978 (PURPA) and
the Energy Policy Act of 1992 (EPA of 1992), competition in the wholesale
electricity market has greatly increased, especially from non-utility generators
of electricity. In 1996, the FERC issued new rules on transmission service to
facilitate competition in the wholesale market on a nationwide basis. The rules
give greater flexibility and more choices to wholesale power customers.
In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum
characteristics and eight functions for transmission entities, including
independent system operators (ISOs) and transmission companies that are required
to become FERC-approved RTOs. The rule stated that public utilities that own,
operate or control interstate transmission facilities had to have filed, by
October 2000, either a proposal to participate in an RTO or an alternative
filing describing efforts and plans to participate in an RTO. The order provided
guidance and specified minimum characteristics and functions required of an RTO
and also stated that all RTOs should be operational by December 15, 2001. During
2001, the deadline for RTOs to be operational was extended.
In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No.
RM01-12-000 Remedying Undue Discrimination through Open Access Transmission
Service and Standard Electricity Market Design (SMD NOPR). The proposed rules
set forth in the SMD NOPR would require, among other things, that 1) all
transmission-owning utilities transfer control of their transmission facilities
to an independent third party; 2) transmission service to bundled retail
customers be provided under the FERC-regulated transmission tariff, rather than
state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities (LSEs) be required to meet minimum criteria for generating reserves. In
2003, the FERC released a White Paper on the Wholesale Market Platform. The
White Paper provides an overview of what the FERC intends to include in a final
rule in the SMD NOPR docket. The White Paper retains the fundamental and most
protested aspects of SMD NOPR, including mandatory RTOs and the FERC's assertion
of jurisdiction over certain aspects of retail service. The FERC has not yet
issued a final rule on SMD NOPR.
To date, many states have adopted legislation that would give retail customers
the right to choose their electricity provider (retail choice) and most other
states have, in some form, considered the issue. There is currently no proposed
legislation in North Carolina, South Carolina or Florida that would introduce
retail choice.
The developments described above have created changing markets for energy. As a
strategy for competing in these changing markets, the Company is becoming a
total energy provider in the region by providing a full array of energy-related
services to its current customers and expanding its market reach. The Company
took a major step towards implementing this strategy through its acquisition of
Florida Progress Corporation (FPC) in November 2000.
Since passage of the EPA of 1992, competition in the wholesale electric utility
industry has significantly increased due to a greater participation by
traditional electricity suppliers, wholesale power marketers and brokers and due
to the trading of energy futures contracts on various commodities exchanges.
This increased competition could affect PEC and PEF's load forecasts, plans for
power supply and wholesale energy sales and related revenues. The impact could
10
vary depending on the extent to which additional generation is built to compete
in the wholesale market, new opportunities are created for PEC and PEF to expand
their wholesale load, or current wholesale customers elect to purchase from
other suppliers after existing contracts expire.
An issue encompassed by industry restructuring is the recovery of "stranded
costs." Stranded costs primarily include the generation assets of utilities
whose value in a competitive marketplace would be less than their current book
value, as well as above-market purchased power commitments to qualifying
facilities (QFs). Thus far, all states that have passed restructuring
legislation have provided for the opportunity to recover a substantial portion
of stranded costs. Assessing the amount of stranded costs for a utility requires
various assumptions about future market conditions, including the future price
of electricity.
In November 2003, the FERC adopted new standards of conduct that apply uniformly
to interstate natural gas pipelines and public utilities. The new standards of
conduct govern the relationship between transmission providers and their energy
affiliates in a manner that prevents market power and preferential treatment.
Each utility was required to submit a plan and schedule for compliance with the
new rules by February 2004. All utilities must be in compliance with the new
rules no later than June 2004. PEC and PEF have submitted their plans and
schedules for timely compliance.
See PART I, ITEM 1, "Competition" of Electric-PEC and Electric-PEF for
discussions of franchises as they relate to PEC and PEF.
See PART I, ITEM 1, "Competition," under Electric-PEC, Electric-PEF and Other
for further discussion of competitive developments within these segments.
PUHCA
As a result of the acquisition of FPC, Progress Energy is now a registered
holding company subject to regulation by the SEC under PUHCA. Therefore,
Progress Energy and its subsidiaries are subject to the regulatory provisions of
PUHCA, including provisions relating to the issuance of securities, sales and
acquisitions of securities and utility assets, and services performed by
Progress Energy Service Company, LLC.
While various proposals, including the 2003 energy bill, have been introduced in
Congress regarding PUHCA, the prospects for legislative reform or repeal are
uncertain at this time.
REGULATORY MATTERS
GENERAL
PEC and PEF are subject to regulation in North Carolina by the North Carolina
Utilities Commission (NCUC), in South Carolina by the Public Service Commission
of South Carolina (SCPSC) and in Florida by the Florida Public Service
Commission (FPSC) with respect to, among other things, rates and service for
electric energy sold at retail, retail service territory and issuances of
securities. In addition, PEC and PEF are subject to regulation by the FERC with
respect to transmission and sales of wholesale power, accounting and certain
other matters. The underlying concept of utility ratemaking is to set rates at a
level that allows the utility to collect revenues equal to its cost of providing
service including a reasonable rate of return on its equity. Increased
competition as a result of industry restructuring may affect the ratemaking
process.
NUCLEAR MATTERS
GENERAL
PEC owns and operates four nuclear units and PEF owns and operates one nuclear
generating unit which are regulated by the United States Nuclear Regulatory
Commission (NRC) under the Atomic Energy Act of 1954 and the Energy
Reorganization Act of 1974. In the event of noncompliance, the NRC has the
authority to impose fines, set license conditions, shut down a nuclear unit, or
some combination of these, depending upon its assessment of the severity of the
situation, until compliance is achieved. The nuclear units are periodically
removed from service to accommodate normal refueling and maintenance outages,
repairs and certain other modifications.
11
The nuclear power industry faces uncertainties with respect to the cost and
long-term availability of sites for disposal of spent nuclear fuel and other
radioactive waste, compliance with changing regulatory requirements, nuclear
plant operations, increased capital outlays for modifications, the technological
and financial aspects of decommissioning plants at the end of their licensed
lives and requirements relating to nuclear insurance.
NRC operating licenses held by PEC currently expire in July 2010 for Robinson
Unit No. 2, in December 2014 and September 2016 for Brunswick Units 2 and 1,
respectively and in October 2026 for the Shearon Harris Nuclear Plant (Harris
Plant). An application to extend the Robinson license 20 years was submitted in
June 2002 and a similar application is expected to be made for the Brunswick
Plant in December 2004 and for the Harris Plant in 2006. According to the NRC
schedule, the Company expects to receive the new license extension for Robinson
in April 2004. A condition of the operating license for each unit requires an
approved plan for decontamination and decommissioning.
In addition, PEC will request to have its license for the Independent Spent Fuel
Storage Installation at the Robinson Plant extended 20 years with an exemption
request for an additional 20-year extension during the first quarter of 2004.
Its current license is due to expire in August 2006. PEC expects to receive this
extension.
PEF has a license to operate its Crystal River Unit No. 3 (CR3) nuclear
generating plant through December 3, 2016. On February 20, 2003, PEF notified
the NRC of its intent to submit an application to extend the plant license in
the first quarter of 2009.
PRESSURIZED WATER REACTORS
In 2002, the NRC sent a bulletin to companies that hold licenses for pressurized
water reactors (PWRs) requiring information on the structural integrity of the
reactor vessel head and a basis for concluding that the vessel head will
continue to perform its function as a coolant pressure boundary. Inspections of
the vessel heads at the Company's PWR plants had been performed during previous
outages. At the Robinson and Harris Plants, inspections were completed in 2001
and there was no degradation of the reactor vessel heads. The Company's
Brunswick Plant has a different design and is not affected by the issue.
Inspection of the vessel head at CR3 was performed during a previous outage and
no degradation of the reactor vessel head was identified.
In 2002, the NRC issued an additional bulletin dealing with head leakage due to
cracks near the control rod nozzles, asking licensees to commit to high
inspection standards to ensure the more susceptible plants have no cracks. The
Robinson Plant is in this category and had a refueling outage in 2002. The
Company completed a series of examinations in 2002 of the entire reactor
pressure vessel head and found no indications of control rod drive mechanism
cracking and no corrosion of the head itself. During the outage, a walkdown of
the reactor coolant pressure boundary was also completed and no corrosion was
found. The Company currently plans to re-inspect the Robinson Plant reactor head
during its next refueling outage in 2004 and replace the head in 2005. The
Harris Plant is ranked in the lowest susceptibility classification. PEF replaced
the vessel head at CR3 during its regularly scheduled refueling outage in 2003.
In 2003, the NRC issued an order requiring specific inspections of the reactor
pressure vessel head and associated penetration nozzles at PWRs. The Company
responded, stating that it intended to comply with the provisions of the Order.
No adverse impact is anticipated. The NRC also issued a bulletin requesting PWR
licensees to address inspection plans for reactor pressure vessel lower head
penetrations. The Company plans to perform bare metal visual inspections of
Robinson during the next regularly scheduled refueling outages in 2004. The
Company completed a bare metal visual inspection of the vessel bottom at Harris
and CR3 during their 2003 outages and found no signs of corrosion or leakage at
either unit. The Company plans to do additional, more detailed inspections as
part of the next scheduled 10-year in-service inspections.
In February 2004, the NRC issued a revised Order for inspection requirements for
reactor pressure vessel heads at PWRs. The Company is in the process of
reviewing the Order. No adverse impact is anticipated.
12
SECURITY
The NRC has issued various orders since September 2001 with regard to security
at nuclear plants. These orders include additional restrictions on access,
increased security measures and closer coordination with the Company's partners
in intelligence, military, law enforcement and emergency response at the
federal, state and local levels. The Company is completing the requirements as
outlined in the orders by the established deadlines. As the NRC, other
governmental entities and the industry continue to consider security issues, it
is possible that more extensive security plans could be required.
SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework
for development by the federal government of interim storage and permanent
disposal facilities for high-level radioactive waste materials. The Nuclear
Waste Act promotes increased usage of interim storage of spent nuclear fuel at
existing nuclear plants. The Company will continue to maximize the use of spent
fuel storage capability within its own facilities for as long as feasible. With
certain modifications and additional approval by the NRC including the
installation of onsite dry storage facilities at Robinson (2005) and Brunswick
(2008), PEC's spent nuclear fuel storage facilities will be sufficient to
provide storage space for spent fuel generated on PEC's system through the
expiration of the current operating licenses for all of PEC's nuclear generating
units. PEF currently is storing spent nuclear fuel onsite in spent fuel pools.
PEF will seek renewal of the CR3 operating license and currently, CR3 has
sufficient storage capacity in place for fuel consumed through the end of the
expiration of the current license in 2016. If PEF receives approval of the CR3
operating license renewal, dry storage may be necessary. See PART II, ITEM 8,
Note 21E to the Progress Energy Consolidated Financial Statements and Note 16D
to the PEC Consolidated Financial Statements for a discussion of the Company's
contract with the U.S. Department of Energy (DOE) for spent nuclear waste.
DECOMMISSIONING
In PEC's and PEF's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdiction, the provisions
for nuclear decommissioning costs are approved by the FERC. See PART II, ITEM 8,
Note 5D to the Progress Energy Consolidated Financial Statements and Note 3D to
the PEC Consolidated Financial Statements for a discussion of PEC and PEF's
nuclear decommissioning costs.
ENVIRONMENTAL
GENERAL
In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and local authorities. The
Company considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and operations
and believes it has all necessary permits to conduct such operations.
Environmental laws and regulations constantly evolve and the ultimate costs of
compliance cannot always be accurately estimated. The estimated capital costs
associated with compliance with pollution control laws and regulations at the
Company's existing fossil facilities that the Company expects to incur from 2004
through 2006 are included in the "Investing Activities" discussion under PART
II, ITEM 7, "Liquidity and Capital Resources".
AIR QUALITY
Amendments to the Federal Clean Air Act require substantial reductions in sulfur
dioxide (SO2) and nitrogen oxide (NOx) emissions from fossil-fueled electric
generating plants. The Company meets the SO2 emissions requirements by
maintaining sufficient SO2 emission allowances. Installation of additional
equipment was necessary to reduce NOx emissions. Increased operation and
maintenance costs, including emission allowance expense, installation of
additional equipment and increased fuel costs are not material to the
consolidated financial position or results of operations of the Company.
13
There has been and may be further proposed federal legislation requiring
reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some of
these proposals establish nationwide caps and emission rates over an extended
period of time. This national multi-emission approach to air pollution control
could involve significant capital costs which could be material to the Company's
financial operations. Some companies may seek recovery of the related costs
through rate adjustments or similar mechanisms. Control equipment that will be
installed on North Carolina fossil generating facilities as part of the North
Carolina law discussed below may address some of the issues outlined above.
However, the Company cannot predict the outcome of this matter.
The U.S. Environmental Protection Agency (EPA) is conducting an enforcement
initiative related to a number of coal-fired utility power plants in an effort
to determine whether modifications at those facilities were subject to New
Source Review requirements or New Source Performance Standards under the Clean
Air Act. Both PEC and PEF were asked to provide information to the EPA as part
of this initiative and cooperated in providing the requested information. The
EPA initiated enforcement actions against other unaffiliated utilities as part
of this initiative, some of which have resulted in settlement agreements calling
for expenditures, ranging from $1.0 billion to $1.4 billion. A utility that was
not subject to a civil enforcement action settled its New Source Review issues
with the EPA for $300 million. These settlement agreements have generally called
for expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. The Company cannot predict the outcome of this matter.
In 2003, the EPA published a final rule addressing routine equipment replacement
under the New Source Review program. The rule defines routine equipment
replacement and the types of activities that are not subject to New Source
Review requirements or New Source Performance Standards under the Clean Air Act.
The rule was challenged in federal court and its implementation has been stayed.
The Company cannot predict the outcome of this matter.
In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
addressing the issue of regional transport of ozone (NOx SIP Call). The EPA's
rule requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce NOx emissions in order to attain a
pre-set state emission level during each year's "ozone season," beginning May
31, 2004. PEC is currently installing controls necessary to comply with the rule
and expects to be in compliance as required by the final rule. Capital
expenditures to meet these measures in North Carolina and South Carolina could
reach approximately $370 million, which has not been adjusted for inflation. The
Company has spent approximately $258 million to date related to these
expenditures. Increased operation and maintenance costs relating to the NOx SIP
Call are not expected to be material to the Company's results of operations. The
Company cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain sources to
make reductions in NOx emissions by May 1, 2003. The final rule also includes a
set of regulations that affect NOx emissions from sources included in the
petitions. The North Carolina coal-fired electric generating plants are included
in these petitions. Acceptable state plans under the NOx SIP Call can be
approved in lieu of the final rules the EPA approved as part of the Section 126
petitions. In April 2002, the EPA published a final rule harmonizing the dates
for the Section 126 rule and the NOx SIP Call. The new compliance date for all
affected sources is now May 31, 2004, rather than May 1, 2003. The EPA has
approved North Carolina's NOx SIP Call rule and has indicated it will rescind
the Section 126 rule in a future rulemaking.
In June 2002, legislation was enacted in North Carolina requiring the state's
electric utilities to reduce the emissions of NOx and SO2 from coal-fired power
plants. Operation and maintenance costs will increase due to the additional
personnel, materials and general maintenance associated with the equipment.
Operation and maintenance expenses are recoverable through base rates, rather
than as part of this program. The legislation also freezes the utilities' base
rates for five years unless there are extraordinary events beyond the control of
the utilities or unless the utilities persistently earn a return substantially
in excess of the rate of return established and found reasonable by the NCUC in
the utilities' last general rate case. See PART II, ITEM 8, Note 21E to the
Progress Energy Consolidated Financial Statements and Note 16D to the Progress
Energy Carolinas Consolidated Financial Statements for further discussion.
14
In 1997, the EPA's Mercury Study Report and Utility Report to Congress conveyed
that mercury is not a risk to the average American and expressed uncertainty
about whether reductions in mercury emissions from coal-fired power plants would
reduce human exposure. Nevertheless, the EPA determined in 2000 that regulation
of mercury emissions from coal-fired power plants was appropriate. In December
2003, the EPA proposed and solicited comment on two alternative control plans
that would limit mercury emissions from coal-fired power plants. The agency has
indicated that it will choose one of the alternatives as the final rule, which
is expected to be promulgated in December 2004. Achieving compliance with either
proposal could involve significant capital costs. The Company cannot predict the
outcome of this matter.
In conjunction with the proposed mercury rule, the EPA proposed a Maximum
Achievable Control Technology (MACT) standard to regulate nickel emissions from
residual oil-fired units. The agency estimates the proposal will reduce national
nickel emissions to approximately 103 tons. The rule is expected to become final
in December 2004. The company cannot predict the outcome of this matter.
In December 2003, the EPA released its proposed Interstate Air Quality Rule
(commonly known as the Fine Particulate Transport Rule and/or the Regional
Transport Rule). The EPA's proposal requires 28 jurisdictions, including North
Carolina, South Carolina, Georgia and Florida, to further reduce NOx and SO2
emissions in order to attain pre-set state NOx and SO2 emissions levels (which
have not yet been determined). The rule is expected to become final in 2004. The
installation of controls necessary to comply with the rule could involve
significant capital costs. The Company cannot predict the outcome of this
matter.
WATER QUALITY
As a result of the operation of certain control equipment needed to address the
air quality issues outlined above, new wastewater streams may be generated.
Integration of these new wastewater streams into existing wastewater treatment
processes may result in permitting, construction and water treatment challenges
to the Company in the immediate and extended future.
After many years of litigation and settlement negotiations the EPA published
final regulations in February 2004 for the implementation of Section 316(b) of
the Clean Water Act. The purpose of these regulations is to minimize any adverse
environmental impact caused by cooling water intake structures and intake
systems located at existing facilities. Over the next several years these
regulations may require the facilities to mitigate the effects to aquatic
organisms by undertaking intake modifications or other restorative activities.
Substantial costs could be incurred by the facilities in order to comply with
the new regulations. The Company cannot predict the outcome and impacts to the
facilities at this time or its cost to comply with any new regulations.
SUPERFUND
The provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
clean up of hazardous waste sites. This statute imposes retroactive joint and
several liabilities. Some states, including North and South Carolina, have
similar types of legislation. There are presently several sites with respect to
which the Company has been notified by the EPA, the State of North Carolina or
the State of Florida of its potential liability, as described below in greater
detail.
Various organic materials associated with the production of manufactured gas,
generally referred to as coal tar, are regulated under federal and state laws.
The lead or sole regulatory agency that is responsible for a particular former
coal tar site depends largely upon the state in which the site is located. There
are several manufactured gas plant (MGP) sites to which both electric utilities
have some connection. In this regard, both electric utilities, with other
potentially responsible parties (PRP), are participating in investigating and,
if necessary, remediating former coal tar sites with several regulatory
agencies, including, but not limited to, the EPA, the Florida Department of
Environmental Protection (FDEP) and the North Carolina Department of Environment
and Natural Resources, Division of Waste Management (DWM). Although the Company
may incur costs at these sites about which it has been notified, based upon the
current status of these sites, the Company cannot predict the outcome of this
matter.
15
Both electric utilities, Progress Fuels and Progress Rail Services Corporation
(Progress Rail) are periodically notified by regulators such as the EPA and
various state agencies of their involvement or potential involvement in sites,
other than MGP sites, that may require investigation and/or remediation.
Although the Company's subsidiaries may incur costs at the sites about which
they have been notified, based upon the current status of these sites, the
Company cannot predict the outcome of this matter.
EMPLOYEES
As of January 31, 2004, Progress Energy and its subsidiaries employed
approximately 15,300 full-time employees. Of this total, approximately 2,200
employees at PEF are represented by the International Brotherhood of Electrical
Workers (IBEW). PEF and the IBEW reached agreement in December 2002 on a new
three-year labor contract.
The Company and some of its subsidiaries have a non-contributory defined benefit
retirement (pension) plan for substantially all full-time employees and an
employee stock purchase plan among other employee benefits. The Company and some
of its subsidiaries also provide contributory postretirement benefits, including
certain health care and life insurance benefits, for substantially all retired
employees.
As of January 31, 2004, PEC employed approximately 5,200 full-time employees.
ELECTRIC - PEC
GENERAL
PEC is a public service corporation formed under the laws of North Carolina in
1926, and is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North and South Carolina. At December 31,
2003, PEC had a total summer generating capacity (including jointly-owned
capacity) of approximately 12,416 MW.
PEC distributes and sells electricity in 56 of the 100 counties in North
Carolina and 15 counties in northeastern South Carolina. The territory served is
an area of approximately 34,000 square miles, including a substantial portion of
the coastal plain of North Carolina extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont section of North
Carolina, an area in northeastern South Carolina and an area in western North
Carolina in and around the city of Asheville. The estimated total population of
the territory served is more than 4.0 million. At December 31, 2003, PEC was
providing electric services, retail and wholesale, to approximately 1.3 million
customers. Major wholesale power sales customers include North Carolina Eastern
Municipal Power Agency (Power Agency) and North Carolina Electric Membership
Corporation. PEC is subject to the rules and regulations of the FERC, the NCUC
and the SCPSC.
BILLED ELECTRIC REVENUES
PEC's electric revenues billed by customer class, for the last three years, are
shown as a percentage of total PEC electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2003 2002 2001
------------- ---- ---- ----
Residential 35% 35% 34%
Commercial 24% 24% 23%
Industrial 18% 18% 19%
Wholesale 19% 19% 19%
Other retail 4% 4% 5%
Major industries in PEC's service area include textiles, chemicals, metals,
paper, food, rubber and plastics, wood products and electronic machinery and
equipment.
16
FUEL AND PURCHASED POWER
Sources of Generation
PEC's total system generation (including jointly-owned capacity) by primary
energy source, along with purchased power, for the last three years is set forth
below:
ENERGY MIX PERCENTAGES
2003 2002 2001
---- ---- ----
Coal 46% 46% 49%
Nuclear 44% 42% 41%
Hydro 1% 1% 0%
Oil/Gas 2% 3% 2%
Purchased power 7% 8% 8%
PEC is generally permitted to pass the cost of recoverable fuel and purchased
power to its customers through fuel adjustment clauses. The future prices for
and availability of various fuels discussed in this report cannot be predicted
with complete certainty. However, PEC believes that its fuel supply contracts,
as described below, will be adequate to meet its fuel supply needs.
PEC's average fuel costs per million British thermal units (Btu) for the last
three years were as follows:
AVERAGE FUEL COST
(per million Btu)
2003 2002 2001
---- ---- ----
Coal $ 2.00 $ 1.93 $ 1.78
Nuclear 0.43 0.43 0.44
Hydro - - -
Oil 6.69 5.48 6.38
Gas 8.32 5.31 4.69
Weighted-average 1.43 1.38 1.26
Changes in the unit price for oil and gas are due to market conditions. Changes
in the unit price for coal between 2001 and 2002 are primarily due to
transportation costs. Changes in the unit price for coal between 2002 and 2003
are being driven by increases in market prices for coal in 2003. Since these
costs are primarily recovered through recovery clauses established by
regulators, fluctuations do not materially affect net income.
Coal
PEC anticipates a requirement of approximately 11.3 million to 11.6 million tons
of coal in 2004. Almost all of the coal will be supplied from Appalachian coal
sources in the United States and is primarily delivered by rail.
For 2004, PEC has short-term, intermediate and long-term agreements from various
sources for approximately 83% of its burn requirements of its coal units. Two of
these contracts are index priced and the remainder are annually fixed price. The
contracts have expiration dates ranging from 2004 to 2008. PEC will continue to
sign contracts of various lengths, terms and quality to meet its expected burn
requirements. All of the coal that PEC has purchased under intermediate and
long-term agreements is considered to be low sulfur coal by industry standards.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a uranium oxide
concentrate and the conversion of this concentrate into uranium hexafluoride.
Stages III and IV entail the enrichment of the uranium hexafluoride and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
17
PEC has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement needs. PEC typically contracts for
all of its enrichment services and fabrication needs with contract durations
ranging from five to ten years. Recent shutdown of a major North American
conversion facility and increased uncertainty of uranium supply has raised the
risk of supply disruption. As a result, Progress Energy has adjusted its nuclear
fuel inventory and procurement strategy accordingly to offset increased supply
disruption risk by increasing planned delivery lead times and strategic
inventory stockpiles. For a discussion of PEC's plans with respect to spent fuel
storage, see PART I, ITEM 1, "Nuclear Matters."
Hydroelectric
Hydroelectric power is electric energy generated by the force of falling water.
PEC has three hydroelectric generating plants licensed by the FERC: Walters,
Tillery and Blewett. PEC also owns the Marshall Plant which has a license
exemption. The total maximum dependable capacity for these units is 218 MW. PEC
is seeking to relicense its Tillery and Blewett Plants. These plants' licenses
currently expire in April 2008. The Walters Plant license will expire in 2034.
Oil & Gas
Natural gas and oil supply for PEC's generation fleet is purchased under term
and spot contracts from several suppliers. The cost of PEC's oil and gas is
determined by market prices as reported in certain industry publications. PEC
believes that it has access to an adequate supply of oil for the reasonably
foreseeable future. PEC's natural gas transportation is purchased under term
firm transportation contracts with interstate pipelines. PEC also purchases
capacity on a seasonal basis from numerous shippers for its peaking load
requirements. PEC believes that existing contracts for oil are sufficient to
cover its requirements if natural gas is unavailable during a normal winter
period for PEC's combustion turbine and combined cycle fleet.
Purchased Power
PEC purchased approximately 4.5 million MWh in 2003, approximately 5.2 million
MWh in 2002 and approximately 5.3 million MWh in 2001 of its system energy
requirements and had available 1,810 MW in 2003, 1,737 MW in 2002 and 1,756 MW
in 2001 of firm purchased capacity under contract at the time of peak load. PEC
may acquire purchased power capacity in the future to accommodate a portion of
its system load needs.
COMPETITION
Electric Industry Restructuring
PEC continues to monitor any developments that occur toward a more competitive
environment and has actively participated in regulatory reform deliberations in
North Carolina and South Carolina. PEC expects that both the North Carolina and
South Carolina General Assemblies will continue to monitor the experiences of
states that have implemented electric restructuring legislation.
Regional Transmission Organizations
In October 2000, as a result of Order 2000, PEC, along with Duke Energy
Corporation and South Carolina Electric & Gas Company, filed an application with
the FERC for approval of a GridSouth RTO. In July 2001, the FERC issued an order
provisionally approving GridSouth. However, in July 2001, the FERC issued orders
recommending that companies in the southeast engage in a mediation to develop a
plan for a single RTO for the Southeast. PEC participated in the mediation. The
FERC has not issued an order specifically on this mediation.
See PART II, ITEM 7, "Other Matters" for additional discussion of current
developments of GridSouth RTO.
Standard Market Design
See PART I, ITEM 1, "General," under Competition for further discussion of
Standard Market Design developments.
18
Franchises
PEC has nonexclusive franchises with varying expiration dates in most of the
municipalities in which it distributes electric energy in North Carolina and
South Carolina. Of these 239 franchises, 194 have expiration dates ranging from
2008 to 2061 and 45 of these have no specific expiration dates. All but 13 of
the 194 franchises with expiration dates have a term of sixty years. The
exceptions include three franchises with terms of ten years, one with a term of
twenty years, six with terms of thirty years, two with terms of forty years and
one with a term of fifty years. PEC also serves within a number of
municipalities and in all of its unincorporated areas without franchise
agreements.
Wholesale Competition
See PART I, ITEM 1, "General," under Competition for a discussion of wholesale
competition.
Stranded Costs
See PART I, ITEM 1, "General," under Competition for a discussion of stranded
costs.
REGULATORY MATTERS
Retail Rate Matters
The NCUC and the SCPSC authorize retail "base rates" that are designed to
provide a utility with the opportunity to earn a specific rate of return on its
"rate base," or investment in utility plant. These rates are intended to cover
all reasonable and prudent expenses of utility operations and to provide
investors with a fair rate of return. In PEC's most recent rate cases in 1988,
the NCUC and the SCPSC each authorized a return on equity of 12.75% for PEC.
Legislation enacted in North Carolina in 2002 freezes PEC's base retail rates
for five years unless there are extraordinary events beyond the control of PEC,
in which case PEC can petition for a rate increase. See PART II, ITEM 8, Note
21E to the Progress Energy Consolidated Financial Statements and Note 16D to the
PEC Consolidated Financial Statements for further discussion of PEC's rate
freeze.
See PART II, ITEM 8, Note 7B to the Progress Energy Consolidated Financial
Statements and Note 5B to the PEC Consolidated Financial Statements for further
discussion of PEC's retail rate developments during 2003.
Wholesale Rate Matters
PEC is subject to regulation by the FERC with respect to rates for transmission
and sale of electric energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the event of certain
emergency situations), the licensing and operation of hydroelectric projects
and, to the extent the FERC determines, accounting policies and practices. PEC
and its wholesale customers last agreed to a general increase in wholesale rates
in 1988; however, wholesale rates have been adjusted since that time through
contractual negotiations.
Fuel Cost Recovery
PEC's operating costs not covered by the utility's base rates include fuel and
purchased power. Each state commission allows electric utilities to recover
certain of these costs through various cost recovery clauses; to the extent the
respective commission determines in an annual hearing that such costs are
prudent. Costs recovered by PEC, by state, are as follows:
o North Carolina - fuel costs and the fuel portion of purchased power
o South Carolina - fuel costs, certain purchased power costs and
emission allowance expense
Each state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
19
NUCLEAR MATTERS
PEC is currently implementing power uprate projects at its nuclear facilities to
increase electrical generation output. A power uprate was completed at the
Harris Plant during 2001 and at the Robinson Nuclear Plant in 2002. Power
uprates are also in progress at the Brunswick Plant. Brunswick Unit 1 increased
its capacity by 52 MW in 2002 and Brunswick 2 increased its capacity by 89 MW in
2003. Additional increases will be implemented in phases over the next couple of
years. The total increased generation from all these projects is estimated to be
approximately 290 MW. See PART I, ITEM 1, "Nuclear Matters," for further
discussion of these and other nuclear matters.
ENVIRONMENTAL MATTERS
There are nine former MGP sites and other sites associated with PEC that have
required or are anticipated to require investigation and/or remediation costs.
In September 2003, the Company sold NCNG to Piedmont Natural Gas Company, Inc.
As part of the sales agreement, the Company retained responsibility to remediate
five former NCNG MGP sites to state standards pursuant to an Administrative
Order by consent. At the time of the sale, the liability for these costs and the
related accrual was transferred to PEC. Presently, PEC cannot determine the
total costs that may be incurred in connection with the remediation of any of
these MGP sites. See PART II, ITEM 8, Note 21E to the Progress Energy
Consolidated Financial Statements and Note 16D to the PEC Consolidated Financial
Statements for further discussion of these environmental matters.
ELECTRIC - PEF
GENERAL
PEF was incorporated in Florida in 1899, and is an operating public utility
engaged in the generation, purchase, transmission, distribution and sale of
electricity. At December 31, 2003, PEF had a total summer generating capacity
(including jointly-owned capacity) of approximately 8,544 MW.
PEF provided electric service during 2003 to an average of 1.5 million customers
in west central Florida. Its service area covers approximately 20,000 square
miles and includes the densely populated areas around Orlando, as well as the
cities of St. Petersburg and Clearwater. PEF is interconnected with 20 municipal
and nine rural electric cooperative systems. Major wholesale power sales
customers include Seminole Electric Cooperative, Inc., Florida Municipal Power
Agency, Florida Power & Light Company and Tampa Electric Company. PEF is subject
to the rules and regulations of the FERC and the FPSC.
BILLED ELECTRIC REVENUES
PEF's electric revenues billed by customer class for the last three years, are
shown as a percentage of total PEF electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2003 2002 2001
------------- ---- ---- ----
Residential 55% 55% 54%
Commercial 24% 24% 24%
Industrial 7% 7% 7%
Others 6% 6% 6%
Wholesale 8% 8% 9%
Important industries in PEF's territory include phosphate rock mining and
processing, electronics design and manufacturing, and citrus and other food
processing. Other important commercial activities are tourism, health care,
construction and agriculture.
20
FUEL AND PURCHASED POWER
General
PEF's consumption of various types of fuel depends on several factors, the most
important of which are the demand for electricity by PEF's customers, the
availability of various generating units, the availability and cost of fuel and
the requirements of federal and state regulatory agencies. PEF's energy mix for
the last three years is presented in the following table:
ENERGY MIX PERCENTAGES
Fuel Type 2003 2002 2001
--------- ---- ---- ----
Coal (a) 36% 33% 33%
Oil 16% 16% 16%
Nuclear 14% 15% 15%
Gas 13% 15% 14%
Purchased Power 21% 21% 22%
(a) Amounts include synthetic fuel from unrelated third parties and petroleum
coke.
PEF is generally permitted to pass the cost of recoverable fuel and purchased
power to its customers through fuel adjustment clauses. The future prices for
and availability of various fuels discussed in this report cannot be predicted
with complete certainty. However, PEF believes that its fuel supply contracts,
as described below, will be adequate to meet its fuel supply needs.
PEF's average fuel costs per million Btu for the last three years were as
follows:
AVERAGE FUEL COST
(per million Btu)
2003 2002 2001
------ ------ ------
Coal (a) $ 2.42 $ 2.43 $ 2.16
Oil 4.38 3.77 3.81
Nuclear 0.50 0.46 0.47
Gas 5.98 4.06 4.52
Weighted-average 3.07 2.60 2.59
(a) Amounts include synthetic fuel from unrelated third parties and petroleum
coke.
Changes in the unit price for coal, oil and gas are due to market conditions.
Since these costs are primarily recovered through recovery clauses established
by regulators, fluctuations do not materially affect net income.
Coal
PEF anticipates a combined requirement of approximately 6.0 million to 6.5
million tons of coal in 2004. Most of the coal is expected to be supplied from
Appalachian coal sources in the United States. Approximately two-thirds of the
fuel is expected to be delivered by rail and the remainder by barge. All of this
fuel is supplied by Progress Fuels, a subsidiary of Progress Energy, pursuant to
contracts between PEF and Progress Fuels.
For 2004, Progress Fuels has medium-term and long-term contracts with various
sources for approximately 100% of the burn requirements of PEF's coal units.
These contracts have price adjustment provisions and have expiration dates
ranging from 2004 to 2006. Progress Fuels will continue to sign contracts of
various lengths, terms and quality to meet PEF's expected burn requirements. All
the coal to be purchased for PEF is considered to be low sulfur coal by industry
standards.
Oil and Gas
Natural gas and oil supply for PEF's generation fleet is purchased under term
and spot contracts from several suppliers. The majority of the cost of PEF's oil
and gas is determined by market prices as reported in certain industry
publications. PEF believes that it has access to an adequate supply of oil for
the reasonably foreseeable future. PEF's natural gas transportation is purchased
under term firm transportation contracts with interstate pipelines. PEF also
purchases capacity on a seasonal basis from numerous shippers and interstate
21
pipelines to serve its peaking load requirements. PEF also uses interruptible
transportation contracts on certain occasions when available. PEF believes that
existing contracts for oil are sufficient to cover its requirements if natural
gas is unavailable during certain time periods.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a uranium oxide
concentrate and the conversion of this concentrate into uranium hexafluoride.
Stages III and IV entail the enrichment of the uranium hexafluoride and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
PEF has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirements needs. PEF typically contracts for
all of its future long-term uranium, conversion and enrichment service needs
with contract durations ranging from five to ten years. Recent shutdown of a
major North American conversion facility and increased uncertainty of uranium
supply has raised the risk of supply disruption. As a result, Progress Energy
has adjusted its nuclear fuel inventory and procurement strategy accordingly to
offset increased supply disruption risk by increasing planned delivery lead
times and strategic inventory stockpiles.
Purchased Power
PEF, along with other Florida utilities, buys and sells power in the wholesale
market on a short-term and long-term basis. At December 31, 2003, PEF had a
variety of purchase power agreements for the purchase of approximately 1,313 MW
of firm power. These agreements include (1) long-term contracts for the purchase
of about 474 MW of purchased power with other investor-owned utilities,
including a contract with The Southern Company for approximately 414 MWs, and
(2) approximately 839 MWs of capacity under contract with certain QFs. The
capacity currently available from QFs represents about 10% of PEF's total
installed system capacity.
COMPETITION
Electric Industry Restructuring
PEF continues to monitor developments toward a more competitive environment and
has actively participated in regulatory reform deliberations in Florida.
Movement toward deregulation in this state has been affected by developments
related to deregulation of the electric industry in other states.
In response to a legislative directive, the FPSC and the FDEP submitted in
February 2003 a joint report on renewable electric generating technologies for
Florida. The report assessed the feasibility and potential magnitude of
renewable electric capacity for Florida, and summarized the mechanisms other
states have adopted to encourage renewable energy. The report did not contain
any policy recommendations. The Company cannot anticipate when, or if,
restructuring legislation will be enacted or if the Company would be able to
support it in its final form.
Regional Transmission Organizations
As a result of Order 2000, PEF, along with Florida Power & Light Company and
Tampa Electric Company (the Applicants) filed with the FERC in October 2000 an
application for approval of a GridFlorida RTO. The GridFlorida proposal is
pending before both the FERC and the FPSC. The FERC provisionally approved the
structure and governance of GridFlorida. The Commission's most recent order in
December 2003 ordered further state proceedings. It is unknown when the FERC or
the FPSC will take final action with regard to the status of GridFlorida or what
the impact of further proceedings will have on the Company's earnings, revenues
or pricing. See PART II, ITEM 7, "Other Matters," for a discussion of current
developments of GridFlorida RTO.
Standard Market Design
See PART I, ITEM 1, "General," under Competition for further discussion of
standard market design developments.
22
Franchise Agreements
PEF holds franchises with varying expiration dates in 107 of the municipalities
in which it distributes electric energy. PEF also serves 14 other municipalities
and in all its unincorporated areas without franchise agreements. The general
effect of these franchises is to provide for the manner in which PEF occupies
rights-of-way in incorporated areas of municipalities for the purpose of
constructing, operating and maintaining an energy transmission and distribution
system.
Approximately 44% of PEF's total utility revenues for 2003 were from the
incorporated areas of the 107 municipalities that had franchise ordinances
during the year. Since 2000, PEF has renewed 32 expiring franchises and reached
agreement on a franchise with a city that did not previously have a franchise.
Franchises with five municipalities have expired without renewal.
All but 26 of the existing franchises cover a 30-year period from the date
enacted. The exceptions are 22 franchises, each with a term of 10 years and
expiring between 2005 and 2012; two franchises each with a term of 15 years and
expiring in 2017; one 30-year franchise that was extended in 1999 for five years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 107 franchises, 36 expire between January 1, 2004 and December 31, 2012 and
71 expire between January 1, 2013 and December 31, 2034.
Ongoing negotiations and, in some cases, litigation are taking place with
certain municipalities to reach agreement on franchise terms and to enact new
franchise ordinances. See PART II, ITEM 7, "Other Matters," for a discussion of
PEF's franchise litigation.
Stranded Costs
The largest stranded cost exposure for PEF is its commitment to QFs. PEF has
taken a proactive approach to this industry issue. PEF continues to seek ways to
address the impact of escalating payments from contracts it was obligated to
sign under provisions of PURPA. See PART I, ITEM 1, "General," under Competition
for further discussion.
Wholesale Competition
See PART I, ITEM 1, "General," under Competition for a discussion of wholesale
competition.
REGULATORY MATTERS
General
PEF is subject to the jurisdiction of the FPSC with respect to, among other
things, rates and service for electric energy sold at retail, retail service
territory and issuances of securities. In addition, PEF is subject to regulation
by the FERC with respect to transmission and sales of wholesale power,
accounting and certain other matters. The underlying concept of utility
ratemaking is to set rates at a level that allows the utility to collect
revenues equal to its cost of providing service plus a reasonable rate of return
on its equity. Increased competition as a result of industry restructuring may
affect the ratemaking process.
Retail Rate Matters
The FPSC authorizes retail "base rates" that are designed to provide a utility
with the opportunity to earn a specific rate of return on its "rate base," or
average investment in utility plant. These rates are intended to cover all
reasonable and prudent expenses of utility operations and to provide investors
with a fair rate of return.
In March 2002, the parties in PEF's rate case entered into a Stipulation and
Settlement Agreement (the Agreement) related to retail rate matters. The
Agreement was approved by the FPSC and is generally effective from May 1, 2002
through December 31, 2005. The Agreement eliminates the authorized Return on
Equity (ROE) range normally used by the FPSC for the purpose of addressing
earning levels; provided, however, that if PEF's base rate earnings fall below a
10% return on equity, PEF may petition the FPSC to amend its base rates. The
Agreement is described in more detail in PART II, ITEM 8, Note 7D to the
Progress Energy Consolidated Financial Statements.
23
Fuel and Other Cost Recovery
PEF's operating costs not covered by the utility's base rates include fuel,
purchased power, energy conservation expenses and specific environmental costs.
The state commission allows electric utilities to recover certain of these costs
through various cost recovery clauses, to the extent the respective commission
determines in an annual hearing that such costs are prudent. In addition, in
December 2002, the FPSC approved an Environmental Cost Recovery Clause (ECRC)
which permits the Company to recover the costs of specified environmental
projects to the extent these expenses are found to be prudent in an annual
hearing and not otherwise included in base rates. Costs are recovered through
this recovery clause in the same manner as the other existing clause mechanisms.
The state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
In late 2002, CR3 received a license amendment authorizing a small power level
increase. The power level increase of approximately four MW was implemented in
February 2003.
See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other
nuclear matters.
ENVIRONMENTAL MATTERS
There are two former MGP sites and other sites associated with PEF that have
required or are anticipated to require investigation and/or remediation costs.
In addition, there are distribution substations and transformers which are also
anticipated to incur investigation and remediation costs. Presently, PEF cannot
determine the total costs that may be included in connection with the
remediation of all sites. See PART II, ITEM 8, Note 21E to the Progress Energy
Consolidated Financial Statements for further discussion of these environmental
matters.
FUELS
The Fuels business segment owns an array of assets that produce, transport and
deliver fuel and provide related services for the open market. The Fuels
business segment has subsidiaries that produce natural gas and oil products,
blend and transload coal, mine coal, and others that produce a solid coal-based
synthetic fuel. This product has been classified as a synthetic fuel within the
meaning of Section 29. Sales of synthetic fuel therefore qualify for tax
credits. See PART II, ITEM 7, "Other Matters," for a discussion of the synthetic
fuel tax credits.
The current combined assets of Fuels which are involved in fuel extraction,
manufacturing and delivery include:
o Natural gas properties in Texas and Louisiana producing about 30 Bcf
per year;
o Five terminals on the Ohio River and its tributaries, part of the
trucking, rail and barge network for coal delivery;
o Three coal-mining complexes, expected to produce about 3 million tons
per year:
o Five wholly-owned synthetic fuel entities, and a 10% minority interest
in one synthetic fuel entity, capable of producing up to 18 million
tons per year;
o Majority-ownership in a barge partnership that moves coal products
from the mouth of the Mississippi River to the CR3 facility in
Florida.
During 2003, Progress Fuels acquired approximately 200 natural gas-producing
wells with proven reserves of approximately 190 Bcf from Republic Energy, Inc.
and three other privately-owned companies, all headquartered in Texas. The total
cash purchase price for the transactions was approximately $168 million. See
PART II, ITEM 8, Note 4B to the Progress Energy Consolidated Financial
Statements.
24
COMPETITION
Fuels' synthetic fuel operations and coal operations compete in the eastern
United States industrial coal markets. Factors contributing to the success in
these markets include a competitive cost structure and strategic locations.
There are, however, numerous competitors in each of these markets, although no
one competitor is dominant in any industry.
Fuels' gas production operations compete in the East Texas, North Texas and
North Louisiana region. Factors contributing to success include a competitive
cost structure. Although there are numerous small, independent competitors in
this market, the major oil and gas producers dominate this industry.
ENVIRONMENTAL MATTERS
See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial
Statements for a discussion of Fuel's environmental matters.
COMPETITIVE COMMERCIAL OPERATIONS (CCO)
CCO sells capacity and energy on the wholesale market outside the realm of
retail regulation. CCO currently owns six plants with approximately 3,100 MW of
generation capacity. CCO has contracts representing 85% of planned production
capacity for 2004 and 50% of planned production capacity for 2005 and 2006.
In May 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of the Williams Companies, Inc., a long-term full-requirements power
supply agreement at fixed prices with Jackson, for $188 million.
CCO is responsible for marketing the energy produced by the nonregulated plants.
The energy is sold under both term contracts and in the spot market. CCO markets
the nonregulated plants not under contract into the nonregulated market and
engages in limited financial trading activities primarily for hedging the fuel
and economic value of its generation portfolio. CCO is also responsible for
purchasing fuel for the merchant generation fleet, such as natural gas and oil.
CCO also uses financial instruments to manage the risks associated with
fluctuating commodity prices and increase the value of the Company's power
generation assets.
COMPETITION
CCO does not operate in the same environment as regulated utilities. It operates
specifically in the wholesale market, which means competition is its primary
driver. CCO competes in the eastern United States utility markets. Factors
contributing to the success in these markets include a competitive cost
structure and strategic locations.
RAIL SERVICES
The Rail Services business segment, led by Progress Rail, is one of the largest
integrated and diversified suppliers of railroad and transit system products and
services in North America and is headquartered in Albertville, Alabama. Rail
Services' principal business functions include two business units: Locomotive
and Railcar Services (LRS) and Engineering and Trackwork (E&TW).
The LRS unit is primarily focused on railroad rolling stock that includes
freight cars, transit cars and locomotives, the repair and maintenance of these
units, the manufacturing or reconditioning of major components for these units
and scrap metal recycling. The E&TW unit focuses on rail and other track
components, the infrastructure which supports the operation of rolling stock,
and the equipment used in maintaining the railroad infrastructure and
right-of-way. The Recycling division of the LRS unit supports both business
units through its reclamation of reconditionable material and is a major
supplier of recyclable scrap metal to North American steel mills and foundries
through its processing locations as well as its scrap brokerage operations.
Rail Services' key railroad industry customers are Class 1 railroads, regional
and short line railroads, North American transit systems, railcar and locomotive
builders, and railcar lessors. The U.S. operations are located in 23 states and
include further geographic coverage through mobile crews on a selected basis.
This coverage allows for Rail Services' customer base to be dispersed throughout
the U.S., Canada and Mexico.
25
In March 2003, the Company signed a letter of intent to sell the majority of
Railcar Ltd. assets to the Andersons, Inc. A definitive purchase agreement was
signed in November 2003 and the transaction closed in February 2004. See PART
II, ITEM 8, Note 3B to the Progress Energy Consolidated Financial Statements for
a discussion of this transaction.
ENVIRONMENTAL MATTERS
See PART II, ITEM 8, Note 21E to the Progress Energy Consolidated Financial
Statements for a discussion of Rail's environmental matters.
OTHER
GENERAL
The Other Businesses segment primarily includes the operations of PTC LLC and
Strategic Resource Solutions Corp. (SRS). This segment also includes other
nonregulated operations of PEC and FPC.
PROGRESS TELECOM LLC
In December 2003, PTC and Caronet, both wholly-owned subsidiaries of Progress
Energy, and EPIK, a wholly-owned subsidiary of Odyssey, contributed
substantially all of their assets and transferred certain liabilities to PTC
LLC, a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an
affiliate of Odyssey for $2 million in cash and Caronet became a wholly-owned
subsidiary of Odyssey. Following consummation of all the transactions described
above, PTC holds a 55 percent ownership interest in, and is the parent, of PTC
LLC; Odyssey holds a combined 45 percent ownership interest in PTC LLC through
EPIK and Caronet. The accounts of PTC LLC are included in the Company's
Consolidated Financial Statements since the transaction date.
PTC LLC has data fiber network transport capabilities that stretch from New York
to Miami, Florida, with gateways to Latin America and conducts primarily a
carrier's carrier business. PTC LLC markets wholesale fiber-optic-based capacity
service in the Eastern United States to long-distance carriers, internet service
providers and other telecommunications companies. PTC LLC also markets wireless
structure attachments to wireless communication companies and governmental
entities. At December 31, 2003, PTC LLC owned and managed more than 8,500 route
miles and more than 420,000 fiber miles of fiber-optic cable.
PTC LLC competes with other providers of fiber-optic telecommunications
services, including local exchange carriers and competitive access providers, in
the Eastern United States.
Lease revenue for dedicated transport and data services is generally billed in
advance on a fixed rate basis and recognized over the period the services are
provided. Revenues relating to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
For additional information regarding asset and investment impairments related to
the Company's investments in the telecommunications industry, see PART II, ITEM
8, Note 9 to the Progress Energy Consolidated Financial Statements, and Note 6
to the PEC Consolidated Financial Statements.
NCNG
In October 2002, the Company approved the sale of NCNG. In September 2003, the
Company completed the sale of NCNG and the Company's equity investment in ENCNG
to Piedmont Natural Gas Company, Inc. See PART II, ITEM 8, Note 3A to the
Progress Energy Consolidated Financial Statements for further discussion of this
transaction.
26
ELECTRIC UTILITY OPERATING STATISTICS - PROGRESS ENERGY
Years Ended December 31
2003 2002 2001 2000(d) 1999
------------ ----------- ----------- ----------- ----------
Energy supply (millions of kilowatt-hours)
Generated - Steam 51,501 49,734 48,732 31,132 28,260
Nuclear 30,576 30,126 27,301 23,857 22,451
Hydro 955 491 245 441 520
Combustion Turbines/Combined Cycle 7,819 8,522 6,644 1,337 435
Purchased 13,848 14,305 14,469 5,724 5,132
------------ ----------- ----------- ----------- ----------
Total energy supply (Company share) 104,699 103,178 97,391 62,491 56,798
Jointly-owned share (a) 5,213 5,258 4,886 4,505 4,353
------------ ----------- ----------- ----------- ----------
Total system energy supply 109,912 108,436 102,277 66,996 61,151
============ =========== =========== =========== ==========
Average fuel cost (per million Btu)
Fossil $ 2.94 $ 2.62 $ 2.46 $ 1.96 $ 1.75
Nuclear fuel $ 0.44 $ 0.44 $ 0.45 $ 0.45 $ 0.46
All fuels $ 2.05 $ 1.84 $ 1.77 $ 1.30 $ 1.16
Energy sales (millions of kilowatt-hours)
Retail
Residential 34,712 33,993 31,976 15,365 13,348
Commercial 24,110 23,888 23,033 12,221 11,068
Industrial 16,749 16,924 17,204 14,762 14,568
Other Retail 4,382 4,287 4,149 1,626 1,359
Wholesale 19,841 19,204 17,715 15,012 14,526
Unbilled 189 275 (1,045) 1,098 (110)
------------ ----------- ----------- ----------- ----------
Total energy sales 99,983 98,571 93,032 60,084 54,759
Company uses and losses 3,753 3,604 3,478 2,286 2,039
------------ ----------- ----------- ----------- ----------
Total energy requirements 103,736 102,175 96,510 62,370 56,798
============ =========== =========== =========== ==========
Electric revenues (in millions)
Retail $ 5,620 $ 5,515 $ 5,462 $ 2,799 $ 2,531
Wholesale 915 881 923 665 556
Miscellaneous revenue 206 205 172 81 60
-------------- ----------- ----------- ----------- ----------
Total electric revenues $ 6,741 $ 6,601 $ 6,557 $ 3,545 $ 3,147
============ =========== =========== =========== ==========
Peak demand of firm load (thousands of kW)
System (b) 19,876 20,365 19,166 18,874 10,948
Company 19,235 19,746 18,564 18,272 10,344
Total regulated capability at year-end (thousands of kW)
Fossil plants 16,522 16,006 15,826 (e) 14,747 6,736
Nuclear plants 4,220 (g) 4,127 (f) 4,008 4,008 3,174
Hydro plants 218 218 218 218 218
Purchased 2,826 2,929 2,890 2,278 1,088
------------ ----------- ----------- ---------- ---------
Total system capability 23,786 23,280 22,942 21,251 11,216
Less jointly-owned portion (c) 698 682 668 662 593
------------ ----------- ----------- ---------- ---------
Total Company capability - regulated 23,088 22,598 22,274 20,589 10,623
============ =========== =========== ========== =========
(a) Amounts represent co-owner's share of the energy supplied from the six
generating facilities that are jointly owned.
(b) For 2000 - 2003, this represents the combined summer non-coincident system
net peaks for PEC and PEF.
(c) For PEC, this represents Power Agency's retained share of jointly-owned
facilities per the Power Coordination Agreement between PEC and Power
Agency.
(d) Amounts include information for PEF since November 30, 2000, the date of
acquisition.
(e) Amount includes 459 MW related to Rowan units that were transferred to PVI
in February 2002.
(f) Amount includes power uprates for Harris, Brunswick 1 and Robinson. The
Maximum Dependable Capability (MDC) for Harris was restated January 2002;
the MDCs for Brunswick 1 and Robinson were restated January 2003.
(g) Amount includes power uprates for CR3 and Brunswick 2. The MDC's were
restated January 2004.
27
OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS
Years Ended December 31
2003 2002 2001 2000 1999
----------- ----------- ----------- ----------- ---------
Energy supply (millions of kilowatt-hours)
Generated - Steam 28,522 28,547 27,913 29,520 28,260
Nuclear 24,537 23,425 21,321 23,275 22,451
Hydro 955 491 245 441 520
Combustion Turbines/Combined Cycle 1,344 1,934 802 733 435
Purchased 4,467 5,213 5,296 4,878 5,132
----------- ----------- ----------- ----------- ---------
Total energy supply (Company share) 59,825 59,610 55,577 58,847 56,798
Power Agency share (a) 4,670 4,659 4,348 4,505 4,353
----------- ----------- ----------- ----------- ---------
Total system energy supply 64,495 64,269 59,925 63,352 61,151
=========== =========== =========== =========== =========
Average fuel cost (per million Btu)
Fossil $ 2.29 $ 2.16 $ 1.91 $ 1.83 $ 1.75
Nuclear fuel $ 0.43 $ 0.43 $ 0.44 $ 0.45 $ 0.46
All fuels $ 1.43 $ 1.38 $ 1.26 $ 1.21 $ 1.16
Energy sales (millions of kilowatt-hours)
Retail
Residential 15,283 15,239 14,372 14,091 13,348
Commercial 12,557 12,468 11,972 11,432 11,068
Industrial 12,749 13,089 13,332 14,446 14,568
Other Retail 1,408 1,437 1,423 1,423 1,359
Wholesale 15,518 15,024 12,996 14,582 14,526
Unbilled (44) 270 (534) 679 (110)
----------- ----------- ----------- ----------- ---------
Total energy sales 57,471 57,527 53,561 56,653 54,759
Company uses and losses 2,354 2,083 2,016 2,194 2,039
----------- ----------- ----------- ----------- ---------
Total energy requirements 59,825 59,610 55,577 58,847 56,798
=========== =========== =========== =========== =========
Electric revenues (in millions)
Retail $ 2,825 $ 2,795 $ 2,666 $ 2,609 $ 2,531
Wholesale 687 652 634 577 556
Miscellaneous revenue 77 92 44 122 59
----------- ----------- ----------- ----------- ---------
Total electric revenues $ 3,589 $ 3,539 $ 3,344 $ 3,308 $ 3,146
=========== =========== =========== =========== =========
Peak demand of firm load (thousands of kW)
System 11,771 11,977 11,376 11,157 10,948
Company 11,130 11,358 10,774 10,555 10,344
Total regulated capability at year-end (thousands of kW)
Fossil plants 8,816 8,816 8,648 (c) 7,569 6,891
Nuclear plants 3,382 (e) 3,293 (d) 3,174 3,174 3,174
Hydro plants 218 218 218 218 218
Purchased 1,513 1,617 1,586 978 1,088
----------- ----------- ---------- ---------- ---------
Total system capability 13,929 13,944 13,626 11,939 11,371
Less Power Agency-owned portion (b) 629 613 599 593 593
----------- ----------- ---------- ---------- ---------
Total Company capability 13,300 13,331 13,027 11,346 10,778
=========== =========== ========== ========== =========
(a) Amounts represent Power Agency's share of the energy supplied from the four
generating facilities that are jointly owned.
(b) Amounts represent Power Agency's retained share of jointly-owned facilities
per the Power Coordination Agreement between PEC and Power Agency.
(c) Amount includes 459 MW related to Rowan units that were transferred to PVI
in February 2002.
(d) Amount includes power upgrades for Harris, Brunswick 1 and Robinson. The
MDC for Harris was restated January 2002; the MDCs for Brunswick 1 and
Robinson were restated January 2003.
(e) Amount includes power uprate for Brunswick 2; the MDC was restated January
2004.
28
ITEM 2. PROPERTIES
The Company believes that its physical properties and those of its subsidiaries
are adequate to carry on its and their businesses as currently conducted. The
Company and its subsidiaries maintain property insurance against loss or damage
by fire or other perils to the extent that such property is usually insured.
ELECTRIC - PEC
At December 31, 2003, PEC's eighteen generating plants represent a flexible mix
of fossil, nuclear, hydroelectric, combustion turbines and combined cycle
resources, with a total summer generating capacity of 12,416 MW. Of this total,
Power Agency owns approximately 682 MW. On December 31, 2003, PEC had the
following generating facilities:
- --------------------------------------------------------------------------------------------------------------------
PEC Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- --------------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Asheville Skyland, NC 2 1964-1971 Coal 100 392
Cape Fear Moncure, NC 2 1956-1958 Coal 100 316
Lee Goldsboro, NC 3 1952-1962 Coal 100 407
Mayo Roxboro, NC 1 1983 Coal 83.83 745 (b)
Robinson Hartsville, SC 1 1960 Coal 100 174
Roxboro Roxboro, NC 4 1966-1980 Coal 96.32 (c) 2,462 (b)
Sutton Wilmington, NC 3 1954-1972 Coal 100 613
Weatherspoon Lumberton, NC 3 1949-1952 Coal 100 176
-------- ---------------
Total 19 5,285
COMBINED CYCLE
Cape Fear Moncure, NC 2 1969 Oil 100 84
Richmond Hamlet, NC 1 2002 Gas/Oil 100 472
-------- ---------------
Total 3 556
COMBUSTION TURBINES
Asheville Skyland, NC 2 1999-2000 Gas/Oil 100 330
Blewett Lilesville, NC 4 1971 Oil 100 52
Darlington Hartsville, SC 13 1974-1997 Gas/Oil 100 812
Lee Goldsboro, NC 4 1968-1971 Oil 100 91
Morehead City Morehead City, NC 1 1968 Oil 100 15
Richmond Hamlet, NC 5 2001-2002 Gas/Oil 100 775
Robinson Hartsville, SC 1 1968 Gas/Oil 100 15
Roxboro Roxboro, NC 1 1968 Oil 100 15
Sutton Wilmington, NC 3 1968-1969 Gas/Oil 100 64
Wayne County Goldsboro, NC 4 2000 Gas/Oil 100 668
Weatherspoon Lumberton, NC 4 1970-1971 Gas/Oil 100 138
-------- ---------------
Total 42 2,975
NUCLEAR
Brunswick Southport, NC 2 1975-1977 Uranium 81.67 1,772 (b)(d)
Harris New Hill, NC 1 1987 Uranium 83.83 900 (b)
Robinson Hartsville, SC 1 1971 Uranium 100 710
-------- ---------------
Total 4 3,382
HYDRO
Blewett Lilesville, NC 6 1912 Water 100 22
Marshall Marshall, NC 2 1910 Water 100 5
Tillery Mount Gilead, NC 4 1928-1960 Water 100 86
Walters Waterville, NC 3 1930 Water 100 105
-------- ---------------
Total 15 218
TOTAL 83 12,416
- --------------------------------------------------------------------------------------------------------------------
(a) Amounts represent PEC's net summer peak rating, gross of co-ownership
interest in plant capacity.
(b) Facilities are jointly owned by PEC and Power Agency. The capacities shown
include Power Agency's share.
(c) PEC and Power Agency are co-owners of Unit 4 at the Roxboro Plant. PEC's
ownership interest in this 700 MW turbine is 87.06%.
(d) During 2003, a power uprate increased the net summer capability of Unit 2
to 900 MWs. The MDC was restated in January 2004.
29
At December 31, 2003, including both the total generating capacity of 12,416 MWs
and the total firm contracts for purchased power of approximately 1,513 MWs, PEC
had total capacity resources of approximately 13,929 MWs.
The Power Agency has acquired undivided ownership interests of 18.33% in
Brunswick Unit Nos. 1 and 2, 12.94% in Roxboro Unit No. 4 and 16.17% in the
Harris Plant and Mayo Unit No. 1. Otherwise, PEC has good and marketable title
to its principal plants and important units, subject to the lien of its mortgage
and deed of trust, with minor exceptions, restrictions, and reservations in
conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. PEC also owns certain easements
over private property on which transmission and distribution lines are located.
At December 31, 2003, PEC had approximately 6,000 circuit miles of transmission
lines including about 300 miles of 500 kilovolt (kV) lines and about 3,000 miles
of 230 kV lines. PEC had distribution lines of approximately 45,000 circuit
miles of overhead conductor and about 17,000 circuit miles of underground cable.
Distribution and transmission substations in service had a transformer capacity
of approximately 12,000,000 kilovolt-ampere (kVA) in 2,411 transformers.
Distribution line transformers numbered approximately 502,700 with an aggregate
capacity of about 21,000,000 kVA.
ELECTRIC - PEF
At December 31, 2003, PEF's fourteen generating plants represent a flexible mix
of fossil, nuclear, combustion turbine and combined cycle resources with a total
summer generating capacity (including jointly-owned capacity) of 8,544 MW. At
December 31, 2003, PEF had the following generating facilities:
- ------------------------------------------------------------------------------------------------------------------
PEF Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- ------------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Anclote Holiday, FL 2 1974-1978 Gas/Oil 100 993
Bartow St. Petersburg, FL 3 1958-1963 Gas/Oil 100 444
Crystal River Crystal River, FL 4 1966-1984 Coal 100 2,302
Suwannee River Live Oak, FL 3 1953-1956 Gas/Oil 100 143
------- ---------------
Total 12 3,882
COMBINED CYCLE
Hines Bartow, FL 2 1999-2003 Gas/Oil 100 998
Tiger Bay Fort Meade, FL 1 1997 Gas 100 207
------- ---------------
Total 3 1,205
COMBUSTION TURBINES
Avon Park Avon Park, FL 2 1968 Gas/Oil 100 52
Bartow St. Petersburg, FL 4 1958-1972 Gas/Oil 100 187
Bayboro St. Petersburg, FL 4 1973 Oil 100 184
DeBary DeBary, FL 10 1975-1992 Gas/Oil 100 667
Higgins Oldsmar, FL 4 1969-1970 Gas/Oil 100 122
Intercession City Intercession City, FL 14 1974-2000 Gas/Oil 100 (c) 1,041 (b)
Rio Pinar Rio Pinar, FL 1 1970 Oil 100 13
Suwannee River Live Oak, FL 3 1980 Gas/Oil 100 164
Turner Enterprise, FL 4 1970-1974 Oil 100 154
University of Gainesville, FL 1 1994 Gas 100 35
Florida Cogeneration
------- ---------------
Total 47 2,619
NUCLEAR
Crystal River Crystal River, FL 1 1977 Uranium 91.8 838 (b)
(d)
------- ---------------
Total 1 838
TOTAL 63 8,544
- ------------------------------------------------------------------------------------------------------------------
(a) Amounts represent PEF's net summer peak rating, gross of co-ownership
interest in plant capacity.
(b) Facilities are jointly owned. The capacities shown include joint owners'
share.
(c) PEF and Georgia Power Company (Georgia Power) are co-owners of a 143 MW
advanced combustion turbine located at PEF's Intercession City site (P11).
Georgia Power has the exclusive right to the output of this unit during the
months of June through September. PEF has that right for the remainder of
the year.
(d) During 2003, a power uprate increased the net summer capability of this
unit to 838 MWs. The MDC was restated in January 2004.
30
At December 31, 2003, PEF had total capacity resources of approximately 9,857
MWs, including both the total generating capacity of 8,544 MWs and the total
firm contracts for purchased power of 1,313 MWs.
Several entities have acquired undivided ownership interests in CR3 in the
aggregate amount of 8.2%. The joint ownership participants are: City of Alachua
- - 0.08%, City of Bushnell - 0.04%, City of Gainesville - 1.41%, Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New Smyrna Beach - 0.56%, City of Ocala - 1.33%, Orlando Utilities
Commission - 1.60% and Seminole Electric Cooperative, Inc. - 1.70%. PEF and
Georgia Power are co-owners of a 143 MW advance combustion turbine located at
PEF's Intercession City site (P11). Georgia Power has the exclusive right to the
output of this unit during the months of June through September. PEF has that
right for the remainder of the year. Otherwise, PEF has good and marketable
title to its principal plants and important units, subject to the lien of its
mortgage and deed of trust, with minor exceptions, restrictions and reservations
in conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. PEF also owns certain easements
over private property on which transmission and distribution lines are located.
At December 31, 2003, PEF had approximately 5,000 circuit miles of transmission
lines including about 200 miles of 500 kV lines and about 1,500 miles of 230 kV
lines. PEF had distribution lines of approximately 25,000 circuit miles of
overhead conductor and about 15,000 circuit miles of underground cable.
Distribution and transmission substations in service had a transformer capacity
of approximately 45,000,000 kVA in 614 transformers. Distribution line
transformers numbered 356,930 with an aggregate capacity of about 18,000,000
kVA.
FUELS
The Fuels business segment controls, either directly or through business units,
coal reserves located in eastern Kentucky and southwestern Virginia. Fuels owns
properties that contain estimated coal reserves of approximately 60 million tons
and controls, through mineral leases, additional estimated coal reserves of
approximately 18 million tons. The reserves controlled include substantial
quantities of high quality, low sulfur coal that is appropriate for use at PEF's
existing generating units. Fuels' total production of coal during 2003 was
approximately 3.5 million tons.
In connection with its coal operations, Fuels' business units own and operate an
underground mining complex located in southeastern Kentucky and southwestern
Virginia. Other subsidiaries own and operate surface and underground mines, coal
processing and loadout facilities, a river terminal facility in eastern
Kentucky, a railcar-to-barge loading facility in West Virginia and two bulk
commodity terminals on the Kanawha River near Charleston, West Virginia. Fuels
employs both company and contract miners in their mining activities.
The Fuels business segment, through its business units, owns all of the
interests in five synthetic fuel entities and a minority interest in one
synthetic fuel entity that owns facilities that produce synthetic fuel. These
facilities are in six different locations in West Virginia, Virginia and
Kentucky.
Fuels' natural gas and oil production in 2003 was 25.4 Bcf equivalent. Fuels has
oil and gas leases in East Texas, North Texas and Louisiana with total proven
natural gas and oil reserves of approximately 360 Bcf equivalent.
CCO
At December 31, 2003, CCO had the following nonregulated generation plants in
service.
- ----------------------------------------------------------------------------------------------------------------
Construction Commercial Configuration/
Project Location Start Date Operation Date Number of Units MW (a)
- ----------------------------------------------------------------------------------------------------------------
Monroe Units 1 and 2 Monroe, GA 4Q 1998/1Q 2000 4Q 1999/2Q 2001 Simple-Cycle, 2 315
Rowan Phase I (b) Salisbury, NC 1Q 2000 2Q 2001 Simple-Cycle, 3 459
Walton (c) Monroe, GA 2Q 2000 2Q 2001 Simple-Cycle, 3 460
DeSoto Units Arcadia, FL 2Q 2001 2Q 2002 Simple-Cycle, 2 320
Effingham Rincon, GA 1Q 2001 3Q 2003 Combined-Cycle, 1 480
Rowan Phase II (b) Salisbury, GA 4Q 2001 2Q 2003 Combined-Cycle, 1 466
Washington (c) Sandersville, GA 2Q 2002 2Q 2003 Simple-Cycle, 4 600
-----------
TOTAL 3,100
- ----------------------------------------------------------------------------------------------------------------
(a) Amounts represent CCO's summer rating.
(b) This project was transferred from PEC to PVI in February 2002.
(c) These projects were purchased from LG&E Energy Corp. in February 2002.
31
RAIL SERVICES
Progress Rail is one of the largest integrated processors of railroad materials
in the United States, and is a leading supplier of new and reconditioned freight
car parts; rail, rail welding and track work components; railcar repair
facilities; railcar and locomotive leasing; maintenance-of-way equipment and
scrap metal recycling. It has facilities in 23 states, Mexico and Canada.
Progress Rail owns and/or operates approximately 5,300 railcars and 100
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.
PTC
PTC LLC provides wholesale telecommunications services throughout the
Southeastern United States. PTC LLC incorporates more than 420,000 fiber miles
of fiber-optic cable in its network including more than 185 Points-of-Presence,
or physical locations where a presence for network access exists.
32
ITEM 3. LEGAL PROCEEDINGS
Legal and regulatory proceedings are included in the discussion of the Company's
business in PART I, ITEM 1 under "Environmental," "Regulatory Matters" and
"Nuclear Matters" and incorporated by reference herein.
1. Strategic Resource Solutions Corp. ("SRS") v. San Francisco Unified School
District, et al., Sacramento Superior Court, Case No. 02AS033114
In November 2001, SRS filed a claim against the San Francisco Unified School
District ("the District") and other defendants claiming that SRS is entitled to
approximately $10 million in unpaid contract payments and delay and impact
damages related to the District's $30 million contract with SRS. In March 2002,
the District filed a counterclaim, seeking compensatory damages and liquidated
damages in excess of $120 million, for various claims, including breach of
contract and demand on a performance bond. SRS has asserted defenses to the
District's claims. SRS has amended its claims and asserted new claims against
the District and other parties, including a former SRS employee and a former
District employee.
On March 13, 2003, the City Attorney and the District filed new claims against
SRS, Progress Energy, Inc., Progress Energy Solutions, Inc., and certain
individuals, alleging fraud, false claims, violations of California statutes,
and seeking compensatory damages, punitive damages, liquidated damages, treble
damages, penalties, attorneys' fees and injunctive relief. The filing states
that the City and the District seek "more than $300 million in damages and
penalties." PEC was added as a cross-defendant.
The Company, SRS, Progress Energy Solutions, Inc. and PEC all have denied the
District's allegations and cross-claims. Discovery is in progress in the matter.
The case has been assigned to a judge under the Sacramento County superior
court's case management rules, and the judge and the parties have been
conferring on scheduling and processes to narrow or resolve issues, if possible,
and to prepare the case for trial. No trial date has been set. SRS and the
Company are vigorously defending all of these claims. The Company cannot predict
the outcome of this matter, but will vigorously defend against the allegations.
2. Collins v. Duke Energy Corporation et al, Civil Action No. 03CP404050
In August 2003, PEC was served as a co-defendant in a purported class action
lawsuit styled as Collins v. Duke Energy Corporation et al, Civil Action No.
03CP404050, in South Carolina's Circuit Court of Common Pleas for the Fifth
Judicial Circuit. PEC is one of three electric utilities operating in South
Carolina named in the suit. The plaintiffs are seeking damages for the alleged
improper use of electric easements but have not asserted a dollar amount for
their damage claims. The complaint alleges that the licensing of attachments on
electric utility poles, towers and other structures to non-utility third parties
or telecommunication companies for other than the electric utilities' internal
use along the electric right-of-way constitutes a trespass.
In September 2003, PEC filed a motion to dismiss all counts of the complaint on
substantive and procedural grounds. In October 2003, the plaintiffs filed a
motion to amend their complaint. PEC believes the amended complaint asserts the
same factual allegations as are in the original complaint and also seeks money
damages and injunctive relief.
The court has not yet held any hearings or made any rulings in this case. In
November 2003, PEC filed a motion to dismiss the plaintiffs' first amended
complaint. PEC cannot predict the outcome of any future proceedings in this
matter, but will vigorously defend against the allegations.
33
3. U.S. Global, LLC v. Progress Energy, Inc. et al, Case No. 03004028-03 and
Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, Case No.
03004028-03
A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two
lawsuits arising out of an Asset Purchase Agreement dated as of October 19,
1999, by and among U.S. Global LLC (Global), EARTHCO, certain affiliates of
EARTHCO (collectively the EARTHCO Sellers), EFC Synfuel LLC (which is owned
indirectly by Progress Energy, Inc.) and certain of its affiliates, including
Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Cost Synfuel LLC
(currently named Sandy River Synfuel LLC) (Collectively the Progress
Affiliates), as amended by an Amendment to Purchase Agreement as of August 23,
2000 (the Asset Purchase Agreement). Global has asserted that pursuant to the
Asset Purchase Agreement it is entitled to (1) interest in two synthetic fuel
facilities currently owned by the Progress Affiliates, and (2) an option to
purchase additional interests in the two synthetic fuel facilities.
The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al, was filed in
the Circuit Court for Broward County, Florida on March 4, 2003 (the Florida
Global Case). The Florida Global Case asserts claims for breach of the Asset
Purchase Agreement and other contract and tort claims related to the Progress
Affiliates' alleged interference with Global's rights under the Asset Purchase
Agreement. The Florida Global Case requests an unspecified amount of
compensatory damages, as well as declaratory relief. On December 15, 2003, the
Progress Affiliates filed a motion to dismiss the Third Amended Complaint in the
Florida Global Case.
The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was
filed by the Progress Affiliates in the Superior Court for Wake County, North
Carolina seeking declaratory relief consistent with the Company's interpretation
of the Asset Purchase Agreement (the North Carolina Global Case). Global was
served with the North Carolina Global Case on April 17, 2003.
On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack
of personal jurisdiction over Global. In the alternative, Global requested that
the court decline to exercise its discretion to hear the Progress Affiliates'
declaratory judgment action. On August 7, 2003, the Wake County Superior Court
denied Global's motion to dismiss and entered an order staying the North
Carolina Global Case, pending the outcome of the Florida Global Case. The
Progress Affiliates have appealed the Superior Court's order staying the case;
Global has cross appealed the denial of its motion to dismiss for lack of
personal jurisdiction. The North Carolina Court of Appeals has not set a hearing
date for the Progress Affiliates' Appeal or Global's cross appeal. The Company
cannot predict the outcome of these matters, but will vigorously defend against
the allegations.
4. Gerber Asset Management LLC v. William Cavanaugh III and Progress Energy,
Inc. et al, Case No. 04 CV 636
On February 3, 2004, Progress Energy, Inc. was served with a class action
complaint alleging violations of federal security laws in connection with the
Company's issuance of Contingent Value Obligations (CVOs). The action was filed
in the United States District Court for the Southern District of New York and
names Progress Energy, Inc. Chairman William Cavanaugh III and Progress Energy,
Inc. as defendants. The Complaint alleges that Progress Energy failed to timely
disclose the impact of the Alternative Minimum Tax required under Sections 55-59
of the Internal Revenue Code (Code) on the value of certain CVOs issued in
connection with the Florida Progress Corporation merger. The suit seeks
unspecified compensatory damages, as well as attorneys' fees and litigation
costs. The Company is currently reviewing the complaint and cannot predict the
outcome of this matter, but will vigorously defend against the allegations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NONE
34
EXECUTIVE OFFICERS OF THE REGISTRANTS
Name Age Recent Business Experience
Robert B. McGehee 60 President and Chief Executive Officer,
Progress Energy, October 2002 and March 1,
2004, respectively, to present. Mr. McGehee
joined the Company (formerly CP&L) in 1997 as
Senior Vice President and General Counsel.
Since that time, he has held several senior
management positions of increasing
responsibility. Most recently, Mr. McGehee
served as President and Chief Operating
Officer of the Company, having responsibility
for the day-to-day operations of the
Company's regulated and nonregulated
businesses. Prior to that, Mr. McGehee served
as President and Chief Executive Officer of
Progress Energy Service Company, LLC.
Before joining Progress Energy, Mr. McGehee
chaired the board of Wise Carter Child &
Caraway, a law firm headquartered in Jackson,
Miss. He primarily handled corporation,
contract, nuclear regulatory and employment
matters. During the 1990s, he also provided
significant counsel to U.S. companies on
reorganizations, business growth initiatives
and preparing for deregulation and other
industry changes.
William S. Orser 59 Group President, Energy Supply, PEC and PEF,
November 2000 to present. Mr. Orser is
responsible for the operation of 38 utility
and nonregulated power plants of Progress
Energy. He also oversees the organizations
that support those plants, as well as the
Company's System Planning and Operations
function.
Mr. Orser joined Progress Energy (formerly
CP&L) in 1993 as Executive Vice President and
Chief Nuclear Officer. He later became
Executive Vice President - Energy Supply,
PEC, a position he held until the acquisition
of Florida Progress in 2000.
Before joining the Company in April 1993, Mr.
Orser was an executive at the Detroit Edison
Company, serving as Executive Vice President
- Nuclear Generation. Previously, he worked
with Portland General Electric Co.
William D. Johnson 50 Group President, Energy Delivery, Progress
Energy, January 2004 to present; Executive
Vice President, Progress Energy Service
Company, LLC, January 1, 2004 to present;
PEC, FPC and PEF November 2000 to present.
Mr. Johnson has been with Progress Energy
(formerly CP&L) since 1992 and most recently
served as President, CEO and Corporate
Secretary, Progress Energy Service Company,
LLC, October 2002 to December 2003. Prior to
that, he was Executive Vice President -
Corporate Relations & Administrative
Services, General Counsel and Secretary of
Progress Energy. Mr. Johnson served as Vice
President - Legal Department and Corporate
Secretary, CP&L from 1997 to 1999.
Before joining Progress Energy, Johnson was a
partner with the Raleigh office of Hunton &
Williams, where he specialized in the
representation of utilities.
35
Peter M. Scott III 54 President and Chief Executive Officer,
Progress Energy Service Company, LLC, January
2004 to present; Executive Vice President,
FPC, PEC, PEF, and Progress Energy Service
Company, LLC, 2000 to present. Mr. Scott has
been with the Company since May 2000 and most
recently served as Executive Vice President
and Chief Financial Officer of Progress
Energy, Inc., May 2000 to December 2003. In
that position, Mr. Scott oversaw the
Company's strategic planning, financial and
enterprise risk management functions.
Before joining Progress Energy, Mr. Scott was
the founding president of Scott, Madden &
Associates, Inc., a general management
consulting firm headquartered in Raleigh,
N.C. The firm served clients in a number of
industries, including energy and
telecommunications. Particular practice area
specialties for Mr. Scott included strategic
planning and operations management.
Geoffrey S. Chatas 41 Executive Vice President and Chief Financial
Officer, Progress Energy, Inc., FPC, PEC and
PEF, January 2004 to present. Mr. Chatas
oversees the Company's accounting, strategic
planning, tax, financial and regulatory
services and enterprise risk management
functions. He previously served as Senior
Vice President, Progress Energy, Inc.,
October 2003 to December 2003.
Before joining Progress Energy, Mr. Chatas
served as Senior Vice President - Finance and
Treasurer for American Electric Power, a
multi-state energy holding company based in
Columbus, Ohio. During his time at AEP, he
managed investor relations and corporate
finance. In addition, Mr. Chatas held
executive financial positions at Banc One and
Citibank.
Robert H. Bazemore, Jr. 49 Chief Accounting Officer and Controller,
Progress Energy, Inc., June 2000 to present;
Controller, FPC and PEF, November 2000 to
present; Vice President and Controller,
Progress Energy Service Company, LLC, August
2000 to present; Chief Accounting Officer and
Controller, PEC, May 2000 to present. Mr.
Bazemore has been with Progress Energy
(formerly CP&L) since 1986 and has served in
a number of roles in corporate support and
field positions, including Director, CP&L,
Operations & Environmental Support
Department, December 1998 to May 2000;
Manager, CP&L Financial & Regulatory
Accounting, September 1995 to December 1998.
Prior to joining Progress Energy, Mr.
Bazemore worked in managerial and accounting
positions with companies in Roanoke, VA and
Jacksonville, FL.
Brenda F. Castonguay 51 Senior Vice President, Progress Energy
Service Company, LLC, July 2002 to present.
Ms. Castonguay directs the work of the Human
Resources, Corporate Services, Real Estate,
IT/Telecommunications and Corporate Security
departments. She joined Progress Energy
(formerly CP&L) in February 1994 as assistant
to the Vice President - Human Resources. She
has also served as Manager - Human Resources
Administrative Services and Vice President -
Human Resources. During her tenure with
Progress Energy's Human Resources Department,
Ms. Castonguay has managed human resources
activities and initiatives affecting
approximately 16,000 full-time employees.
Before joining the Company, Ms. Castonguay
held managerial positions with Maine Yankee
Atomic Power Co., Central Maine Power Co. and
General Telephone & Electronics (GTE) Corp.
36
Donald K. Davis 58 Executive Vice President, PEC, May 2000 to
present. Mr. Davis is also President and
Chief Executive Officer, SRS, June 2000 to
present and was President and Chief Executive
Officer, NCNG, July 2000 to September 2003.
Mr. Davis joined the Company in May 2000 as
Executive Vice President, Gas and Energy
Services.
Before joining the Company, Mr. Davis was
Chairman, President and Chief Executive
Officer of Yankee Atomic Electric Company,
and served as Chairman, President and Chief
Executive Officer of Connecticut Atomic Power
Company from 1997 to May 2000 where he was
responsible for two electric wholesale
generating companies. Before joining Yankee
Atomic Power Co., Davis served as a principal
of PRISM Consulting Inc., a utility
management consulting firm he founded in
1992.
Fred N. Day IV 60 President and Chief Executive Officer, PEC,
October 2003 to present; Executive Vice
President, PEF, November 2000 to present. Mr.
Day oversees all aspects of Carolinas
Delivery operations, including distribution
and customer service, transmission, and
products and services. He previously served
as Executive Vice President, PEC and PEF.
During his more than 30 years with Progress
Energy (formerly CP&L), Mr. Day has held
several management positions of increasing
responsibility. He was promoted to Vice
President - Western Region in 1995.
*H. William Habermeyer, Jr. 61 President and Chief Executive Officer, PEF,
November 2000 to present. Mr. Habermeyer
joined Progress Energy (formerly PEC) in 1993
after a career in the U.S. Navy. During his
tenure with the Company, Mr. Habermeyer has
served as Vice President - Nuclear Services
and Environmental Support; Vice President -
Nuclear Engineering; and Vice President -
Western Region. While overseeing Western
Region operations, Mr. Habermeyer was
responsible for regional distribution
management, customer support and community
relations.
*Bonnie V. Hancock 42 President, Progress Fuels Corporation,
September 2002 to present. Ms. Hancock has
served in several positions since joining
Progress Energy (formerly CP&L) in 1993,
including Director - Federal Tax, Vice
President and Controller and Vice President -
Strategic Planning.
Before joining the Company, Ms. Hancock
directed all tax planning and research
activities at Potomac Electric Power Co. in
Washington, D.C. She also worked in
management positions with Finalco, Inc. and
Aronson, Greene, Fisher and Co. CPAs.
C.S. Hinnant 59 Senior Vice President and Chief Nuclear
Officer, PEC, June 1998 to present. Mr.
Hinnant joined Progress Energy (formerly
CP&L) in 1972 at the Brunswick Nuclear Plant
near Southport, N.C., where he held several
positions in the startup testing and
operating organizations. He left Progress
Energy in 1976 to work for Babcock and Wilcox
in the Commercial Nuclear Power Division,
returning to Progress Energy in 1977. Since
that time, he has served in various
management positions at three of Progress
Energy's nuclear plant sites.
37
Tom D. Kilgore 56 Group President, PEC (November 2000 to
present); President and CEO, Progress
Ventures, Inc., March 2000 to present.
Progress Ventures, Inc. was created in 2000
to manage Progress Energy's assets and
operations in fuel extraction, manufacturing
and delivery, nonregulated generation and
energy marketing and trading.
Mr. Kilgore joined Progress Energy (formerly
CP&L) in August 1998 as Senior Vice President
- Power Operations. Before joining the
Company, Mr. Kilgore was President and Chief
Executive Officer - Oglethorpe Power Corp. He
held other management positions at Oglethorpe
including Senior Vice President - Power
Supply. Before joining Oglethorpe Power, Mr.
Kilgore was Director - Fossil and Hydro
Operations for Arkansas Power and Light Co.,
where he held numerous other management
positions.
Jeffrey J. Lyash 42 Senior Vice President, PEF, November 2003 to
present. Mr. Lyash oversees all aspects of
energy delivery operations for PEF. Prior to
coming to PEF, Mr. Lyash was Vice President -
Transmission in Energy Delivery in the
Carolinas since January 2002.
Mr. Lyash joined Progress Energy in 1993 and
spent his first eight years with the Company
at the Brunswick Nuclear Plant in Southport,
North Carolina. His last position at
Brunswick was as Director of site operations.
John R. McArthur 48 Senior Vice President, General Counsel and
Secretary of Progress Energy, January 2004 to
present. Mr. McArthur oversees the Audit
Services, Corporate Communications, Corporate
Relations and Administrative Services, Legal,
Economic Development, Environment, Health &
Safety and Public Affairs departments. Mr.
McArthur is also Senior Vice President and
Corporate Secretary, Florida Progress and
PEC, and Senior Vice President, PEF, January
1 to present. Previously, he served the
Company as Senior Vice President - Corporate
Relations (December 2002 to December 2003)
and as Vice President - Public Affairs
(December 2001 to December 2002).
Before joining Progress Energy in December
2001, Mr. McArthur was a member of North
Carolina Governor Mike Easley's senior
management team, handling major policy
initiatives as well as media and legal
affairs. He also directed Governor Easley's
transition team after the election of 2000.
Prior to joining Governor Easley, Mr.
McArthur handled state government affairs in
10 southeastern states for General Electric
Co. He also served as chief counsel in the
North Carolina Attorney General's office,
where he supervised utility, consumer, health
care, and environmental protection issues.
Before that, he was a partner at Hunton &
Williams.
E. Michael Williams 55 Senior Vice President, PEC and PEF, June 2000
and November 2000, respectively, to present.
Before joining the Company in 2000, Mr.
Williams was with Central and Southwest
Corp., Inc. and subsidiaries for 28 years and
served in various positions prior to becoming
Vice President - Fossil Generation in Dallas.
*Indicates individual is an executive officer of Progress Energy, Inc., but not
Carolina Power & Light Company.
38
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS
Progress Energy's Common Stock is listed on the New York Stock Exchange. The
high and low intra-day stock sales prices for Progress Energy for each quarter
for the past two years, and the dividends declared per share are as follows:
2003 High Low Dividends Declared
- ---- ---- --- ------------------
First Quarter $ 46.10 $ 37.45 $ 0.560
Second Quarter 48.00 38.99 0.560
Third Quarter 45.15 39.60 0.560
Fourth Quarter 46.00 41.60 0.575
2002 High Low Dividends Declared
- ---- ---- --- ------------------
First Quarter $ 50.86 $ 43.01 $ 0.545
Second Quarter 52.70 47.91 0.545
Third Quarter 51.97 36.54 0.545
Fourth Quarter 44.82 32.84 0.560
The December 31 closing price of the Company's Common Stock was $45.26 for 2003
and $43.35 for 2002.
As of January 30, 2004, the Company had 70,118 holders of record of Common
Stock.
Progress Energy holds all 159,608,055 shares outstanding of PEC common stock
and, therefore, no public trading market exists for the common stock of PEC.
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's subsidiaries.
PROGRESS ENERGY
Information on the equity compensation plans of Progress Energy is set forth
under the heading "Equity Compensation Plant Information" in the Progress Energy
2003 definitive proxy statement dated March 31, 2004 and incorporated by
reference herein.
PEC
PEC does not have any equity compensation plans under which its equity
securities are issued.
39
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
2003 (a) 2002 (a) 2001 (a) 2000 (a)(b) 1999
---------- ---------- ---------- ------------- -----------
(dollars in millions, except per share data)
Operating results
Operating revenues $ 8,743 $ 8,091 $ 8,129 $ 3,769 $ 3,265
Income from continuing
operations before cumulative $ 811 $ 552 $ 541 $ 478 $ 383
effect
Net Income $ 782 $ 528 $ 542 $ 478 $ 379
Per share data
Basic earnings
Income from continuing
operations $ 3.42 $ 2.54 $ 2.64 $ 3.04 $ 2.58
Net income $ 3.30 $ 2.43 $ 2.65 $ 3.04 $ 2.56
Diluted earnings
Income from continuing
operations $ 3.40 $ 2.53 $ 2.63 $ 3.03 $ 2.58
Net income $ 3.28 $ 2.42 $ 2.64 $ 3.03 $ 2.55
Dividends declared per common
share $ 2.26 $ 2.20 $ 2.14 $ 2.08 $ 2.02
Assets (d) $ 26,202 $ 24,208 $ 23,647 $ 22,842 $ 10,655
Capitalization
Common stock equity $ 7,444 $ 6,677 $ 6,004 $ 5,424 $ 3,413
Preferred stock - redemption
not required 93 93 93 93 59
Long-term debt, net (c) 9,934 9,747 8,619 4,904 2,162
Current portion of long-term debt 868 275 688 184 197
Short-term obligations 4 695 942 4,959 1,035
----------- ----------- ----------- ----------- -------------
Total capitalization and total debt $ 18,343 $ 17,487 $ 16,346 $ 15,564 $ 6,866
=========== =========== =========== =========== =============
(a) Operating results and balance sheet data have been restated for
discontinued operations.
(b) Operating results and balance sheet data includes information for FPC since
November 30, 2000, the date of acquisition.
(c) Includes long-term debt to affiliated trust of $309 million at December 31,
2003.
(d) All periods have been restated for the reclassification of cost of removal,
nuclear decommissioning and fossil dismantlement (See Note 5F).
40
PROGRESS ENERGY CAROLINAS, INC.
The selected consolidated financial data should be read in conjunction with the
consolidated financial statements and the notes thereto included elsewhere in
this report.
Years Ended December 31
2003 2002 2001 2000(a)(b) 1999(b)
----------- ----------- ------------ ------------ ----------
(dollars in millions)
Operating results
Operating revenues $ 3,600 $ 3,554 $ 3,360 $ 3,528 $ 3,365
Net income $ 482 $ 431 $ 364 $ 461 $ 382
Earnings for common stock $ 479 $ 428 $ 361 $ 458 $ 379
Assets (d) $ 11,008 $ 10,405 $ 10,604 $ 10,525 $ 10,656
Capitalization
Common stock equity $ 3,237 $ 3,089 $ 3,095 $ 2,852 $ 3,413
Preferred stock - redemption
not required 59 59 59 59 59
Long-term debt, net 3,086 3,048 2,698 3,134 2,162
Current portion of long-term debt 300 - 600 - 197
Short-term obligations (c) 29 438 309 486 1,035
----------- ----------- ----------- ----------- -----------
Total capitalization and total debt $ 6,711 $ 6,634 $ 6,761 $ 6,531 $ 6,866
=========== =========== =========== =========== ===========
(a) Operating results and balance sheet data do not include information for
NCNG, SRS, Monroe Power Company or PVI subsequent to July 1, 2000, the date
PEC distributed its ownership interest in the stock of these companies to
Progress Energy.
(b) Operating results include NCNG results for the period July 15, 1999 to July
1, 2000. Balance sheet data includes NCNG for December 31, 1999.
(c) Includes notes payable to affiliated companies, related to the money pool
program, of $25 million and $48 million at December 31, 2003 and 2001,
respectively.
(d) All periods have been restated for the reclassification of cost of removal
and nuclear decommissioning (See Note 3F).
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
the "Risk Factors" sections and "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for
a discussion of the factors that may impact any such forward-looking statements
made herein.
Management's Discussion and Analysis should be read in conjunction with the
Progress Energy Consolidated Financial Statements.
INTRODUCTION
Progress Energy is an integrated energy company, with its primary focus on the
end-use and wholesale electricity markets. The Company's reportable business
segments and their primary operations include:
o Progress Energy Carolinas Electric (PEC Electric) - primarily engaged
in the generation, transmission, distribution and sale of electricity
in portions of North Carolina and South Carolina;
o Progress Energy Florida (PEF) - primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of
Florida;
o Competitive Commercial Operations (CCO) - engaged in nonregulated
electric generation operations and marketing activities primarily in
the southeastern United States;
o Fuels - primarily engaged in natural gas production in Texas and
Louisiana, coal mining and related services, and the production of
synthetic fuels and related services, both of which are located in
Kentucky, West Virginia, and Virginia;
o Rail Services (Rail) - engaged in various rail and railcar related
services in 23 states, Mexico and Canada; and
o Other Businesses (Other) - engaged in other nonregulated business
areas, including telecommunications primarily in the eastern United
States and energy services operations, which do not meet the
requirements for separate segment reporting disclosure.
In 2003, the Company realigned its business segments to reflect the current
management structure and assigned new names to the segments to better reflect
their operations. For comparative purposes, 2002 and 2001 segment information
has been restated to align with the 2003 organizational and reporting structure.
Strategy
The Company's goals related to its regulated utilities and nonregulated
businesses are to continue focusing on achieving their financial objectives,
delivering excellent customer satisfaction and continually striving for
operational excellence. The target is to maintain a business mix of
approximately 80% regulated and 20% nonregulated business. A summary of the
significant financial objectives or issues impacting Progress Energy, its
regulated utilities and nonregulated operations are addressed more fully in the
following discussion.
o Progress Energy, Inc.
Progress Energy has several key financial objectives, the first of
which is to achieve operating cash flows sufficient to meet planned
capital expenditures and support its current dividend policy. Any
excess cash flow would be used for debt reduction, primarily at the
holding company. In addition, the Company seeks to achieve earnings
growth through its core regulated utility businesses and through
improving returns at its nonregulated businesses. The Company also
seeks to maintain ready access to credit markets.
The ability to meet these objectives is largely dependent on the
earnings and cash flows of its two regulated utilities. The regulated
utilities contributed $787 million of net income and produced over 90%
of consolidated cash flow from operations in 2003. In addition,
synthetic fuel income of $200 million also contributed significantly
to net income. Partially offsetting the net income contribution
provided by the regulated utilities and synthetic fuels was a loss of
$236 million recorded at Corporate, primarily related to interest
expense. While the Company's synthetic fuel operations provide
significant earnings, the significant amount of cash flow benefits
from synthetic fuels will come in the future when deferred tax credits
ultimately are utilized. Credits generated but not utilized are
42
carried forward indefinitely as alternative minimum tax credits and
will provide positive cash flow when utilized. At December 31, 2003,
deferred credits were $659 million. The Company does not anticipate
any significant acquisitions in the near term.
Progress Energy reduced its debt to total capitalization ratio to
58.9% at the end of 2003 as compared to 61.3% at the end of 2002. The
Company expects to continue to improve this ratio as it plans to
reduce total debt through growth in operating cash flow after
dividends, ongoing equity issuances and with proceeds from asset
sales. The Company expects capital expenditures to be approximately
$1.3 billion in 2004 and in 2005.
Progress Energy continues to maintain investment grade credit ratings,
despite a ratings downgrade in 2003 by both Moody's and Standard &
Poor's. Both these ratings agencies upgraded the Company's outlook
from "negative" to "stable" in 2003. The downgrades have not
materially affected Progress Energy's access to liquidity or the cost
of its short-term borrowings.
o Regulated Utilities
The regulated utilities earnings and operating cash flows are heavily
influenced by weather, the economy, demand for electricity related to
customer growth, actions of regulatory agencies and cost controls.
Both PEC Electric and PEF operate in retail service territories that
are forecast to have income and population growth higher than the U.S.
average. New housing starts in both these territories are also
expected to exceed the U.S. average. In recent years, lower industrial
sales, primarily at PEC Electric and mainly related to weakness in the
textile sector, have negatively impacted earnings growth. The Company
does not expect any significant improvement in industrial sales in the
near term. These combined factors, and assuming normal weather, are
expected to contribute to approximately 2%-3% annual KWh sales growth
at the utilities through at least 2006. The Company does not
anticipate any significant additional generation expansion to meet
this growth other than the previously planned 500 MW combined-cycle
unit at PEF in 2005.
PEC Electric and PEF continue to monitor progress toward a more
competitive environment. No retail electric restructuring legislation
has been introduced in the jurisdictions in which PEC Electric and PEF
operate and both operate under rate agreements. As part of the Clean
Smokestacks bill in North Carolina and an agreement with the Public
Service Commission of South Carolina (SCPSC), PEC Electric is
operating under a rate freeze in North Carolina through 2007 and a
rate cap in South Carolina through 2005. PEF is operating under a rate
agreement in Florida through 2005. See Note 7 of the Progress Energy
Consolidated Financial Statements for further discussion of the
utilities' rates.
The utilities will continue to exercise strong financial discipline as
it relates to controlling operation and maintenance costs despite
expected increases in benefit-related costs and insurance expense.
Operating cash flows are expected to be more than sufficient to fund
capital spending in 2004 and in 2005.
o Nonregulated businesses
The Company's primary nonregulated businesses are CCO, Fuels and
Progress Rail.
Cash flows and earnings of the nonregulated businesses are impacted
largely by the ability to obtain additional term contracts or sell
energy on the spot market at favorable terms, the volume of synthetic
fuel produced and tax credits utilized, and volumes and prices of both
coal and natural gas sales.
Progress Energy expects an excess of supply in the wholesale electric
energy market for the next several years. During 2003, CCO completed
the build out of its nonregulated generation assets bringing CCO's
total capacity to 3,100 MW. The Company has no current plans to expand
its portfolio of nonregulated generating plants. The Company has
contracts for planned production capacity of 85% in 2004 and 50% for
both 2005 and 2006. CCO will continue to seek to secure term contracts
with load-serving entities to utilize its excess capacity.
Fuels will continue to develop its natural gas production asset base
both as a long-term economic hedge for the Company's nonregulated
generation fuel needs and to obtain a meaningful presence in natural
gas markets that will allow it to provide attractive returns for the
Company's shareholders. In 2004, Fuels anticipates that, with budgeted
capital expenditures, it will have a 25% increase in gas production.
43
The Company's majority-owned synthetic fuel entities participate in
the Internal Revenue Service (IRS) Prefiling Agreement (PFA) program.
The PFA program is a program that allows taxpayers to voluntarily
accelerate the IRS exam process in order to seek resolution of
specific issues. The Company has resolved certain issues with the IRS
and is continuing to work with the IRS to resolve any remaining
issues. The Company cannot predict when the exam process will be
completed or the final resolution of any outstanding matters. These
facilities have private letter rulings (PLRs) from the IRS with
respect to their synthetic fuel operations. The Company has no current
plans to alter its synthetic fuel production schedule as a result of
these matters. The Company plans to produce approximately 11 million
to 12 million tons of synthetic fuel in 2004. Through December 31,
2003, the Company had generated $1,243 million of synthetic fuel tax
credits to date (including FPC prior to the acquisition by the
Company). See additional discussion at Synthetic Fuel Tax Credits in
the OTHER MATTERS section below and at Note 14 to the Progress Energy
Consolidated Financial Statements.
Progress Energy continues to look for opportunities to divest of its
Progress Rail subsidiary at an opportune time as it is not considered
part of its core business strategy in the future. The Company expects
to accomplish the divestiture within the next three years.
Progress Energy and its consolidated subsidiaries are subject to various risks.
For a complete discussion of these risks see the Risk Factors section.
RESULTS OF OPERATIONS
FOR 2003 AS COMPARED TO 2002 AND 2002 AS COMPARED TO 2001
In this section, earnings and the factors affecting earnings are discussed. The
discussion begins with a summarized overview of the Company's consolidated
earnings which is followed by a more detailed discussion and analysis by
business segment.
PROGRESS ENERGY
In 2003, Progress Energy's net income was $782 million, a 48% increase from $528
million in 2002. Income from continuing operations before cumulative effect of
changes in accounting principles and discontinued operations was $811 million in
2003, a 47% increase from $552 million in 2002. Net income for 2003 increased
compared to 2002 primarily due to the inclusion in 2002 of an impairment of $265
million after-tax related to assets in the telecommunications and rail
businesses. The Company recorded impairments of $23 million after-tax in 2003 on
an investment portfolio and on long-lived assets. The increase in net income in
2003 of $12 million, excluding the impairments, is primarily due to:
o An increase in retail customer growth at the utilities.
o Growth in natural gas production and sales.
o Higher synthetic fuel sales.
o Absence of severe storm costs incurred in 2002.
o Lower loss recorded in 2003 related to the sale of NCNG, with the majority
of the loss on the sale being recorded in 2002.
o Lower interest charges in 2003.
Partially offsetting these items were the:
o Net impact of the 2002 Florida Rate settlement.
o Impact of the change in the fair value of the CVOs.
o Milder weather in 2003 as compared to 2002.
o Increased benefit-related costs.
o Higher depreciation expense at both utilities and the Fuels and CCO
segments.
o The impact of changes in accounting principles in 2003.
Each of these items is discussed further in the results of operations for the
segments below.
Basic earnings per share from net income increased from $2.43 per share in 2002
to $3.30 per share in 2003 in part due to the factors outlined above. Dilution
related to a November 2002 equity issuance of 14.7 million shares and issuances
under the Company's Investor Plus and employee benefit programs in 2002 and 2003
also reduced basic earnings per share by $0.33 in 2003.
44
Net income in 2002 decreased 2.6% from $542 million in 2001. The decrease in net
income in 2002 is primarily due to impairments and other charges related to the
telecommunications and rail business operations, the discontinued operations of
NCNG, the rate case settlement of PEF, PEC severe storm costs and increased
benefit costs. Partially offsetting these items were continued customer growth
and usage at the utilities, lower depreciation at PEF, 2001 impairments in the
telecommunications and SRS business units, the impact of the change in market
value of CVOs and the elimination of goodwill amortization in 2002.
The Company's segments contributed the following profit or loss from continuing
operations for 2003, 2002 and 2001:
- --------------------------------------------------------------------------------------------------------------------
(in millions)
- --------------------------------------------------------------------------------------------------------------------
2003 Change 2002 Change 2001
- --------------------------------------------------------------------------------------------------------------------
PEC Electric $ 515 $ 2 $ 513 $ 45 $ 468
PEF 295 (28) 323 14 309
Fuels 235 59 176 (23) 199
CCO 20 (7) 27 23 4
Rail Services (1) 41 (42) (30) (12)
Other (17) 226 (243) (81) (162)
-----------------------------------------------------------------
Total Segment Profit (Loss) $ 1,047 $ 293 $ 754 $ (52) $ 806
Corporate (236) (34) (202) 63 (265)
-----------------------------------------------------------------
Total Income from Continuing Operations $ 811 $ 259 $ 552 $ 11 $ 541
Discontinued Operations, Net of Tax (8) 16 (24) (25) 1
Cumulative Effect of Changes in Accounting
Principles (21) (21) - - -
-----------------------------------------------------------------
Net Income $ 782 $ 254 $ 528 $ (14) $ 542
- --------------------------------------------------------------------------------------------------------------------
PROGRESS ENERGY CAROLINAS ELECTRIC
PEC Electric contributed segment profits of $515 million, $513 million and $468
million in 2003, 2002 and 2001, respectively. The slight increase in profits in
2003, when compared to 2002, was primarily due to customer growth, strong
wholesale sales during the first quarter of 2003, lower Service Company
allocations and lower interest costs, which were offset by unfavorable weather
in 2003, higher depreciation expense and increased benefit-related costs. The
increase in profits in 2002, when compared to 2001, was attributable to customer
growth, favorable weather in 2002, lower interest charges and the allocation of
tax benefits from the holding company partially offset by severe storm costs in
December 2002.
Revenues
PEC Electric's electric revenues for the years ended December 31, 2003, 2002 and
2001 and the percentage change by year and by customer class are as follows:
- -------------------------------------------------------------------------------------------------
(in millions)
- -------------------------------------------------------------------------------------------------
Customer Class 2003 % Change 2002 % Change 2001
- -------------------------------------------------------------------------------------------------
Residential $ 1,259 1.5% $ 1,241 7.7% $ 1,152
Commercial 850 2.2 832 6.0 785
Industrial 636 (1.4) 645 (1.4) 654
Governmental 79 1.3 78 4.0 75
------------- ------------- -------------
Total Retail Revenues 2,824 1.0 2,796 4.9 2,666
Wholesale 687 5.5 651 2.7 634
Unbilled (6) - 15 - (32)
Miscellaneous 84 9.1 77 1.3 76
------------- ------------- -------------
Total Electric Revenues $ 3,589 1.4% $ 3,539 5.8% $ 3,344
- -------------------------------------------------------------------------------------------------
45
PEC Electric's electric energy sales for 2003, 2002 and 2001 and the percentage
change by year and by customer class are as follows:
- ---------------------------------------------------------------------------------------------------
(in thousands of MWh)
- ---------------------------------------------------------------------------------------------------
Customer Class 2003 % Change 2002 % Change 2001
- ---------------------------------------------------------------------------------------------------
Residential 15,283 0.3% 15,239 6.0% 14,372
Commercial 12,557 0.7 12,468 4.1 11,972
Industrial 12,749 (2.6) 13,089 (1.8) 13,332
Governmental 1,408 (2.0) 1,437 1.0 1,423
------------- -------------- -------------
Total Retail Energy Sales 41,997 (0.6) 42,233 2.8 41,099
Wholesale 15,518 3.3 15,024 15.6 12,996
Unbilled (44) - 270 - (534)
------------- -------------- -------------
Total MWh Sales 57,471 (0.1%) 57,527 7.4% 53,561
- ---------------------------------------------------------------------------------------------------
PEC Electric's revenues, excluding recoverable fuel revenues of $901 million and
$851 million in 2003 and 2002, respectively, were unchanged from 2002 to 2003.
Milder weather in 2003, when compared to 2002 accounted for a $61 million retail
revenue reduction. While heating degree days were 4.8% above prior year, cooling
degree days were 25.2% below prior year. However, the more severe weather in the
northeast region of the United States during the first quarter of 2003 drove a
$19 million increase in wholesale revenues. Additionally, retail customer growth
in 2003 generated an additional $42 million of revenues in 2003. PEC Electric's
retail customer base increased as approximately 23,000 new customers were added
in 2003.
PEC's electric revenues, excluding recoverable fuel revenues of $851 million and
$734 million in 2002 and 2001, respectively, increased $78 million. During 2002,
residential and commercial sales reflected continued growth in the number of
customers served by PEC Electric, with approximately 26,000 new customers in
2002. Sales of energy and revenue increased in 2002 compared to 2001 for all
customer classes except industrial. Increases in retail sales and wholesale
sales were also driven by favorable weather during 2002 when compared to 2001.
Wholesale sales growth was partially offset by price declines in the wholesale
market.
Downturns in the economy during 2001, 2002 and 2003 impacted energy usage within
the industrial customer class. Total industrial revenues, excluding fuel
revenues, declined during 2003 when compared to 2002 and during 2002 when
compared to 2001 by $13 million and $24 million, respectively, as the number of
industrial customers decreased due to a slowdown in the textile industry, as
well as a decrease in usage in the chemical industry.
Expenses
Fuel and Purchased Power
Fuel expense increased $73 million in 2003, when compared to $752 million in
2002, primarily due to higher prices incurred for coal, oil and natural gas used
during generation. Costs for fuel per Btu increased for all three commodities
during the year. See movement in prices under Average Fuel Cost Summary in Part
I, Item 1, PEC Electric - Fuel and Purchased Power. Fuel expense increased $114
million in 2002, when compared to $638 million in 2001, primarily due to an 8.2%
increase in generation with a higher percentage of generation being produced by
combustion turbines, which have higher fuel costs.
Purchased power expense decreased $51 million in 2003, when compared to $347
million in 2002, mainly due to a decrease in the volume purchased as milder
weather reduced system requirements and due to the renegotiation at more
favorable terms of two contracts that expired during the year. For 2002,
purchased power decreased $7 million, when compared to $354 million in 2001,
mainly due to decreases in prices and volumes purchased.
Fuel expenses are recovered primarily through cost recovery clauses and, as
such, changes in expense have no material impact on operating results.
Operations and Maintenance (O&M)
O&M expense decreased $20 million in 2003 when compared to $802 million in 2002.
O&M expense in 2002 included severe storm costs of $27 million. Those costs
along with lower 2003 Service Company allocations of $16 million, due to the
change in allocation methodology as required by the SEC in early 2003, are the
primary reasons for decreased O&M expenses. This decrease was partially offset
by higher benefit-related costs of $21 million. PEC Electric incurred O&M costs
of $25 million related to three severe storms in 2003. The NCUC allowed deferral
of $24 million of these storm costs. These costs are being amortized over a
five-year period, beginning in the months the expenses were incurred. PEC
Electric amortized $3 million of these costs in 2003 which is included in
depreciation and amortization expense on the Consolidated Income Statement.
46
O&M expense increased $91 million in 2002 when compared to $711 million in 2001
primarily due to the 2002 storm costs of $27 million, which were not deferred.
O&M expense in 2002, when compared to 2001, was also negatively impacted by a
lower pension credit of $6 million, the establishment of an inventory reserve of
$11 million for materials that have no future benefit, increased salaries and
benefits and other increases in maintenance and outage support.
Depreciation and Amortization
Depreciation and amortization increased $38 million in 2003, when compared to
$524 million in 2002. Depreciation and amortization increased $74 million
related to the 2003 impact of the Clean Air legislation in North Carolina and
decreased $53 million related to the 2002 impact of the accelerated nuclear
amortization program. Both programs are approved by the state regulatory
agencies and are discussed further at Notes 7 and 21E to the Progress Energy
Consolidated Financial Statements. In addition, depreciation increased $19
million due to additional assets placed into service.
Depreciation and amortization increased $2 million in 2002 when compared to $522
million in 2001. PEC Electric recorded $53 million of accelerated amortization
expense in 2002 and $75 million in 2001 related to the nuclear amortization
program. The year-over-year favorability was offset by additional depreciation
recognized in 2002, as compared to 2001, on new assets that were placed in
service during 2002.
PEC filed a new depreciation study in 2004 that provides support for reducing
depreciation expense on an annual basis by approximately $45 million. The
reduction is primarily attributable to assumption changes for nuclear
generation, offset by increases for distribution assets. The new rates are
primarily effective January 1, 2004.
Interest Expense
Net interest expense was $194 million, $212 million and $241 million in 2003,
2002 and 2001, respectively. Declines in interest expense resulted from reduced
short-term debt and refinancing certain long-term debt with lower interest rate
debt.
Income Tax Expense
In 2003 and 2002, $24 million and $35 million, respectively, of the tax benefit
that was previously held at the Company's holding company was allocated to PEC
Electric. As required by an SEC order issued in 2002, holding company tax
benefits are allocated to profitable subsidiaries. Other fluctuations in income
taxes are primarily due to changes in pretax income.
PROGRESS ENERGY FLORIDA
PEF contributed segment profits of $295 million, $323 million and $309 million
in 2003, 2002 and 2001, respectively. The decrease in profits in 2003, when
compared to 2002, was primarily due to the impact of the 2002 rate case
stipulation, higher benefit-related costs primarily related to higher pension
expense, higher depreciation and the unfavorable impact of weather. These
amounts were partially offset by continued customer growth and lower interest
charges. The increase in profits in 2002, when compared to 2001, was attributed
to the impact of milder weather in 2001 as compared to 2002, continued customer
growth and the allocation of tax benefits from the holding company. These items
were partially offset by the impact of the 2002 rate case stipulation, increased
benefits costs and lower pension credit and higher system reliability and
enhancement spending.
PEF's profits in 2003 and 2002 were affected by the outcome of the rate case
stipulation, which included a one-time retroactive revenue refund in 2002, a
decrease in retail rates of 9.25% (effective May 1, 2002), provisions for
revenue sharing with the retail customer base, lower depreciation and
amortization and increased service revenue rates. See Note 7B to the Progress
Energy Consolidated Financial Statements for further discussion of the rate case
settlement.
47
Revenues
PEF's electric revenues for the years ended December 31, 2003, 2002 and 2001 and
the percentage change by year and by customer class, as well as the impact of
the rate case settlement on revenue, are as follows:
- ------------------------------------------------------------------------------------------------
(in millions)
- ------------------------------------------------------------------------------------------------
Customer Class 2003 % Change 2002 % Change 2001
- ------------------------------------------------------------------------------------------------
Residential $ 1,691 2.8% $ 1,645 0.1% $ 1,643
Commercial 740 1.2 731 (3.1) 754
Industrial 219 3.8 211 (5.4) 223
Governmental 181 4.6 173 (1.7) 176
Revenue Sharing Refund (35) - (5) - -
Retroactive Retail Rate Refund - - (35) - -
---------- ------------ -----------
Total Retail Revenues 2,796 2.8 2,720 (2.7) 2,796
Wholesale 227 (1.3) 230 (20.1) 288
Unbilled (2) - (3) - (22)
Miscellaneous 131 13.9 115 (23.8) 151
---------- ------------ -----------
Total Electric Revenues $ 3,152 2.9% $ 3,062 (4.7)% $ 3,213
- ------------------------------------------------------------------------------------------------
PEF's electric energy sales for the years ended December 31, 2003, 2002 and 2001
and the percentage change by year and by customer class are as follows:
- --------------------------------------------------------------------------------------------
(in thousands of MWh)
- --------------------------------------------------------------------------------------------
Customer Class 2003 % Change 2002 % Change 2001
- --------------------------------------------------------------------------------------------
Residential 19,429 3.6% 18,754 6.5% 17,604
Commercial 11,553 1.2 11,420 3.2 11,061
Industrial 4,000 4.3 3,835 (1.0) 3,872
Governmental 2,974 4.4 2,850 4.5 2,726
---------- ----------- -----------
Total Retail Energy Sales 37,956 3.0 36,859 4.5 35,263
Wholesale 4,323 3.4 4,180 (11.4) 4,719
Unbilled 233 - 5 - (511)
---------- ----------- -----------
Total MWh Sales 42,512 3.6% 41,044 4.0% 39,471
- --------------------------------------------------------------------------------------------
PEF's revenues, excluding fuel revenues of $1,487 million and $1,402 million in
2003 and 2002, respectively, increased $5 million from 2002 to 2003. Revenues
were favorably impacted by $49 million in 2003, primarily as a result of
customer growth (approximately 36,000 additional customers). In addition, other
operating revenues were favorable $16 million due primarily to higher wheeling
and transmission revenues and higher service charge revenues (resulting from
increased rates allowed under the 2002 rate settlement). These increases were
partially offset by the negative impact of the rate settlement, which decreases
revenues, lower wholesale sales and the impact of unfavorable weather. The
provision for revenue sharing increased $12 million in 2003 compared to the $5
million provision recorded in 2002. Revenues in 2003 were also impacted by the
final resolution of the 2002 revenue sharing provisions as the FPSC issued an
order in July of 2003 that required PEF to refund an additional $18 million to
customers related to 2002. The 9.25% rate reduction from the settlement
accounted for an additional $46 million decline in revenues. The 2003 impact of
the rate settlement was partially offset by the absence of the prior year
interim rate refund of $35 million. Lower wholesale revenues (excluding fuel
revenues) of $17 million and the $8 million impact of milder weather also
reduced base revenues during 2003.
PEF's revenues, excluding fuel revenues of $1,402 million and $1,453 million in
2002 and 2001, respectively, decreased $100 million from 2001 to 2002. The
revenue declines were driven by the $119 million impact of the rate case,
comprised of a $35 million one-time retroactive refund, a $79 million decrease
due to the rate reduction, and an estimated revenue sharing refund of $5
million. Additionally, wholesale revenues (excluding fuel revenues) declined $12
million, driven primarily by a contract that was not renewed. Year-over-year
comparisons were also unfavorably impacted by the recognition of $63 million of
revenue deferred from 2000 to 2001. Partially offsetting the unfavorable revenue
impacts was customer growth (approximately 33,000 additional customers), the
impact of weather conditions, primarily a warmer than normal summer in 2002, and
an increase in other operating revenue, resulting primarily from higher service
charge revenues (resulting from increased rates allowed under the 2002 rate case
settlement), along with higher transmission and wheeling revenues.
48
Expenses
Fuel and Purchased Power
Fuel used in generation and purchased power increased $87 million in 2003 when
compared to $1,349 million in 2002. The increase is due to higher costs to
generate electricity and higher purchased power costs as a result of an increase
in volume due to system requirements and higher natural gas prices.
Fuel used in generation and purchased power totaled $1,349 million for the year
ended December 31, 2002, a decrease of $71 million from 2001. The decrease is
primarily due to a lower recovery of fuel expense that resulted from a
mid-course correction of PEF's fuel cost recovery clause, as part of the rate
settlement, and lower purchased power costs, partially offset by an increase in
coal prices and volume from high system requirements.
Fuel and purchased power expenses are recovered primarily through cost recovery
clauses and, as such, changes in expense have no material impact on operating
results.
Operations and Maintenance (O&M)
O&M expense increased $49 million, when compared to $591 million in 2002. The
increase is largely related to increases in certain benefit-related expenses of
$36 million, which consisted primarily of higher pension expense of $27 million
and higher operational costs related to the CR3 nuclear outage and plant
maintenance.
O&M expense increased $96 million in 2002 when compared to $495 million in 2001,
due primarily to a reduced pension credit of $31 million, increased costs
related to the Commitment to Excellence program of $11 million and an increase
in other salary and benefit costs of $22 million related partially to increased
medical costs. The Commitment to Excellence program was initiated in 2002 to
improve service and reliability.
Depreciation and Amortization
Depreciation and amortization increased $12 million in 2003 when compared to
$295 million in 2002. Depreciation increased primarily as a result of additional
assets being placed into service that were partially offset by lower
amortization of the Tiger Bay regulatory asset of $2 million, which was fully
amortized in September 2003.
Depreciation and amortization decreased $158 million in 2002 when compared to
$453 million in 2001. In addition to the depreciation and amortization reduction
of approximately $79 million related to the rate case, depreciation declined an
additional $97 million related to accelerated amortization on the Tiger Bay
regulatory asset, which was created as a result of the early termination of
certain long-term cogeneration contracts. See Note 7D to the Progress Energy
Consolidated Financial Statements for further details on the rate case. PEF
amortized the regulatory asset according to a plan approved by the FPSC in 1997.
Interest Expense
Interest charges decreased $15 million in 2003 compared to $106 million in 2002
primarily due to the reversal of a regulatory liability for accrued interest
related to previously resolved tax matters.
Income Tax Expense
In 2003 and 2002, $13 million and $20 million, respectively, of the tax benefit
that was previously held at the Company's holding company was allocated to PEF.
As required by an SEC order issued in 2002, holding company tax benefits are
allocated to profitable subsidiaries. Other fluctuations in income taxes are
primarily due to changes in pretax income.
DIVERSIFIED BUSINESSES
The Company's diversified businesses consist of the Fuels segment, the CCO
segment, the Rail Services segment and the Other segment, which consists
primarily of the energy services operations and telecommunications operations.
49
FUELS
Fuels' segment profits increased $59 million in 2003 as compared to $176 million
in 2002 primarily due to an increase in synthetic fuel earnings, higher natural
gas earnings from increased natural gas prices, the addition of North Texas Gas
operations in March 2003 and the addition of Westchester in April 2002. These
results were partially offset by an asset impairment during the fourth quarter
of $11 million after-tax at the Kentucky May Coal Company. Fuels' 2002 profits
as compared to 2001 decreased $23 million primarily as a result of lower
synthetic fuel production, which was partially offset by increased natural gas
revenues as a result of the Westchester acquisition.
Fuels contributed segment profits of $235 million, $176 million and $199 million
in 2003, 2002 and 2001, respectively. The following summarizes Fuels' segment
profits for the years ended December 31, 2003, 2002 and 2001:
- ---------------------------------------------------------------------
(in millions) 2003 2002 2001
- ---------------------------------------------------------------------
Synthetic fuel operations $ 200 $ 156 $ 185
Natural gas operations 34 10 5
Coal fuel and other operations 1 10 9
-----------------------------------
Segment profits $ 235 $ 176 $ 199
- ---------------------------------------------------------------------
Synthetic Fuel Operations
Synthetic fuel operations generated profits of $200 million, $156 million and
$185 million, respectively, for the years ended December 31, 2003, 2002 and
2001. The production and sale of the synthetic fuel generate operating losses,
but qualify for tax credits under Section 29, which more than offset the effects
of such losses. See "Synthetic Fuels Tax Credits" under OTHER MATTERS below for
additional discussion of these tax credits. The operations resulted in the
following losses (prior to tax credits) and tax credits for 2003, 2002 and 2001:
- ----------------------------------------------------------------------
(in millions) 2003 2002 2001
- ----------------------------------------------------------------------
Tons sold 12.4 11.2 13.3
After-tax losses (excluding tax credits) $ (145) $ (135) $ (164)
Tax credits 345 291 349
----------------------------
Net Profit $ 200 $ 156 $ 185
- ----------------------------------------------------------------------
Synthetic fuels' net profits for 2003 increased as compared to 2002 due to
higher sales, improved margins and a higher tax credit per ton. The 2003 tax
credits also include a $12.7 million favorable true-up from 2002. Additionally,
synthetic fuels' results in 2003 include 13 months of operations for some
facilities. Prior to the fourth quarter of 2003, results of these synthetic
fuels' operations had been recognized one month in arrears. The net impact of
this action increased net income by $2 million for the year. Synthetic fuels'
net profits decreased in 2002 compared to 2001 due to lower sales. Synthetic
fuels' net profits decreased $29 million in 2002 when compared to 2001. The
decrease in profits was primarily due to a decline in tons produced as severe
storm costs incurred at one of the utilities reduced the Company's ability to
use the tax credits generated from production.
Natural Gas Operations
Natural gas operations generated profits of $34 million, $10 million and $5
million for the years ended December 31, 2003, 2002 and 2001, respectively. The
increase in production and price resulting from the acquisitions of Westchester
in 2002 and North Texas Gas in the first quarter of 2003 drove increased revenue
and earnings in 2003 as compared to 2002. In October of 2003, the Company
completed the sale of certain gas-producing properties owned by Mesa
Hydrocarbons, LLC. See Notes 4 and 3C to the Progress Energy Consolidated
Financial Statements for discussions of the Westchester and the North Texas Gas
acquisitions and the Mesa disposition. The increase in profits of $5 million
from 2001 to 2002 is due to an increase in gas production of 49% as a result of
the Westchester acquisition in April of 2002. The following summarizes the
production and revenues of the natural gas operations for 2003, 2002 and 2001 by
facility:
50
- ----------------------------------------------------------------
2003 2002 2001
- ----------------------------------------------------------------
Production in Bcf equivalent
Mesa 4.8 6.0 8.3
Westchester 13.5 5.8 -
North Texas Gas 7.1 - -
--------------------------
Total Production 25.4 11.8 8.3
--------------------------
Revenues in millions
Mesa $ 13 $ 15 $ 18
Westchester 65 24 -
North Texas Gas 38 - -
--------------------------
Total Revenues $ 116 $ 39 $ 18
--------------------------
Gross Margin
In millions of $ $ 91 $ 29 $ 15
As a % of revenues 78% 74% 83%
- ----------------------------------------------------------------
Coal Fuel and Other Operations
Coal fuel and other operations generated profits of $1 million, $10 million and
$9 million, respectively, for the years ended December 31, 2003, 2002 and 2001.
Coal fuel and other operations segment profits decreased $9 million from 2002 to
2003. The decrease is due primarily to the recording of an impairment of certain
assets at the Kentucky May Coal Mine totaling $11 million after-tax. See
discussion of impairment recorded in Note 9 to the Progress Energy Consolidated
Financial Statements.
COMPETITIVE COMMERCIAL OPERATIONS
CCO generates and sells electricity to the wholesale market from nonregulated
plants. These operations also include marketing activities.
CCO's operations generated segment profits of $20 million, $27 million and $4
million in 2003, 2002 and 2001, respectively. CCO's operations were most
significantly impacted by placing additional generating capability into service
in 2002 and 2003. The following summarizes the annual revenues, gross margin and
segment profits from the CCO plants:
- --------------------------------------------------------
(in millions) 2003 2002 2001
- --------------------------------------------------------
Total revenues $ 170 $ 92 $ 16
Gross margin
In millions of $ $ 141 $ 83 $ 14
As a % of revenues 83% 90% 87%
Segment profits $ 20 $ 27 $ 4
- --------------------------------------------------------
The increase in revenue for 2003 when compared to 2002 is primarily due to
increased contracted capacity on newly constructed plants, energy revenue from a
new, full-requirements power supply contract and a tolling agreement termination
payment received during the first quarter. Generating capacity increased from
1,554 megawatts at December 31, 2002 to 3,100 megawatts at December 31, 2003,
with the Effingham, Rowan Phase 2 and Washington plants being placed in service
in 2003. In the second quarter of 2003, PVI acquired from Williams Energy
Marketing and Trading a full-requirements power supply agreement with Jackson in
Georgia for $188 million, which resulted in additional revenues of $21 million
when compared to the same periods in 2002. The revenue increases related to
higher volumes were partially offset by higher depreciation costs of $22
million, increased interest charges of $16 million and other fixed charges.
The increase in revenues from 2001 to 2002 is due to the increase in capacity
during the year. In 2001 operations included one nonregulated plant with a
315-megawatt capacity and, at the end of 2002, plants with 1,554 megawatts of
capacity were operational. The increase in capacity was due to the transfer of
one plant from PEC Electric, the purchase of one operational plant from LG&E
Energy Corp. (See Note 4D to the Progress Energy Consolidated Financial
Statements) and one additional plant being placed in service. The increase in
capacity drove the increase in net income. The earnings potential was offset by
general softness in the energy market in 2002.
51
The Company has contracts representing 85%, 50%, and 50% of planned production
capacity for 2004 through 2006, respectively. The Company is actively pursuing
opportunities with current customers and other potential new customers to
utilize its excess capacity.
RAIL SERVICES
Rail Services' (Rail) operations represent the activities of Progress Rail and
include railcar and locomotive repair, trackwork, rail parts reconditioning and
sales, scrap metal recycling, railcar leasing and other rail-related services.
Rail's results for the year ended December 31, 2001, include Rail Services'
cumulative revenues and net loss from the date of acquisition, November 30,
2000, because Rail Services had been held for sale from the date of acquisition
through the second quarter of 2001.
Rail contributed losses of $1 million, $42 million and $12 million for the years
ended December 31, 2003, 2002 and 2001, respectively. The net loss in 2002
includes a $40 million after-tax estimated impairment of assets held for sale
related to Railcar Ltd., a leasing subsidiary of Progress Rail. In March 2003,
the Company signed a letter of intent to sell the majority of Railcar Ltd.
assets to The Andersons, Inc. The asset purchase agreement was signed in
November 2003 and the transaction closed on February 12, 2004. As such, assets
of Railcar Ltd. have been reported as assets held for sale. See Note 3B to the
Progress Energy Consolidated Financial Statements for discussion of this planned
divestiture. Excluding the impairment recorded in 2002, profits for Rail were
flat year over year 2003 compared to 2002. Earnings for Rail increased in 2002
compared to 2001, excluding the $40 million impairment booked in 2002 as
discussed above. Rail Services' 2002 results were favorably impacted by
aggressive cost cutting, new business opportunities and restructuring
initiatives. Rail Services' results for both years were affected by a downturn
in the overall economy and decreases in rail service procurement by major
railroads. A downturn in the domestic scrap market also impacted Rail Services
results for 2002.
An SEC order approving the merger of FPC required the Company to divest of
Progress Rail by November 30, 2003. However, the SEC has granted an extension
until 2006.
OTHER
Progress Energy's Other segment includes the operations of SRS, the
telecommunications operations of PTC and Caronet and the operation of nonutility
subsidiaries of PEC. SRS is engaged in providing energy services to industrial,
commercial and institutional customers to help manage energy costs and currently
focuses its activities in the southeastern United States. Telecommunication
operations provide broadband capacity services, dark fiber and wireless services
in Florida and the eastern United States. In December 2003, PTC and Caronet,
both wholly-owned subsidiaries of Progress Energy, and EPIK, a wholly-owned
subsidiary of Odyssey, contributed substantially all of their assets and
transferred certain liabilities to PTC LLC, a subsidiary of PTC. Subsequently,
the stock of Caronet was sold to an affiliate of Odyssey for $2 million in cash,
and Caronet became an indirect wholly-owned subsidiary of Odyssey. Following
consummation of all the transactions described above, PTC holds a 55% ownership
interest in, and is the parent of, PTC LLC. Odyssey holds a combined 45%
ownership interest in PTC LLC through EPIK and Caronet. The accounts of PTC LLC
are included in the Company's Consolidated Financial Statements since the
transaction date.
The Other segment contributed segment losses of $17 million, $243 million and
$162 million, respectively, for the years ended December 31, 2003, 2002 and
2001. Included in the 2003 segment losses is an investment impairment of $6
million after-tax on the Affordable Housing portfolio held by the nonutility
subsidiaries of PEC. The 2002 segment losses include an asset impairment and
other charges in the telecommunications business of $225 million after-tax.
Segment losses in 2001 include an asset and investment impairment recorded at
SRS ($46 million after-tax) and investment impairments in Interpath
Communications, Inc. (Interpath) of $102 million after-tax. See discussion of
impairments at Note 9 of the Progress Energy Consolidated Financial Statements.
52
CORPORATE SERVICES
Corporate Services (Corporate) includes the operations of the holding company,
Progress Energy Service Company and other consolidating and nonoperating
entities, as summarized below:
- ------------------------------------------------------------------------------------------------
Income (Expense) (in millions)
- ------------------------------------------------------------------------------------------------
2003 Change 2002 Change 2001
- ------------------------------------------------------------------------------------------------
Other interest expense $ (285) $ (10) $ (275) $ (14) $ (261)
Contingent value obligations (9) (37) 28 30 (2)
Tax reallocation (38) 18 (56) (56) -
Other income taxes 124 11 113 68 45
Other income (expense) (28) (16) (12) 35 (47)
------------- ------------ ------------
Segment loss $ (236) $ (34) $ (202) $ 63 $ (265)
- ------------------------------------------------------------------------------------------------
Net pre-tax interest charges in Corporate were $285 million, $275 million and
$261 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Interest expense increased $10 million in 2003 compared to 2002 due to a
decrease of $9 million in the amount of interest capitalized related to
construction at nonregulated generating plants, as construction was completed
and plants were placed in service. The increase in 2002, when compared to 2001,
was primarily related to increased debt associated with the purchase of
nonregulated generating facilities. This was partially offset by lower interest
rates and $19 million of interest capitalization in 2002 related to the building
of the nonregulated generating plants.
Progress Energy issued 98.6 million CVOs in connection with the FPC acquisition.
Each CVO represents the right to receive contingent payments based on the
performance of four synthetic fuel facilities owned by Progress Energy. The
payments, if any, are based on the net after-tax cash flows the facilities
generate. At December 31, 2003, 2002, and 2001, the CVOs had a fair market value
of approximately $23 million, $14 million, and $42 million, respectively.
Progress Energy recorded unrealized losses of $9 million and $2 million for the
years ended December 31, 2003 and 2001, and an unrealized gain of $28 million
for the year ended December 31, 2002 to record the changes in fair value of
CVOs, which had average unit prices of $0.23, $0.14, and $0.43 at December 31,
2003, 2002 and 2001, respectively.
As required by an SEC order issued in 2002, holding company tax benefits are
allocated to profitable subsidiaries. Tax benefits reallocated from the Holding
Company to the profitable subsidiaries increased Corporate's income tax expense
by $38 million and $56 million in 2003 and 2002. Other fluctuations in income
taxes are primarily due to changes in pretax income.
As part of the acquisition of FPC, goodwill of approximately $3.6 billion was
recorded, and amortization of $90 million was included in other income (expense)
at the Corporate segment in 2001. In accordance with Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets," (SFAS No.
142) effective January 1, 2002, the Company no longer amortizes goodwill. See
Note 8 to the Progress Energy Consolidated Financial Statements for more details
on goodwill.
DISCONTINUED OPERATIONS
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. As a result, the operating results of NCNG were reclassified to
discontinued operations for all reportable periods. Progress Energy sold NCNG
and ENCNG for net proceeds of approximately $450 million. Progress Energy
incurred a loss from discontinued operations of $8 million for the year ended
December 31, 2003 compared with a loss of $24 million for 2002. The loss for
2003 reflects the finalization of the sale of NCNG. See Note 3A to the Progress
Energy Consolidated Financial Statements for more information on this
divestiture.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
Progress Energy recorded adjustments for the cumulative effects of changes in
accounting principles due to the adoption of several new accounting
pronouncements. These adjustments totaled to a $21 million loss after-tax which
was due primarily to new Financial Accounting Standards Board (FASB) guidance
related to the accounting for certain contracts. This guidance discusses whether
the pricing in a contract that contains broad market indices qualifies for
certain exceptions that would not require the contract to be recorded at its
fair value. PEC Electric had a purchase power contract with Broad River LLC that
did not meet the criteria for an exception, and a negative fair value adjustment
was recorded in the fourth quarter of 2003 for $23 million after-tax. See Note
17A to the Progress Energy Consolidated Financial Statements and Note 12A to the
PEC Consolidated Financial Statements.
53
APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company prepared its consolidated financial statements in accordance with
accounting principles generally accepted in the United States. In doing so,
certain estimates were made that were critical in nature to the results of
operations. The following discusses those significant estimates that may have a
material impact on the financial results of the Company and are subject to the
greatest amount of subjectivity. Senior management has discussed the development
and selection of these critical accounting policies with the Audit Committee of
the Company's Board of Directors.
Utility Regulation
The Company's regulated utilities segments are subject to regulation that sets
the prices (rates) the Company is permitted to charge customers based on the
costs that regulatory agencies determine the Company is permitted to recover. At
times, regulators permit the future recovery through rates of costs that would
be currently charged to expense by a nonregulated company. This ratemaking
process results in deferral of expense recognition and the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in each state in which the Company operates, a
significant amount of regulatory assets has been recorded. The Company
continually reviews these assets to assess their ultimate recoverability within
the approved regulatory guidelines. Impairment risk associated with these assets
relates to potentially adverse legislative, judicial or regulatory actions in
the future. Additionally, the state regulatory agencies often provide
flexibility in the manner and timing of the depreciation of property, nuclear
decommissioning costs and amortization of the regulatory assets. Note 7 to the
Progress Energy Consolidated Financial Statements provides additional
information related to the impact of utility regulation on the Company.
Asset Impairments
The Company evaluates the carrying value of long-lived assets for impairment
whenever indicators exist. Examples of these indicators include current period
losses combined with a history of losses, or a projection of continuing losses,
or a significant decrease in the market price of a long-lived asset group. If an
indicator exists, the asset group held and used is tested for recoverability by
comparing the carrying value to the sum of undiscounted expected future cash
flows directly attributable to the asset group. If the asset group is not
recoverable through undiscounted cash flows or if the asset group is to be
disposed of, an impairment loss is recognized for the difference between the
carrying value and the fair value of the asset group. A high degree of judgment
is required in developing estimates related to these evaluations and various
factors are considered, including projected revenues and cost and market
conditions.
Due to the reduction in coal production at the Kentucky May Coal Mine, the
Company evaluated its long-lived assets in 2003 and recorded an impairment of
$17 million before tax ($11 million after-tax). See Note 9A to the Progress
Energy Consolidated Financial Statements for further information on this
impairment and other charges.
During 2002, the Company recorded pre-tax long-lived asset impairments of $305
million related to its telecommunications business. See Note 9A to the Progress
Energy Consolidated Financial Statements for further information on this
impairment and other charges. The fair value of these assets was determined
using an external valuation study heavily weighted on a discounted cash flow
methodology and using market approaches as supporting information.
The Company also continually reviews its investments to determine whether a
decline in fair value below the cost basis is other than temporary. In 2003, the
Company's affordable housing investment (AHI) portfolio was reviewed and deemed
to be impaired based on various factors including continued operating losses of
the AHI portfolio and management performance issues arising at certain
properties within the AHI portfolio. As a result, the Company recorded
impairments of $18 million on a pre-tax basis during the fourth quarter of 2003.
The Company also recorded an impairment of $3 million for a cost investment.
During 2002 and 2001, the Company recorded pre-tax impairments to its cost
method investment in Interpath of $25 million and $157 million, respectively.
The fair value of this investment was determined using an external valuation
study heavily weighted on a discounted cash flow methodology and using market
approaches as supporting information. These cash flows included numerous
assumptions including the pace at which the telecommunications market would
rebound. In the fourth quarter of 2002, the Company sold its remaining interest
in Interpath for a nominal amount.
54
Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, which requires that
goodwill be tested for impairment at least annually and more frequently when
indicators of impairment exist. See Note 8 to the Progress Energy Consolidated
Financial Statements for further detail on goodwill. SFAS No. 142 requires a
two-step goodwill impairment test. The Company performs the annual goodwill
impairment test each year. The first step, used to identify potential
impairment, compares the fair value of the reporting unit with its carrying
amount, including goodwill. The second step, used to measure the amount of the
impairment loss if step one indicates a potential impairment, compares the
implied fair value of the reporting unit goodwill with the carrying amount of
the goodwill.
The Company completed the initial transitional goodwill impairment test, which
indicated that the Company's goodwill was not impaired as of January 1, 2002.
The carrying amounts of goodwill at December 31, 2003 and 2002, for reportable
segments PEC Electric, PEF and CCO, are $1,922 million, $1,733 million and $64
million, respectively.
During 2003, the Other segment acquired $7 million in goodwill as part of the
PTC business combination with EPIK. The Company performed the annual goodwill
impairment test for the CCO segment in the first quarter of 2003, and the annual
goodwill impairment test for the PEC Electric and PEF segments in the second
quarter of 2003, which indicated no impairment. If the fair values for the
utility segments were lower by 10%, there still would be no impact on the
reported value of their goodwill.
During 2002, the Company completed the acquisition of two electric generating
projects, Walton County Power, LLC and Washington County Power, LLC. The
acquisitions resulted in goodwill of $64 million.
Synthetic Fuels Tax Credits
Progress Energy, through the Fuels business unit, produces coal-based synthetic
fuel. The production and sale of the synthetic fuel qualifies for tax credits
under Section 29 if certain requirements are satisfied, including a requirement
that the synthetic fuel differs significantly in chemical composition from the
feedstock used to produce such synthetic fuel and that the fuel was produced
from a facility that was placed in service before July 1, 1998. Any synthetic
fuel tax credit amounts not utilized are carried forward indefinitely and are
included in deferred taxes on the accompanying Consolidated Balance Sheets. See
Note 14 to the Progress Energy Consolidated Financial Statements for further
information on the synthetic fuel tax credits. All of Progress Energy's
synthetic fuel facilities have received PLRs from the IRS with respect to their
operations. These tax credits are subject to review by the IRS, and if Progress
Energy fails to prevail through the administrative or legal process, there could
be a significant tax liability owed for previously taken Section 29 credits,
with a significant impact on earnings and cash flows.
Pension Costs
As discussed in Note 16A to the Progress Energy Consolidated Financial
Statements, Progress Energy maintains qualified non-contributory defined benefit
retirement (pension) plans. The Company's reported costs are dependent on
numerous factors resulting from actual plan experience and assumptions of future
experience. For example, such costs are impacted by employee demographics,
changes made to plan provisions, actual plan asset returns and key actuarial
assumptions such as expected long-term rates of return on plan assets and
discount rates used in determining benefit obligations and annual costs.
Due to a slight decline in the market interest rates for high-quality (AAA/AA)
debt securities, which are used as the benchmark for setting the discount rate,
the Company lowered the discount rate to 6.3% at December 31, 2003, which will
increase the 2004 benefit costs recognized, all other factors remaining
constant. However, after a few years of negative asset returns due to equity
market declines, plan assets performed very well in 2003, with returns of
approximately 30%. That positive asset performance will result in decreased
pension cost in 2004. Evaluations of the effects of these factors have not been
completed, but the Company estimates that the 2004 total cost recognized for
pension will decrease by approximately $5 million from the amount recorded in
2003, due in large part to these factors.
The Company has pension plan assets, with a fair value of approximately $1.6
billion at December 31, 2003. The Company's expected rate of return on pension
plan assets is 9.25%. The Company reviews this rate on a regular basis. Under
Statement of Financial Accounting Standards No. 87, "Employer's Accounting for
Pensions" (SFAS No. 87), the expected rate of return used in pension cost
recognition is a long-term rate of return; therefore, the Company would only
55
adjust that return if its fundamental assessment of the debt and equity markets
changes or its investment policy changes significantly. The Company believes
that its pension plans' asset investment mix and historical performance support
the long-term rate of 9.25% being used. The Company did not adjust the rate in
response to short-term market fluctuations such as the abnormally high market
return levels of the latter 1990s, recent years' market declines and the market
rebound in 2003. A 0.25% change in the expected rate of return for 2003 would
have changed 2003 pension cost by approximately $4 million.
Another factor affecting the Company's pension cost, and sensitivity of the cost
to plan asset performance, is its selection of a method to determine the
market-related value of assets, i.e., the asset value to which the 9.25%
expected long-term rate of return is applied. SFAS No. 87 specifies that
entities may use either fair value or an averaging method that recognizes
changes in fair value over a period not to exceed five years, with the method
selected applied on a consistent basis from year to year. The Company has
historically used a five-year averaging method. When the Company acquired
Florida Progress Corporation (Florida Progress) in 2000, it retained the Florida
Progress historical use of fair value to determine market-related value for
Florida Progress pension assets. Changes in plan asset performance are reflected
in pension cost sooner under the fair value method than the five-year averaging
method and, therefore, pension cost tends to be more volatile using the fair
value method. For example, in 2003 the expected return for assets subject to the
averaging method was 3% lower than in 2002, whereas the expected return for
assets subject to the fair value method was 18% lower than in 2002.
Approximately 50% of the Company's pension plan assets is subject to each of the
two methods.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
Progress Energy is a registered holding company and, as such, has no operations
of its own. As a holding company, Progress Energy's primary cash obligations are
its common dividend and interest expense associated with $4.8 billion of senior
unsecured debt. The ability to meet its obligations is primarily dependent on
the earnings and cash flows of its two electric utilities and nonregulated
subsidiaries, and the ability of those subsidiaries to pay dividends or repay
funds to Progress Energy.
Other significant cash requirements of Progress Energy arise primarily from the
capital-intensive nature of its electric utility operations as well as the
expansion of its diversified businesses, primarily those of the Fuels segment.
Progress Energy relies upon its operating cash flow, generated primarily by its
two regulated electric utility subsidiaries, commercial paper facilities and its
ability to access long-term capital markets for its liquidity needs. Since a
substantial majority of Progress Energy's operating costs are related to its two
regulated electric utilities, a significant portion of these costs are recovered
from customers through fuel and energy cost recovery clauses.
As a registered holding company under Public Utility Holding Company Act of 1935
(PUHCA), Progress Energy obtains approval from the SEC for the issuance and sale
of securities as well as the establishment of intercompany extensions of credit
(utility and nonutility money pools). PEC and PEF participate in the utility
money pool, which allows the two utilities to lend and borrow between each
other. Progress Energy can lend money into the utility money pool but cannot
borrow funds. The nonutility money pool was established to allow Progress
Energy's nonregulated operations to lend and borrow funds amongst each other.
Progress Energy can also lend money to the nonutility money pool but cannot
borrow funds.
During 2003, the Company realized approximately $450 million of net cash
proceeds from the sale of NCNG and ENCNG. The Company also received net proceeds
of approximately $97 million in October 2003 for the sale of its Mesa gas
properties located in Colorado. Progress Energy used the proceeds from these
sales to reduce indebtedness, primarily commercial paper, then outstanding.
On March 1, 2004, Progress Energy used available cash and proceeds from the
issuance of commercial paper to retire $500 million 6.55% senior unsecured
notes. Cash and commercial paper capacity were created primarily from the sale
of the assets in 2003 as noted above.
For the 12 months ended December 31, 2003, the Company received approximately
$309 million of net proceeds through the sale of 7.6 million shares of common
stock issued through the Progress Energy Direct Stock Purchase and Dividend
Reinvestment Plan, and its 401(k) Savings and Stock Ownership Plan. The Company
expects to reduce the issuance of common stock in 2004.
Progress Energy's cash from operations and common stock issuances in 2004 is
expected to fund its capital expenditures. To the extent necessary, incremental
borrowings or commercial paper issuances may also be used as a source of
liquidity.
56
Progress Energy believes its internal and external liquidity resources will be
sufficient to fund its current business plans. Risk factors associated with
commercial paper backup credit facilities and credit ratings are discussed below
and in the "Risk Factors" section of this report.
The following discussion of Progress Energy's liquidity and capital resources is
on a consolidated basis.
CASH FLOWS FROM OPERATIONS
Cash from operations is the primary source used to meet operating requirements
and capital expenditures. Total cash from operations for 2003 was $1.8 billion,
compared to $1.6 billion in 2002. The increase in cash from operating activities
for 2003 when compared with 2002 is largely the result of improved operating
results at PEC. Total cash from operations for 2002 was $1.6 billion, up $271
million from 2001.
Progress Energy's two electric utilities produced over 90% of consolidated cash
from operations in 2003. It is expected that the two electric utilities will
continue to produce a majority of the consolidated cash flows from operations
over the next several years as its nonregulated investments, primarily
generation assets, improve asset utilization and begin generating operating cash
flows.
In addition, Fuels' synthetic fuel operations do not currently produce positive
operating cash flow primarily due to the difference in timing of when tax
credits are recognized for financial reporting purposes and when tax credits are
realized for tax purposes.
Total cash from operations provided the funding for approximately 90% of the
Company's capital expenditures, including property additions, nuclear fuel
expenditures and diversified business property additions during 2003, excluding
proceeds from asset sales of $579 million. Progress Energy expects its operating
cash flow to exceed its projected capital expenditures and common dividends
beginning in 2004 and current plans are to use the excess cash flow to reduce
debt.
INVESTING ACTIVITIES
Excluding proceeds from sales of subsidiaries and investments, cash used in
investing activities was $2.0 billion in 2003, down approximately $300 million
when compared with 2002. The decrease is due primarily to lower utility property
additions due to completion of Hines 2 construction at PEF and lower
acquisitions of nonregulated assets.
Cash used in investing was $2.2 billion in 2002, up $562 million when compared
with 2001. The increase was due primarily to PVI purchasing two generating
projects from LG&E Energy Corp. for approximately $350 million.
Capital expenditures for Progress Energy's regulated electric operations were
$1.0 billion or approximately 58% of consolidated capital expenditures in 2003,
excluding proceeds from asset sales. As shown in the table below, the Company
anticipates that the proportion of nonregulated capital spending to total
capital expenditures will decrease substantially in 2004 when compared with
2003. The decrease reflects the completion of PVI's nonregulated generation
portfolio in 2003. Progress Energy expects the majority of its capital
expenditures to be incurred at its regulated operations. Forecasted nonregulated
expenditures relate primarily to Progress Fuels and its gas operations,
primarily for drilling new wells.
(in millions) Actual Forecasted
----------- ------------------------------------------------
2003 2004 2005 2006
----------- ------------ -------------- -----------
Regulated capital expenditures $ 1,018 $ 980 $ 990 $ 1,020
Nuclear fuel expenditures 117 90 120 80
AFUDC - borrowed funds (7) (20) (20) (10)
Nonregulated capital expenditures 607 200 160 120
----------- ------------ -------------- -----------
Total $ 1,735 $ 1,250 $ 1,250 $ 1,210
=========== ============ ============== ===========
Regulated capital expenditures in the table above include total expenditures
from 2004 through 2006 of approximately $105 million expected to be incurred at
PEC fossil-fueled electric generating facilities to comply with Section 110 of
the Clean Air Act, referred to as the NOx SIP Call. See Note 21E to the Progress
Energy Consolidated Financial Statements.
57
In June 2002, legislation was enacted in North Carolina requiring the state's
electric utilities to reduce the emissions of nitrogen oxide (NOx) and sulfur
dioxide (SO2) from coal-fired power plants. PEC expects its capital costs to
meet these emission targets will be approximately $813 million by 2013. For the
years 2004 through 2006, the Company expects to incur approximately $320 million
of total capital costs associated with this legislation, which is included in
the table above. See Note 21E to the Progress Energy Consolidated Financial
Statements and "Current Regulatory Environment" under OTHER MATTERS below for
more information on this legislation.
In 2003, PEC determined that its external funding levels did not fully meet the
nuclear decommissioning financial assurance levels required by the United States
Nuclear Regulatory Commission (NRC). The funding levels had been adversely
affected by the declines in the equity markets. The total shortfall was
approximately $95 million (2010 dollars) for Robinson Unit No. 2, $82 million
(2016 dollars) for Brunswick Unit No. 1 and $99 million (2014 dollars) for
Brunswick Unit No. 2. PEC met the financial assurance requirements by obtaining
a parent company guarantee. The funding status for these facilities would be
positively affected by a continuing recovery in the equity markets and by the
approval of license extension applications.
PEC retains funds internally to meet decommissioning liability. The NCUC order
issued February 2004 found that by January 1, 2008 PEC must begin transitioning
these amounts to external funds. The transition of $131 million must be
completed by December 31, 2017, and at least 10% must be transitioned each year.
PEC has exclusively utilized external funding for its decommissioning liability
since 1994.
All projected capital and investment expenditures are subject to periodic review
and revision and may vary significantly depending on a number of factors
including, but not limited to, industry restructuring, regulatory constraints,
market volatility and economic trends.
FINANCING ACTIVITIES
Cash provided by operating activities and proceeds from asset sales exceeded
property and fuel additions by approximately $625 million. The excess, when
combined with $304 million of net cash generated from the sale of common stock,
resulted in an increase of cash and cash equivalents of $212 million after
paying common dividends. As of December 31, 2003, on a consolidated basis, the
Company had $868 million of long-term debt maturing in 2004, $300 million of
which was prefunded through issuances of long-term debt in 2003. On March 1,
2004, Progress Energy funded the maturity of its $500 million 6.55% senior
unsecured notes with cash on hand and commercial paper.
On January 15, 2004, PEC funded the maturity of $150 million 5.875% First
Mortgage Bonds with commercial paper proceeds. PEC also has $150 million 7.875%
First Mortgage Bonds maturing on April 15, 2004. It plans to use commercial
paper proceeds to fund this maturity.
During 2003, both PEC and PEF took advantage of historically low interest rates
and refinanced several issues of debt.
In February 2003, PEF issued $425 million of First Mortgage Bonds, 4.80% Series,
Due March 1, 2013 and $225 million of First Mortgage Bonds, 5.90% Series, Due
March 1, 2033. Proceeds from this issuance were used to repay the balance of its
outstanding commercial paper, to refinance its secured and unsecured
indebtedness, including $150 million of PEF's First Mortgage Bonds, 8% Series,
Due December 1, 2022 at 103.75% of the principal amount of such bonds.
On March 1, 2003, $70 million of PEF's First Mortgage Bonds, 6.125% Series, Due
March 1, 2003, matured. PEF funded the maturity with commercial paper.
On May 27, 2003, PEC redeemed $150 million of First Mortgage Bonds, 7.5% Series,
Due March 1, 2023 at 103.22% of the principal amount of such bonds. PEC funded
the redemption with commercial paper.
On July 1, 2003, $110 million of PEF's First Mortgage Bonds, 6.0% Series, Due
July 1, 2003 and $35 million of PEF's medium-term notes, 6.62% Series, matured.
PEF funded the maturity with commercial paper.
On August 15, 2003, PEC redeemed $100 million of First Mortgage Bonds, 6.875%
Series, Due August 15, 2023 at 102.84%. PEC funded the redemption with
commercial paper.
58
On September 11, 2003, PEC issued $400 million of First Mortgage Bonds, 5.125%
Series, Due September 15, 2013 and $200 million of First Mortgage Bonds, 6.125%
Series, Due September 15, 2033. Proceeds from this issuance were used to reduce
the balance of PEC's outstanding commercial paper and short-term notes payable
to affiliated companies, which notes represent PEC's borrowings under the
internal money pool operated by Progress Energy.
On November 21, 2003, PEF issued $300 million of First Mortgage Bonds, 5.10%
Series Due December 1, 2015. Proceeds from this issuance were used to refinance
$100 million of PEF's First Mortgage Bonds, 7% Series, Due 2023 at 103.19% of
the principal amount of such bonds and to reduce the outstanding balance of its
notes payable to affiliates.
The amount of debt issued by PEC and PEF in September and November,
respectively, took into consideration debt maturities and other financing needs
for 2004. As such, neither PEC nor PEF anticipate the need to issue long-term
debt in 2004.
In March 2003, Progress Genco Ventures LLC (Genco), a wholly-owned subsidiary of
PVI, terminated its $50 million working capital credit facility. Under a related
construction facility, Genco has drawn $241 million at December 31, 2003.
During 2003, Progress Energy obtained a new three-year financing order which
will expire September 30, 2006. Under the new order, Progress Energy, the
holding company, can issue up to $2.8 billion of long-term securities, $1.5
billion of short-term debt and $3 billion of parent guarantees.
At December 31, 2003, the Company and its subsidiaries had committed lines of
credit totaling $1.6 billion, for which there were no loans outstanding. All of
the credit facilities supporting the $1.6 billion of credit were arranged
through a syndication of commercial banks. There are no bilateral contracts
associated with these facilities. These lines of credit support the Company's
commercial paper borrowings. The following table summarizes the Company's credit
facilities:
(in millions)
Company Description Total
- ------------------------------------------------------------------------------
Progress Energy, Inc. 364-Day (expiring 11/10/04) $ 250
Progress Energy, Inc. 3-Year (expiring 11/13/04) 450
Progress Energy Carolinas, Inc. 364-Day (expiring 7/29/04) 165
Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285
Progress Energy Florida, Inc. 364-Day (expiring 3/31/04) 200
Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200
-----------
Total credit facilities $ 1,550
===========
The Company's financial policy precludes issuing commercial paper in excess of
its supporting lines of credit. At December 31, 2003, the Company did not have
any commercial paper outstanding, leaving $1.6 billion available for issuance.
In addition, the Company had requirements to pay minimal annual commitment fees
to maintain its credit facilities. At December 31, 2002, the total amount of
commercial paper outstanding was $695 million.
In addition, these credit agreements and Genco's $241 million bank facility
contain various terms and conditions that could affect the Company's ability to
borrow under these facilities. These include a maximum debt-to-total capital
ratio, an interest coverage test, a material adverse change clause and
cross-default provisions.
All of the credit facilities and Genco's bank facility include a defined maximum
total debt-to-total capital ratio (leverage) and coverage ratios. At December
31, 2003, the calculated ratios for these four companies, pursuant to the terms
of the agreements, are as follows:
59
Maximum Actual Minimum Actual
Leverage Leverage (a) Coverage Coverage
Company Ratio Ratio Ratio Ratio
- ---------------------------------------------------------------------------------------------
Progress Energy, Inc. 68% 61.5% 2.5 : 1 3.74 : 1
Progress Energy Carolinas, Inc. 65% 51.4% n/a n/a
Progress Energy Florida, Inc. 65% 51.5% 3.0 : 1 9.22 : 1
Progress Genco Ventures, LLC 40% 24.6% 1.25 : 1 6.35 : 1
- ---------------------------------------------------------------------------------------------
(a) Indebtedness as defined by the bank agreements includes certain letters
of credit and guarantees which are not recorded on the Consolidated
Balance Sheets.
The credit facilities of Progress Energy, PEC, PEF and Genco include a provision
under which lenders could refuse to advance funds in the event of a material
adverse change in the borrower's financial condition.
Each of these credit agreements contains cross-default provisions for defaults
of indebtedness in excess of $10 million. Under these provisions, if the
applicable borrower or certain subsidiaries of the borrower fail to pay various
debt obligations in excess of $10 million, the lenders could accelerate payment
of any outstanding borrowing and terminate their commitments to the credit
facility. Progress Energy's cross-default provision only applies to Progress
Energy and its significant subsidiaries (i.e., PEC, Florida Progress, PEF,
Progress Capital Holdings, Inc. (PCH), PVI and Progress Fuels).
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, primarily
commercial paper issued by the holding company, not its subsidiaries. In the
event that these indenture cross-default provisions are triggered, the debt
holders could accelerate payment of approximately $4.3 billion in long-term
debt, as of March 1, 2004. Certain agreements underlying the Company's
indebtedness also limit its ability to incur additional liens or engage in
certain types of sale and leaseback transactions.
The Company has on file with the SEC a shelf registration statement under which
senior notes, junior debentures, common and preferred stock and other trust
preferred securities are available for issuance by the Company. At December 31,
2003, the Company had approximately $1 billion available under this shelf
registration.
Progress Energy and PEF each have an uncommitted bank bid facility authorizing
each of them to borrow and re-borrow, and have loans outstanding at any time, up
to $300 million and $100 million, respectively. At December 31, 2003, there were
no outstanding loans against these facilities.
PEC currently has on file with the SEC a shelf registration statement under
which it can issue up to $900 million of various long-term securities. PEF
currently has on file registration statements under which it can issue an
aggregate of $750 million of various long-term debt securities.
Both PEC and PEF can issue First Mortgage Bonds under their respective First
Mortgage Bond indentures. At December 31, 2003, PEC and PEF could issue up to
$2.8 billion and $3.4 billion based on property additions and $1.9 billion and
$76 million based upon retirements.
The following table shows Progress Energy's and Progress Energy Carolinas'
capital structure at December 31, 2003 and 2002:
Progress Energy PEC
-------------------------- ------------------------
2003 2002 2003 2002
- -------------------------------------------------------------------------
Common Stock 40.6% 38.2% 48.2% 46.6%
Preferred Stock 0.5% 0.5% 0.9% 0.9%
Total Debt 58.9% 61.3% 50.9% 52.5%
The amount and timing of future sales of company securities will depend on
market conditions, operating cash flow, asset sales and the specific needs of
the Company. The Company may from time to time sell securities beyond the amount
needed to meet capital requirements in order to allow for the early redemption
of long-term debt, the redemption of preferred stock, the reduction of
short-term debt or for other general corporate purposes.
60
CREDIT RATING MATTERS
The major credit rating agencies have currently rated the Company's securities
as follows:
Moody's
Investors Service Standard & Poor's Fitch Ratings
- ----------------------------------------------------------------------------------------------------
Progress Energy, Inc.
Corporate Credit Rating Not Applicable BBB Not Applicable
Senior Unsecured Baa2 BBB- BBB-
Commercial Paper P-2 A-2 Not Applicable
Progress Energy Carolinas, Inc.
Corporate Credit Rating Not Applicable BBB Not Applicable
Commercial Paper P-2 A-2 F2
Senior Secured Debt A3 BBB A-
Senior Unsecured Debt Baa1 BBB BBB+
Progress Energy Florida, Inc.
Corporate Credit Rating Not Applicable BBB Not Applicable
Commercial Paper P-1 A-2 F2
Senior Secured Debt A1 BBB A-
Senior Unsecured Debt A2 BBB BBB+
FPC Capital I
Preferred Stock* Baa1 BB+ Not Applicable
Progress Capital Holdings, Inc.
Senior Unsecured Debt* A3 BBB- Not Applicable
- ----------------------------------------------------------------------------------------------------
*Guaranteed by Florida Progress Corporation
These ratings reflect the current views of these rating agencies and no
assurances can be given that these ratings will continue for any given period of
time. However, the Company monitors its financial condition as well as market
conditions that could ultimately affect its credit ratings.
The Company and its subsidiaries' debt indentures and credit agreements do not
contain any "ratings triggers," which would cause the acceleration of interest
and principal payments in the event of a ratings downgrade. However, in the
event of a downgrade, the Company and/or its subsidiaries may be subject to
increased interest costs on the credit facilities backing up the commercial
paper programs. The Company and its subsidiaries have certain contracts which
have provisions that are triggered by a ratings downgrade. These contracts
include counterparty trade agreements, derivative contracts, certain Progress
Energy guarantees and various types of third-party purchase agreements. None of
these contracts would require any action on the part of Progress Energy or its
subsidiaries unless the ratings downgrade results in a rating below investment
grade.
The power supply agreement with Jackson Electric Membership Corporation that PVI
acquired from Williams Energy Marketing and Trading Company (See PART I, ITEM 1,
General, Wholesale Energy Contract Acquisition) included a performance guarantee
that Progress Energy assumed. In the event that Progress Energy's credit ratings
fall below investment grade, Progress Energy will be required to provide
additional security for its guarantee in form and amount acceptable to Jackson.
See Progress Energy, Inc. Risk Factors for additional discussion.
In February 2003, Moody's Investors Service announced that it was lowering
Progress Energy, Inc.'s senior unsecured debt rating from Baa1 to Baa2, and
changing the outlook of the rating from negative to stable. Moody's cited the
slower-than-planned pace of the Company's efforts to pay down debt from its
acquisition of Florida Progress as the primary reason for the ratings change.
Moody's also changed the outlook of PEF (A1 senior secured) and PCH (A3 senior
unsecured) from stable to negative and lowered the trust preferred rating of FPC
Capital I from A3 to Baa1 with a negative outlook.
Also in February 2003, Fitch Ratings Service assigned an initial rating to
Progress Energy's senior unsecured debt of BBB-. No short-term rating was
assigned.
Fitch also downgraded the ratings of PEF and PEC. PEF's senior secured rating
was changed to A- from AA- and its senior unsecured rating was changed to BBB+
from A+. PEF's short-term rating was changed to F-2 from F-1+. PEC's senior
secured rating was changed to A- from A+ and its senior unsecured rating was
changed to BBB+ from A. PEC's short-term rating was changed to F-2 from F-1.
Fitch's outlook for all three rated entities is stable.
61
In August 2003, Standard & Poor's (S&P) credit rating agency announced that it
had lowered its corporate credit rating on Progress Energy Inc., PEC, PEF, and
Florida Progress to BBB from BBB+. The outlook of the ratings was changed from
negative to stable.
These changes have not had a material impact on the companies' access to capital
or their financial results.
Interest Rate Derivatives
Progress Energy uses interest rate derivative instruments to manage the fixed
and variable rate debt components of its debt portfolio. The Company's long-term
objective is to maintain a debt portfolio mix of approximately 30% variable rate
debt, 70% fixed rate. At December 31, 2003, Progress Energy's variable rate and
fixed rate debt comprised 16% and 84%, respectively, including the effects of
interest rate derivatives.
During 2003, cash proceeds from the sale of NCNG and gas reserves were used to
pay down debt, primarily commercial paper. While this reduced the Company's
floating rate portion well below its long-term target of 30%, on March 1, 2004,
the Company issued commercial paper to fund a portion of the maturing $500
million 6.55% senior unsecured notes, increasing the amount of floating rate
debt back to over 20%.
Progress Fuels periodically enters into derivative instruments to hedge its
exposure to price fluctuations on natural gas sales. At December 31, 2003,
Progress Fuels had approximately 19 Bcf of cash flow hedges in place for its
natural gas production. These positions extend through December 2005.
Genco has a floating rate credit facility that requires, as part of the loan
terms, a cash flow hedge against floating interest rate exposure. In order to
satisfy this requirement, Genco entered into a series of interest rate collars
during 2002 with notional amounts up to a maximum of $195 million and a final
maturity date of March 20, 2007.
Contractual Obligations
The following table reflects Progress Energy's contractual cash obligations and
other commercial commitments at December 31, 2003 in the respective periods in
which they are due:
(in millions)
- ---------------------------------------------------------------------------------------------------------
Less than 1 More than 5
Contractual Obligations Total year 1-3 years 3-5 years years
- ---------------------------------------------------------------------------------------------------------
Long-term debt $ 10,874 $ 868 $ 1,256 $ 1,742 $ 7,008
Capital lease obligations 50 4 8 7 31
Operating leases 307 38 60 41 168
Fuel and purchased power 10,683 1,672 1,976 1,312 5,723
Other purchase obligations 369 140 78 27 124
North Carolina clean air capital
commitments 783 90 230 210 253
Funding obligations 182 51 - 13 118
Other commitments 111 26 52 33 -
------------------------------------------------------------------
Total $ 23,359 $ 2,889 $ 3,660 $ 3,385 $ 13,425
==================================================================
Information on the Company's contractual obligations at December 31, 2003 is
included in the notes to the Progress Energy Consolidated Financial Statements.
Future debt maturities are included in Note 12 to the Progress Energy
Consolidated Financial Statements. The Company's fuel and purchased power
obligations have expiration dates ranging from 2004 to 2025 and are included in
Note 21A to the Progress Energy Consolidated Financial Statements. The Company's
other purchase obligations are included in Note 21A to the Progress Energy
Consolidated Financial Statements. The Company's lease obligations are included
in Note 21C to the Progress Energy Consolidated Financial Statements. PEC's
North Carolina clean air legislation capital commitments are described in Note
21E to the Progress Energy Consolidated Financial Statements. In 2004, the
Company expects to make $51 million of required contributions directly to
retirement plan assets. Decommissioning cost provisions are included in Note 5D
to the Progress Energy Consolidated Financial Statements. In 2008, PEC must
begin transitioning amounts currently retained internally to its external
decommissioning funds. The transition of $131 million must be complete by
December 31, 2017, and at least 10% must be transitioned each year. The
Company's other commitments are included in Note 21B to the Progress Energy
Consolidated Financial Statements.
62
The Company takes into consideration the future commitments shown above when
assessing its liquidity and future financing needs.
The Company's maturing debt obligations are generally expected to be refinanced
with new debt issuances in the capital markets. However, the Company does plan
to annually reduce its leverage by one to two percentage points over the next
few years through the sale of assets and excess operating cash flow.
Fuel and purchased power commitments represent the majority of the Company's
remaining future commitments after its debt obligations. Essentially all of the
Company's fuel and purchased power costs are recovered through pass-through
clauses in accordance with North Carolina, South Carolina and Florida
regulations and therefore do not require separate liquidity support.
OTHER MATTERS
CURRENT REGULATORY ENVIRONMENT
General
The Company's electric utility operations in North Carolina, South Carolina and
Florida are regulated by the NCUC, the Public Service Commission of South
Carolina (SCPSC) and the FPSC, respectively. The electric businesses are also
subject to regulation by the FERC, the NRC and other federal and state agencies
common to the utility business. In addition, the Company is subject to SEC
regulation as a registered holding company under PUHCA. As a result of
regulation, many of the fundamental business decisions, as well as the rate of
return the electric utilities are permitted to earn, are subject to the approval
of governmental agencies.
Electric Industry Restructuring
PEC and PEF continue to monitor any developments toward a more competitive
environment and have actively participated in regulatory reform deliberations in
North Carolina, South Carolina and Florida. Movement toward deregulation in
these states has been affected by recent developments, including developments
related to deregulation of the electric industry in other states. The Company
expects the legislatures in all three states will continue to monitor the
experiences of states that have implemented electric restructuring legislation.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
Florida Retail Rate Proceeding
In March 2002, the parties in PEF's rate case entered into a Stipulation and
Settlement Agreement (the Agreement) related to retail rate matters. The
Agreement was approved by the FPSC and is generally effective from May 1, 2002
through December 31, 2005; provided, however, that if PEF's base rate earnings
fall below a 10% return on equity, PEF may petition the FPSC to amend its base
rates. See Note 7D to the Progress Energy Consolidated Financial Statements for
additional information on the Agreement.
North Carolina Clean Air Legislation
In June 2002, legislation was enacted in North Carolina requiring the state's
electric utilities to reduce the emissions of NOx and SO2 from coal-fired power
plants. Progress Energy expects its capital costs to meet these emission targets
to be approximately $813 million by 2013, of which approximately $30 million has
been expended through December 31, 2003. PEC currently has approximately 5,100
MW of coal-fired generation in North Carolina that is affected by this
legislation. The legislation requires the emissions reductions to be completed
in phases by 2013, and applies to each utility's total system rather than
setting requirements for individual power plants. The legislation also freezes
the utilities' base rates for five years unless there are significant cost
changes due to governmental action or other extraordinary events beyond the
control of the utilities or unless the utilities persistently earn a return
substantially in excess of the rate of return established and found reasonable
by the NCUC in the utilities' last general rate case. Further, the legislation
allows the utilities to recover from their retail customers the projected
capital costs during the first seven years of the 10-year compliance period
beginning on January 1, 2003. The utilities must recover at least 70% of their
projected capital costs during the five-year rate freeze period. Pursuant to the
law, PEC entered into an agreement with the state of North Carolina to transfer
to the state all future emissions allowances it generates from over-complying
with the federal emission limits when these units are completed. The law also
requires the state to undertake a study of mercury and carbon dioxide emissions
63
in North Carolina. Operation and maintenance costs will increase due to the
additional personnel, materials and general maintenance associated with the
equipment. Operation and maintenance expenses are recoverable through base
rates, rather than as part of this program. Progress Energy cannot predict the
future regulatory interpretation, implementation or impact of this law.
Florida Proposed Clean Air Legislation
In 2004, a bill was introduced in the Florida legislature that would require
significant reductions in SO2, NOx and particulate emissions from certain coal,
natural gas and oil-fired generating units owned or operated by investor-owned
electric utilities, including PEF. The SO2 and NOx reductions would be effective
beginning with calendar year 2010 and the particulate reductions would be
effective beginning with calendar year 2012. Under the proposed legislation, the
FPSC would be authorized to allow the utilities to recover the costs of
compliance with the emission reductions over a period not greater than seven
years beginning in 2005, but the utilities' rates would be frozen at 2004 levels
for at least five years of the maximum recovery period. The Company cannot
predict the outcome of this matter.
Other Retail Rate Matters
See Note 7B to the Progress Energy Consolidated Financial Statements for
additional information on the Company's other retail rate matters.
Regional Transmission Organizations and Standard Market Design
In 2000, the FERC issued Order 2000 regarding RTOs. This Order set minimum
characteristics and functions that RTOs must meet, including independent
transmission service. In July 2002, the FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination through
Open Access Transmission Service and Standard Electricity Market Design (SMD
NOPR). If adopted as proposed, the rules set forth in the SMD NOPR would
materially alter the manner in which transmission and generation services are
provided and paid for. PEC and PEF, as subsidiaries of Progress Energy, filed
comments in November 2002 and supplemental comments in January 2003. In April
2003, the FERC released a White Paper on the Wholesale Market Platform. The
White Paper provides an overview of what the FERC currently intends to include
in a final rule in the SMD NOPR docket. The White Paper retains the fundamental
and most-protested aspects of SMD NOPR, including mandatory RTOs and the FERC's
assertion of jurisdiction over certain aspects of retail service. The FERC has
not yet issued a final rule on SMD NOPR. The Company cannot predict the outcome
of these matters or the effect that they may have on the GridFlorida and
GridSouth proceedings currently ongoing before the FERC. It is unknown what
impact the future proceedings will have on the Company's earnings, revenues or
prices. See Note 7C to the Progress Energy Consolidated Financial Statements for
additional information on GridFlorida and GridSouth.
FRANCHISE LITIGATION
Three cities, with a total of approximately 18,000 customers, have litigation
pending against PEF in various circuit courts in Florida. Three other cities,
with a total of approximately 30,000 customers, have subsequently settled their
lawsuits with PEF and signed new, 30-year franchise agreements. The lawsuits
principally seek 1) a declaratory judgment that the cities have the right to
purchase PEF's electric distribution system located within the municipal
boundaries of the cities, 2) a declaratory judgment that the value of the
distribution system must be determined through arbitration, and 3) injunctive
relief requiring PEF to continue to collect from PEF's customers and remit to
the cities, franchise fees during the pending litigation, and as long as PEF
continues to occupy the cities' rights-of-way to provide electric service,
notwithstanding the expiration of the franchise ordinances under which PEF had
agreed to collect such fees. Five circuit courts have entered orders requiring
arbitration to establish the purchase price of PEF's electric distribution
system within five cities. Two appellate courts have upheld those circuit court
decisions and authorized cities to determine the value of PEF's electric
distribution system within the cities through arbitration. Arbitration in one of
the cases (the City of Casselberry) was held in August 2002. Following
arbitration, the parties entered settlement discussions, and in July 2003, the
City approved a settlement agreement and a new, 30-year franchise agreement with
PEF. The settlement resolves all pending litigation with that city. A second
arbitration (with the 13,000-customer City of Winter Park) was completed in
February 2003. That arbitration panel issued an award in May 2003 setting the
value of PEF's distribution system within the City of Winter Park at
approximately $32 million, not including separation and reintegration costs and
construction work in progress, which could add several million dollars to the
award. The panel also awarded PEF approximately $11 million in stranded costs.
In September 2003, Winter Park voters passed a referendum that would authorize
the City to issue bonds of up to approximately $50 million to acquire PEF's
electric distribution system. The City has not yet definitively decided whether
it will acquire the system, but has indicated that it will seek wholesale power
supply bids and bids to operate and maintain the distribution system. At this
time, whether and when there will be further proceedings regarding the City of
Winter Park cannot be determined. A third arbitration (with the 2,500-customer
Town of Belleair) was completed in June 2003. In September 2003, the arbitration
panel issued an award in that case setting the value of the electric
distribution system within the Town at approximately $6 million. The panel
further required the Town to pay to PEF its requested $1 million in separation
and reintegration costs and approximately $2 million in stranded costs. The Town
has not yet decided whether it will attempt to acquire the system. At this time,
whether and when there will be further proceedings regarding the Town of
Belleair cannot be determined. A fourth arbitration (with the 13,000-customer
City of Apopka) had been scheduled for January 2004. In December 2003, the
Apopka City Commission voted on first reading to approve a settlement agreement
and a 30-year franchise with PEF. The settlement and franchise became effective
upon approval by the Commission at a second reading of the franchise in January
2004. The settlement resolves all outstanding litigation between the parties.
Arbitration in the remaining city's litigation (the 1,500-customer City of
Edgewood) has not yet been scheduled.
64
As part of the above litigation, two appellate courts have also reached opposite
conclusions regarding whether PEF must continue to collect from its customers
and remit to the cities "franchise fees" under the expired franchise ordinances.
PEF has filed an appeal with the Florida Supreme Court to resolve the conflict
between the two appellate courts. The Florida Supreme Court held oral argument
in one of the appeals in August 2003. Subsequently, the Court requested briefing
from the parties in the other appeal, which was completed in November 2003. The
Court has not yet issued a decision in these cases. The Company cannot predict
the outcome of these matters at this time.
NUCLEAR
In the Company's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdictions, the provisions
for nuclear decommissioning costs are approved by the FERC. See Note 5D to the
Progress Energy Consolidated Financial Statements for a discussion of the
Company's nuclear decommissioning costs.
SYNTHETIC FUELS TAX CREDITS
Progress Energy, through the Fuels business segment, produces coal-based solid
synthetic fuel. The production and sale of the synthetic fuel qualifies for tax
credits under Section 29 if certain requirements are satisfied, including a
requirement that the synthetic fuel differs significantly in chemical
composition from the feedstock used to produce such synthetic fuel and that the
fuel was produced from a facility that was placed in service before July 1,
1998. Any synthetic fuel tax credit amounts not utilized are carried forward
indefinitely and are included in deferred taxes on the accompanying Consolidated
Balance Sheets. See Note 14 to the Progress Energy Consolidated Financial
Statements. All entities have received PLRs from the IRS with respect to their
synthetic fuel operations. These tax credits are subject to review by the IRS,
and if Progress Energy fails to prevail through the administrative or legal
process, there could be a significant tax liability owed for previously taken
Section 29 credits, with a significant impact on earnings and cash flows. Total
Section 29 credits generated to date (including FPC prior to its acquisition by
the Company) are approximately $1,243 million. The current Section 29 tax credit
program expires at the end of 2007.
One of the Company's synthetic fuel entities, Colona Synfuel Limited
Partnership, L.L.L.P. (Colona), from which the Company (and FPC prior to its
acquisition by the Company) has been allocated approximately $317 million in tax
credits to date, is being audited by the IRS. The Company is audited regularly
in the normal course of business, as are most similarly situated companies, and
the audit of Colona was expected.
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS Pre-Filing Agreement
(PFA) program. The PFA program allows taxpayers to voluntarily accelerate the
IRS exam process in order to seek resolution of specific issues. Either the
Company or the IRS can withdraw from the program at any time, and issues not
resolved through the program may proceed to the next level of the IRS exam
process.
65
In June 2003, the Company was informed that IRS field auditors had raised
questions regarding the chemical change associated with coal-based synthetic
fuel manufactured at its Colona facility and the testing process by which the
chemical change is verified. (The questions arose in connection with the
Company's participation in the PFA program.) The chemical change and the
associated testing process were described as part of the PLR request for Colona.
Based on that application, the IRS ruled in Colona's PLR that the synthetic fuel
produced at Colona undergoes a significant chemical change and thus qualifies
for tax credits under Section 29.
In October 2003, the National Office of the IRS informed the Company that it had
rejected the IRS field auditors' challenges regarding whether the synthetic fuel
produced at the company's Colona facility was the result of a significant
chemical change. The National Office had concluded that the experts, engaged by
Colona who test the synthetic fuel for chemical change, use reasonable
scientific methods to reach their conclusions. Accordingly, the National Office
will not take any adverse action on the PLR that has been issued for the Colona
facility.
Although this ruling applies only to the Colona facility, the Company believes
that the National Office's reasoning would be equally applicable to the other
Progress Energy facilities. The Company applies essentially the same chemical
process and uses the same independent laboratories to confirm chemical change in
the synthetic fuel manufactured at each of its other facilities.
In February 2004, subsidiaries of the Company finalized execution of the Colona
Closing Agreement with the IRS concerning their Colona synthetic fuel
facilities. The Colona Closing Agreement provided that the Colona facilities
were placed in service before July 1, 1998, which is one of the qualification
requirements for tax credits under Section 29. The Colona Closing Agreement
further provides that the fuel produced by the Colona facilities in 2001 is a
"qualified fuel" for purposes of the Section 29 tax credits. This action
concludes the IRS PFA program with respect to Colona.
Although the execution of the Colona Closing Agreement is a significant event,
the audits of the Company's facilities are not yet completed and the PFA process
continues with respect to the four synthetic fuel facilities owned by other
affiliates of Progress Energy and FPC. Currently, the focus of that process is
to determine that the facilities were placed in service before July 1, 1998. In
management's opinion, Progress Energy is complying with all the necessary
requirements to be allowed such credits under Section 29, although it cannot
provide certainty, that it will prevail if challenged by the IRS on credits
taken. Accordingly, the Company has no current plans to alter its synthetic fuel
production schedule as a result of these matters.
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29. The investigation is examining the utilization
of the credits, the nature of the technologies and fuels created, the use of the
synthetic fuel, and other aspects of Section 29 and is not specific to the
Company's synthetic fuel operations. Progress Energy is providing information in
connection with this investigation. The Company cannot predict the outcome of
this matter.
In addition, the Company has retained an advisor to assist in selling an
interest in one or more synthetic fuel entities. The Company is pursuing the
sale of a portion of its synthetic fuel production capacity that is
underutilized due to limits on the amount of credits that can be generated and
utilized by the Company. The Company would expect to retain an ownership
interest and to operate any sold facility for a management fee. The final
outcome and timing of these discussions is uncertain and the Company cannot
predict the outcome of this matter.
ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters. These environmental matters are discussed in detail in Note 21E to the
Progress Energy Consolidated Financial Statements and Note 16D to the Progress
Energy Carolinas Consolidated Financial Statements. This discussion identifies
specific environmental issues, the status of the issues, accruals associated
with issue resolutions and the associated exposures to the Company.
NEW ACCOUNTING STANDARDS
See Note 2 to the Progress Energy Consolidated Financial Statements for a
discussion of the impact of new accounting standards.
66
PEC
The information required by this item is incorporated herein by reference to the
following portions of Progress Energy's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate to PEC:
RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER
MATTERS.
The following Management's Discussion and Analysis and the information
incorporated herein by reference contain forward-looking statements that involve
estimates, projections, goals, forecasts, assumptions, risks and uncertainties
that could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. Please review "Risk Factors" and
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors
that may impact any such forward-looking statements made herein.
RESULTS OF OPERATIONS
The results of operations for the PEC consolidated for the years ended December
31, 2003, 2002 and 2001, respectively, are summarized in the table below. The
results of operations for the PEC Electric segment are identical between PEC and
Progress Energy for all periods presented. The primary difference between the
results of operations of the PEC Electric segment and the consolidated PEC
results of operations for the 2001, 2002 and 2003 comparison periods relate to
the non-electric operations, as summarized below:
(in millions) 2003 2002 2001
---------- --------- ---------
PEC Electric income before cumulative effect $ 515 $ 513 $ 468
Caronet net income (loss) 5 (79) (99)
Other non-electric net loss (18) (6) (8)
Cumulative effect of accounting change (23) - -
---------- --------- ---------
Earnings for common stock $ 479 $ 428 $ 361
========== ========= =========
Caronet's results of operations for 2002 and 2001 include after-tax impairments
of $87 million and $107 million, respectively, for other-than-temporary declines
in the value of the assets of Caronet and Caronet's investment in Interpath. The
Interpath investment was sold in December 2002 for a nominal amount. In December
2003, PTC and Caronet, both wholly-owned subsidiaries of Progress Energy, and
EPIK, a wholly-owned subsidiary of Odyssey, contributed substantially all of
their assets and transferred certain liabilities to PTC LLC, a subsidiary of
PTC. Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for
$2 million in cash and Caronet become an indirect wholly-owned subsidiary of
Odyssey. Following consummation of all the transactions described above, PTC
holds a 55 percent ownership interest in, and is the parent, of PTC LLC. Odyssey
holds a combined 45 percent ownership interest in PTC LLC through EPIK and
Caronet. The accounts of PTC LLC are included in the Company's Consolidated
Financial Statements since the transaction date.
The Other non-electric segments contributed segment losses of $18 million.
Included in the 2003 segment losses is an investment impairment of $6 million
after-tax on the Affordable Housing portfolio held by the non-utility
subsidiaries of PEC.
PEC Electric recorded cumulative effects of changes in accounting principles due
to the adoption of a new accounting pronouncement. This adjustment totaled to a
$23 million loss which was due primarily to the new FASB guidance related to the
accounting for certain contracts. This guidance discusses whether the pricing in
a contract that contains broad market indices qualifies for certain exceptions
that would not require the contract to be recorded at its fair value. PEC
Electric had a purchase power contract with Broad River LLC, that did not meet
the criteria for an exception, and a negative fair value adjustment was recorded
in the fourth quarter of 2003 for $23 million. See Note 12A to the PEC
Consolidated Financial Statements
Note 1C to the PEC Consolidated Financial Statements discusses its significant
accounting policies. The most critical accounting policies and estimates that
impact PEC's financial statements are the economic impacts of utility regulation
and asset impairment policies, which are described in more detail in the
Progress Energy Management's Discussion and Analysis section.
67
LIQUIDITY AND CAPITAL RESOURCES
PEC's estimated capital requirements for 2004, 2005 and 2006 are $625 million,
$595 million and $610 million, respectively, and primarily reflect construction
expenditures to support customer growth, add regulated generation and upgrade
existing facilities. PEC expects to fund its capital requirements primarily
through internally generated funds. In addition, PEC has a $450 million credit
facility which supports the issuance of commercial paper. Access to the
commercial paper market and the utility money pool provide additional liquidity
to help meet PEC's working capital requirements.
See Note 8 to the PEC Consolidated Financial Statements for information on PEC's
available credit facilities at December 31, 2003, and the discussion above for
Progress Energy under "Financing Activities" for information regarding PEC's
financing activities.
CONTRACTUAL OBLIGATIONS
The following table reflects PEC's contractual obligations and other commercial
commitments at December 31, 2003 in the respective periods in which they are
due:
(in millions)
- -------------------------------------------------------------------------------------------------------
Less than 1 More than 5
Contractual Obligations Total year 1-3 years 3-5 years years
- -------------------------------------------------------------------------------------------------------
Long-term debt $ 3,408 $ 300 $ 300 $ 500 $ 2,308
Capital lease obligations 35 2 4 4 25
Operating leases 135 6 15 12 102
Fuel and purchased power 2,062 543 659 313 547
Other purchase obligations 18 5 - - 13
North Carolina clean air capital
commitments 783 90 230 210 253
Funding obligations 148 17 - 13 118
- -------------------------------------------------------------------------------------------------------
Total $ 6,589 $ 963 $ 1,208 $ 1,052 $ 3,366
=================================================================
Information on PEC's contractual obligations at December 31, 2002 is included in
the notes to the PEC Consolidated Financial Statements. Future debt maturities
are included in Note 8 to the PEC Consolidated Financial Statements. PEC's fuel
and purchased power obligations and lease obligations are included in Notes 16A
and 16B, respectively, to the PEC Consolidated Financial Statements. PEC's other
purchase obligations are included in Note 16A to the PEC Consolidated Financial
Statements. PEC's North Carolina clean air legislation commitments are described
in Note 16E to PEC's Consolidated Financial Statements. In 2004, PEC expects to
make required contributions of $17 million directly to pension plan assets.
Decommissioning cost provisions are included in Note 3D to the PEC Consolidated
Financial Statements. In 2008, PEC must begin transitioning amounts currently
retained internally to its external decommissioning funds. The transition of
$131 million must be complete by December 31, 2017, and at least 10% must be
transitioned each year.
68
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PROGRESS ENERGY, INC.
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Certain market risks are inherent in the Company's financial
instruments, which arise from transactions entered into in the normal course of
business. The Company's primary exposures are changes in interest rates with
respect to its long-term debt and commercial paper, and fluctuations in the
return on marketable securities with respect to its nuclear decommissioning
trust funds. The Company manages its market risk in accordance with its
established risk management policies, which may include entering into various
derivative transactions.
These financial instruments are held for purposes other than trading. The risks
discussed below do not include the price risks associated with nonfinancial
instrument transactions and positions associated with the Company's operations,
such as purchase and sales commitments and inventory.
Interest Rate Risk
The Company manages its interest rate risks through the use of a combination of
fixed and variable rate debt. Variable rate debt has rates that adjust in
periods ranging from daily to monthly. Interest rate derivative instruments may
be used to adjust interest rate exposures and to protect against adverse
movements in rates.
The following tables provide information at December 31, 2003 and 2002, about
the Company's interest rate risk-sensitive instruments. The tables present
principal cash flows and weighted-average interest rates by expected maturity
dates for the fixed and variable rate long-term debt and FPC obligated
mandatorily redeemable securities of trust. The tables also include estimates of
the fair value of the Company's interest rate risk-sensitive instruments based
on quoted market prices for these or similar issues. For interest rate swaps and
interest rate forward contracts, the tables present notional amounts and
weighted-average interest rates by contractual maturity dates. Notional amounts
are used to calculate the contractual cash flows to be exchanged under the
interest rate swaps and the settlement amounts under the interest rate forward
contracts. See "Interest Rate Derivatives" under LIQUIDITY AND CAPITAL RESOURCES
above for more information on interest rate derivatives.
December 31, 2003 Fair Value
December 31,
(dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003
- -----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 868 $ 349 $ 909 $ 674 $ 827 $ 5,836 $ 9,463 $ 10,501
Average interest rate 6.67% 7.38% 6.78% 6.41% 6.27% 6.51% 6.55%
Variable rate long-term debt - - - $ 241 - $ 861 $ 1,102 $ 1,103
Average interest rate - - - 3.04% - 1.08% 1.51%
Debt to affiliated trust - - - - - $ 309 $ 309 $ 313(d)
Interest rate - - - - - 7.10% 7.10%
Interest rate derivatives:
Pay variable/receive
fixed(a) - - $ (300) $ (350) $ (200) - $ (850) $ (4)
Payer swaptions(b) - - - - $ 400 - $ 400 $ 5
Interest rate collars(c) $ 65 - - $ 130 - - $ 195 $ (11)
- -----------------------------------------------------------------------------------------------------------------------
(a) Receives floating rate based on three-month London Inter Bank Offering Rate
(LIBOR). Designated as hedge of $850 million of fixed-rate debt.
(b) PGN has the right to enter into a 3-year, pay-fixed swap beginning January
2005 at a fixed rate of 4.75%.
(c) Interest rate collars on $195 million notional. Designated as hedge of
variable rate interest.
(d) Refer to Note 12F to the Progress Energy Consolidated Financial Statements.
69
December 31, 2002 Fair Value
December 31,
(dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002
- -----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 275 $ 869 $ 355 $ 909 $ 674 $ 5,614 $ 8,696 $ 9,584
Average interest rate 6.42% 6.66% 7.38% 6.78% 6.41% 6.90% 6.83% -
Variable rate long-term debt - - - - $ 225 $ 861 $ 1,086 $ 1,087
Average interest rate - - - - 0.03% 1.24% 1.61% -
FPC mandatorily redeemable
securities of trust - - - - - $ 300 $ 300 $ 303
Interest rate - - - - - 7.10% 7.10% -
Interest rate derivatives:
Pay variable /receive
fixed(a) - - - - $ 350 - $ 350 $ 5
Interest rate forward
contracts(b) $ 35 - - - - - $ 35 $ (1)
Interest rate collars(c) - $ 65 - - $ 130 - $ 195 $ (12)
- -----------------------------------------------------------------------------------------------------------------------
(a) Receives fixed and pays floating rate based on three-month LIBOR.
(b) Treasury Rate Lock agreement on $35 million designated as cash flow hedge
of anticipated debt issuance. (c) Interest rate collars on $195 million
notional. Designated as hedge of variable rate interest.
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents, which
are exposed to price fluctuations in equity markets and to changes in interest
rates. The fair value of these funds was $938 million and $797 million at
December 31, 2003 and 2002, respectively. The Company actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, target allocation
percentages for various asset classes. The accounting for nuclear
decommissioning recognizes that the Company's regulated electric rates provide
for recovery of these costs net of any trust fund earnings and, therefore,
fluctuations in trust fund marketable security returns do not affect the
earnings of the Company.
Contingent Value Obligations Market Value Risk
In connection with the acquisition of FPC, the Company issued 98.6 million
Contingent Value Obligations (CVOs). Each CVO represents the right to receive
contingent payments based on the performance of four synthetic fuel facilities
purchased by subsidiaries of FPC in October 1999. The payments, if any, are
based on the net after-tax cash flows the facilities generate. These CVOs are
recorded at fair value and unrealized gains and losses from changes in fair
value are recognized in earnings. At December 31, 2003 and 2002, the fair value
of these CVOs was $23 million and $14 million, respectively. A hypothetical 10%
decrease in the December 31, 2003 market price would result in a $2 million
decrease in the fair value of the CVOs.
Commodity Price Risk
The Company is exposed to the effects of market fluctuations in the price of
natural gas, electricity and other energy-related products marketed and
purchased as a result of its ownership of energy-related assets. The Company's
exposure to these fluctuations is significantly limited by the cost-based
regulation of PEC and PEF. In addition, many of the Company's long-term power
sales contracts shift substantially all fuel responsibility to the purchaser.
The Company uses natural gas hedging instruments to manage a portion of the
market risk associated with fluctuations in the future sales price of the
Company's natural gas. In addition, the Company may engage in limited economic
hedging and trading activity using natural gas and electricity financial
instruments. Refer to Note 17 to the Progress Energy Consolidated Financial
Statements for additional information with regard to the Company's commodity
contracts and use of derivative financial instruments.
70
PEC
The information required by this item is incorporated herein by reference to the
Progress Energy Quantitative and Qualitative Disclosures About Market Risk
insofar as it relates to PEC.
Interest Rate Risk
The following tables provide information at December 31, 2003 and 2002, about
PEC's interest rate risk sensitive instruments:
December 31, 2003 Fair Value
December 31,
(dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003
- -----------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 300 $ 300 - $ 200 $ 300 $ 1,688 $ 2,788 $ 3,065
Average interest rate 6.9% 7.50% - 6.80% 6.65% 6.09% 6.44%
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - - 1.09%
December 31, 2002 Fair Value
December 31,
(dollars in millions) 2003 2004 2005 2006 2007 Thereafter Total 2002
- -------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt - $ 300 $ 307 - $ 200 $ 1,638 $ 2,445 $ 2,708
Average interest rate - 6.9% 7.48% - 6.80% 6.61% 6.76% -
Variable rate long-term debt - - - - - $ 620 $ 620 $ 620
Average interest rate - - - - - 1.29% 1.29% -
Commodity Price Risk
PEC exposed to the effects of market fluctuations in the price of natural gas,
electricity and other energy-related products marketed and purchased as a result
of its ownership of energy-related assets. PEC's exposure to these fluctuations
is significantly limited by cost-based regulation. PEC may engage in limited
economic hedging and trading activity using natural gas and electricity
financial instruments. Refer to Note 12 to the Progress Energy Carolinas
Consolidated Financial Statements for additional information with regard to
PEC's commodity contracts and use of derivative financial instruments.
71
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 74
Consolidated Financial Statements - Progress Energy, Inc.:
Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001 75
Consolidated Balance Sheets at December 31, 2003 and 2002 76
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 77
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2003,
2002 and 2001 78
Consolidated Quarterly Financial Data (Unaudited) 79
Notes to Consolidated Financial Statements
Note 1 - Organization and Summary of Significant Accounting Policies 80
Note 2 - New Accounting Standards 84
Note 3 - Divestitures 85
Note 4 - Acquisitions and Business Combinations 87
Note 5 - Property, Plant and Equipment 89
Note 6 - Inventory 93
Note 7 - Regulatory Matters 94
Note 8 - Goodwill and Other Intangible Assets 97
Note 9 - Impairments of Long-Lived Assets and Investments 98
Note 10 - Equity 99
Note 11 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 102
Note 12 - Debt and Credit Facilities 103
Note 13 - Fair Value of Financial Instruments 106
Note 14 - Income Taxes 107
Note 15 - Contingent Value Obligations 109
Note 16 - Benefit Plans 109
Note 17 - Risk Management Activities and Derivatives Transactions 113
Note 18 - Related Party Transactions 115
Note 19 - Financial Information by Business Segment 115
Note 20 - Other Income and Other Expense 116
Note 21 - Commitments and Contingencies 117
72
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
Independent Auditors' Report 128
Consolidated Financial Statements - Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc.:
Consolidated Statements of Income and Comprehensive Income for the Years Ended
December 31, 2003, 2002, and 2001 129
Consolidated Balance Sheets at December 31, 2003 and 2002 130
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002
and 2001 131
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2003, 2002
and 2001 132
Consolidated Quarterly Financial Data (Unaudited) 132
Notes to Consolidated Financial Statements
Note 1 - Organization and Summary of Significant Accounting Policies 133
Note 2 - New Accounting Standards 136
Note 3 - Property, Plant and Equipment 138
Note 4 - Inventory 141
Note 5 - Regulatory Matters 141
Note 6 - Impairments of Long-Lived Assets and Investments 143
Note 7 - Equity 144
Note 8 - Debt and Credit Facilities 146
Note 9 - Fair Value of Financial Instruments 147
Note 10 - Income Taxes 147
Note 11 - Benefit Plans 149
Note 12 - Risk Management Activities and Derivatives Transactions 152
Note 13 - Related Party Transactions 153
Note 14 - Financial Information by Business Segment 153
Note 15 - Other Income and Other Expense 154
Note 16 - Commitments and Contingencies 155
Independent Auditors' Report on Consolidated Financial Statement Schedule - Progress Energy, Inc. 163
Independent Auditors' Report on Consolidated Financial Statement Schedule - Carolina Power &
Light Company d/b/a Progress Energy Carolinas, Inc. 164
Consolidated Financial Statement Schedules for the Years Ended December 31,
2003, 2002 and 2001:
II-Valuation and Qualifying Accounts - Progress Energy, Inc. 165
II-Valuation and Qualifying Accounts - Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc. 166
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Consolidated
Financial Statements or the accompanying Notes to the Consolidated Financial
Statements.
73
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress Energy,
Inc. and its subsidiaries at December 31, 2003 and 2002, and the related
consolidated statements of income, changes in common stock equity and cash flows
for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company and its subsidiaries at December
31, 2003 and 2002, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2003, in conformity
with accounting principles generally accepted in the United States of America.
As discussed in Notes 5F and 17A to the consolidated financial statements, in
2003, the Company adopted Statement of Financial Accounting Standards No. 143
and Derivatives Implementation Group Issue C20. As discussed in Note 8 to the
consolidated financial statements, in 2002, the Company changed its method of
accounting for goodwill to conform to Statement of Financial Accounting
Standards No. 142.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004
74
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
Years ended December 31
(In millions except per share data) 2003 2002 2001
- --------------------------------------------------------------------------------------------------------------
Operating Revenues
Utility $ 6,741 $ 6,601 $ 6,557
Diversified business 2,002 1,490 1,572
- --------------------------------------------------------------------------------------------------------------
Total Operating Revenues 8,743 8,091 8,129
- --------------------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 1,695 1,586 1,543
Purchased power 862 862 868
Operation and maintenance 1,419 1,390 1,228
Depreciation and amortization 883 820 1,067
Taxes other than on income 405 386 380
Diversified business
Cost of sales 1,746 1,410 1,589
Depreciation and amortization 157 118 83
Impairment of long-lived assets 17 364 43
Other 197 145 92
- --------------------------------------------------------------------------------------------------------------
Total Operating Expenses 7,381 7,081 6,893
- --------------------------------------------------------------------------------------------------------------
Operating Income 1,362 1,010 1,236
- --------------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 11 15 22
Impairment of investments (21) (25) (164)
Other, net (25) 27 (34)
- --------------------------------------------------------------------------------------------------------------
Total Other Income (Expense) (35) 17 (176)
- --------------------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 632 641 690
Allowance for borrowed funds used during construction (7) (8) (17)
- --------------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 625 633 673
- --------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax and
Cumulative Effect of Changes in Accounting Principles 702 394 387
Income Tax Benefit (109) (158) (154)
- --------------------------------------------------------------------------------------------------------------
Income from Continuing Operations before Cumulative Effect of
Changes in Accounting Principles 811 552 541
Discontinued Operations, Net of Tax (8) (24) 1
- --------------------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Changes in Accounting
Principles 803 528 542
Cumulative Effect of Changes in Accounting Principles,
Net of Tax (21) - -
- --------------------------------------------------------------------------------------------------------------
Net Income $ 782 $ 528 $ 542
- --------------------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 237 217 205
- --------------------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations before Cumulative Effect
of Changes in Accounting Principles $ 3.42 $ 2.54 $ 2.64
Discontinued Operations, Net of Tax (.03) (.11) .01
Cumulative Effect of Changes in Accounting Principles, Net of Tax (.09) - -
Net Income $ 3.30 $ 2.43 $ 2.65
- --------------------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations before Cumulative Effect
of Changes in Accounting Principles $ 3.40 $ 2.53 $ 2.63
Discontinued Operations, Net of Tax (.03) (.11) .01
Cumulative Effect of Changes in Accounting Principles, Net of Tax (.09) - -
Net Income $ 3.28 $ 2.42 $ 2.64
- --------------------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.26 $ 2.20 $ 2.14
- --------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
75
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(In millions) December 31
ASSETS 2003 2002
- ------------------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 21,675 $ 20,157
Accumulated depreciation (8,116) (7,540)
- ------------------------------------------------------------------------------------------------------------
Utility plant in service, net 13,559 12,617
Held for future use 13 15
Construction work in progress 634 752
Nuclear fuel, net of amortization 228 217
- ------------------------------------------------------------------------------------------------------------
Total Utility Plant, Net 14,434 13,601
- ------------------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 273 61
Accounts receivable 865 737
Unbilled accounts receivable 217 225
Inventory 808 875
Deferred fuel cost 317 184
Assets of discontinued operations - 490
Prepayments and other current assets 348 262
- ------------------------------------------------------------------------------------------------------------
Total Current Assets 2,828 2,834
- ------------------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 612 347
Nuclear decommissioning trust funds 938 797
Diversified business property, net 2,158 1,884
Miscellaneous other property and investments 464 519
Goodwill 3,726 3,719
Prepaid pension costs 462 60
Intangibles, net 327 155
Other assets and deferred debits 253 292
- ------------------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 8,940 7,773
- ------------------------------------------------------------------------------------------------------------
Total Assets $ 26,202 $ 24,208
- ------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- ------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500 million shares authorized,
246 and 238 million shares issued and outstanding, $ 5,270 $ 4,951
respectively
Unearned restricted shares (1 and 1 million shares, respectively) (17) (21)
Unearned ESOP shares (4 and 5 million shares, respectively) (89) (102)
Accumulated other comprehensive loss (50) (238)
Retained earnings 2,330 2,087
- ------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 7,444 6,677
- ------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries-Not Subject to Mandatory Redemption 93 93
Long-Term Debt Affiliate 309 -
Long-Term Debt 9,625 9,747
- ------------------------------------------------------------------------------------------------------------
Total Capitalization 17,471 16,517
- ------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 868 275
Accounts payable 704 659
Interest accrued 209 220
Dividends declared 140 132
Short-term obligations 4 695
Customer deposits 167 158
Liabilities of discontinued operations - 125
Other current liabilities 572 430
- ------------------------------------------------------------------------------------------------------------
Total Current Liabilities 2,664 2,694
- ------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 737 858
Accumulated deferred investment tax credits 190 206
Regulatory liabilities 2,938 120
Cost of removal - 2,940
Asset retirement obligations 1,271 -
Other liabilities and deferred credits 931 873
- ------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 6,067 4,997
- ------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 21)
- ------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 26,202 $ 24,208
- ------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
76
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
- ------------------------------------------------------------------------------------------------------------------------
Years ended December 31
(In millions) 2003 2002 2001
- ------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 782 $ 528 $ 542
Adjustments to reconcile net income to net cash provided by operating
activities:
Loss (income) from discontinued operations 8 24 (1)
Impairment of long-lived assets and investments 38 389 207
Cumulative effect of changes in accounting principles 21 - -
Depreciation and amortization 1,146 1,099 1,266
Deferred income taxes (276) (402) (367)
Investment tax credit (16) (18) (23)
Deferred fuel cost (credit) (133) (37) 69
Cash provided (used) by changes in operating assets and
liabilities:
Accounts receivable (168) (35) 183
Inventories 78 (49) (299)
Prepayments and other current assets 25 (39) (21)
Accounts payable 41 100 (213)
Other current liabilities 167 56 123
Other 75 28 (93)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,788 1,644 1,373
- ------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (1,018) (1,174) (1,177)
Diversified business property additions (607) (570) (350)
Nuclear fuel additions (117) (81) (116)
Proceeds from sales of subsidiaries and investments 579 43 53
Acquisition of businesses, net of cash - (365) -
Acquisition of intangibles (200) (10) -
Other (17) (61) (66)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (1,380) (2,218) (1,656)
- ------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 304 687 488
Issuance of long-term debt, net 1,539 1,783 4,564
Net decrease in short-term indebtedness (696) (247) (4,018)
Retirement of long-term debt (810) (1,157) (322)
Dividends paid on common stock (541) (480) (432)
Other 8 (5) (42)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities (196) 581 238
- ------------------------------------------------------------------------------------------------------------------------
Cash Used in Discontinued Operations - - (1)
- ------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 212 7 (46)
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 61 54 100
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 273 $ 61 $ 54
- ------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 612 $ 631 $ 588
income taxes (net of refunds $ 177 $ 219 $ 127
Noncash Activities
o In April 2002, Progress Fuels Corporation, a subsidiary of the Company,
acquired 100% of Westchester Gas Company. In conjunction with the purchase,
the Company issued approximately $129 million in common stock (See Note
4E).
o In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, Inc., both indirectly wholly-owned subsidiaries of Progress
Energy, and EPIK Communications, Inc., a wholly-owned subsidiary of Odyssey
Telecorp, Inc., contributed substantially all of their assets and
transferred certain liabilities to Progress Telecom, LLC, a subsidiary of
PTC (See Note 4A).
See Notes to Consolidated Financial Statements.
77
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
Unearned Accumulated Total
Common Stock Unearned ESOP Other Common
(In millions except per share data) Outstanding Restricted Common Comprehensive Retained Stock
Shares Amount Stock Stock Income (Loss) Earnings Equity
- ---------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2001 206 $ 3,621 $ (13) $ (127) - $ 1,943 $ 5,424
Net income 542 542
FAS 133 transition adjustment (net of
tax of $15) (24) (24)
Change in net unrealized losses on cash
flow hedges (net of tax of $13) (21) (21)
Reclassification adjustment for amounts
included in net income (net of tax
of $9) 14 14
Foreign currency translation and other (1) (1)
-----------
Comprehensive income 510
-----------
Issuance of shares 13 489 489
Purchase of restricted stock (8) (8)
Restricted stock expense recognition 6 6
Cancellation of restricted shares (1) 1 -
Allocation of ESOP shares 12 13 25
Dividends ($2.14 per share) (442) (442)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001 219 4,121 (14) (114) (32) 2,043 6,004
Net income 528 528
Change in net unrealized losses on cash
flow hedges (net of tax of $18) (28) (28)
Reclassification adjustment for amounts
included in net income (net of tax
of $10) 16 16
Foreign currency translation and other (2) (2)
Minimum pension liability adjustment
(net of tax of $121) (192) (192)
-----------
Comprehensive income 322
-----------
Issuance of shares 19 815 815
Purchase of restricted stock (16) (16)
Restricted stock expense recognition 8 8
Cancellation of restricted shares (1) 1 -
Allocation of ESOP shares 16 12 28
Dividends ($2.20 per share) (484) (484)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 238 4,951 (21) (102) (238) 2,087 6,677
Net income 782 782
Change in net unrealized losses on cash
flow hedges (net of tax of $7) (12) (12)
Reclassification adjustment for amounts
included in net income (net of tax
of ($11)) 19 19
Foreign currency translation and other 4 4
Minimum pension liability adjustment
(net of tax of ($112)) 177 177
-----------
Comprehensive income 970
-----------
Issuance of shares 8 309 309
Purchase of restricted stock (1) (7) (8)
Restricted stock expense recognition 10 10
Cancellation of restricted shares (1) 1 -
Allocation of ESOP shares 12 13 25
Dividends ($2.26 per share) (539) (539)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003 246 $ 5,270 $ (17) $ (89) $ (50) $ 2,330 $ 7,444
===========================================================================================================================
See Notes to Consolidated Financial Statements.
78
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In millions except per share data) First Second Third Fourth
Quarter Quarter Quarter Quarter
- ------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 2,187 $ 2,050 $ 2,458 $ 2,048
Operating income 357 274 478 253
Income from continuing operations 208 154 337 112
Income before cumulative effect of
changes in accounting principles 218 157 318 110
Net income 219 157 318 88
Common stock data:
Basic earnings per common share
Income from continuing operations 0.89 0.65 1.41 0.47
Income before cumulative effect of
changes in accounting principles 0.94 0.67 1.33 0.46
Net income 0.94 0.67 1.33 0.37
Diluted earnings per common share
Income from continuing operations 0.89 0.65 1.40 0.47
Income before cumulative effect of
changes in accounting principles 0.93 0.66 1.33 0.46
Net income 0.94 0.66 1.33 0.37
Dividends paid per common share 0.560 0.560 0.560 0.560
Market price per share - High 46.10 48.00 45.15 46.00
Low 37.45 38.99 39.60 41.60
- ------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $ 1,813 $ 1,994 $ 2,316 $ 1,968
Operating income 244 306 201 259
Income from continuing operations 124 122 157 149
Net income 133 121 152 122
Common stock data:
Basic earnings per common share
Income from continuing operations 0.58 0.57 0.72 0.66
Net income 0.62 0.56 0.71 0.55
Diluted earnings per common share
Income from continuing operations 0.58 0.56 0.71 0.66
Net income 0.62 0.56 0.70 0.55
Dividends paid per common share 0.545 0.545 0.545 0.545
Market price per share - High 50.86 52.70 51.97 44.82
Low 43.01 47.91 36.54 32.84
o In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
All amounts were restated for discontinued operations (See Note 3A) and
2003 amounts were restated for the cessation of reporting results for
portions of the Fuels' segment operations one month in arrears (See Note
1B).
o Fourth quarter 2003 includes impairments related to Kentucky May and
Affordable Housing investment of $38 million ($24 million after-tax) (See
Note 9).
o Fourth quarter 2003 includes a cumulative effect for DIG Issue 20 of $38
million ($23 million after-tax) (See Note 17).
o Third quarter 2002 includes impairment and other charges related to PTC,
Caronet and Interpath Communications, Inc. of $355 million ($225 million
after-tax) (See Note 9).
o Fourth quarter 2002 includes estimated impairment of assets held for sale
of Railcar Ltd. of $59 million ($40 million after-tax) (See Note 3B).
See Notes to Consolidated Financial Statements.
79
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a holding company
headquartered in Raleigh, North Carolina. The Company is registered under
the Public Utility Holding Company Act of 1935 (PUHCA), as amended and as
such, the Company and its subsidiaries are subject to the regulatory
provisions of PUHCA. Effective January 1, 2003, three of the Company's
subsidiaries, Carolina Power & Light Company (CP&L), Florida Power
Corporation and Progress Ventures, Inc., began doing business under the
assumed names Progress Energy Carolinas, Inc. (PEC), Progress Energy
Florida, Inc. (PEF) and Progress Energy Ventures, Inc. (PVI), respectively.
The legal names of these entities have not changed. The current corporate
and business unit structure remains unchanged.
Through its wholly-owned subsidiaries, PEC and PEF, the Company's PEC
Electric and PEF segments are primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina, South Carolina and Florida. The Progress Ventures business unit
consists of the Fuels business segment (Fuels) and Competitive Commercial
Operations (CCO) operating segments. The Fuels segment is involved in
natural gas drilling and production, coal terminal services, coal mining,
synthetic fuel production, fuel transportation and delivery. The CCO
segment includes nonregulated generation and energy marketing activities.
Through the Rail Services (Rail) segment, the Company is involved in
nonregulated railcar repair, rail parts reconditioning and sales, railcar
leasing and sales, and scrap metal recycling. Through its other business
units, the Company engages in other nonregulated business areas, including
telecommunications and energy management and related services. Progress
Energy's legal structure is not currently aligned with the functional
management and financial reporting of the Progress Ventures business unit.
Whether, and when, the legal and functional structures will converge
depends upon legislative and regulatory action, which cannot currently be
anticipated.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of the Company and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable
and the future recovery of the sales price through the ratemaking process
is probable.
Unconsolidated investments in companies over which the Company does not
have control, but has the ability to exercise influence over operating and
financial policies (generally 20% - 50% ownership), are accounted for under
the equity method of accounting. Certain investments in debt and equity
securities that have readily determinable market values, and for which the
Company does not have control, are accounted for at fair value in
accordance with SFAS No. 115, "Accounting for Certain Investments in Debt
and Equity Securities." Other investments are stated principally at cost.
These equity and cost investments, which total approximately $57 million
and $109 million at December 31, 2003 and 2002, respectively, are included
in miscellaneous other property and investments in the Consolidated Balance
Sheets. The primary component of this balance is the Company's investments
in affordable housing of $29 million and $72 million at December 31, 2003
and 2002, respectively. This decrease is primarily due to the sale of
certain PEC investments in the third quarter of 2003. For a discussion of
how new FASB interpretations will affect these affordable housing
investments see Note 2.
The results of operations of Rail are reported one month in arrears. During
2003, the Company ceased recording portions of the Fuels' segment
operations one month in arrears. The net impact of this action increased
net income by $2 million for the year.
Certain amounts for 2002 and 2001 have been reclassified to conform to the
2003 presentation.
80
C. Significant Accounting Policies
Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
amounts of revenues and expenses reflected during the reporting period.
Actual results could differ from those estimates.
Revenue Recognition
The Company recognizes electric utility revenues as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Diversified business revenues are generally recognized
at the time products are shipped or as services are rendered. Leasing
activities are accounted for in accordance with SFAS No. 13, "Accounting
for Leases." Gains and losses from energy trading activities and other
derivatives are reported on a net basis. Revenues related to design and
construction of wireless infrastructure are recognized upon completion of
services for each completed phase of design and construction. Revenues from
the sale of oil and gas production are recognized when title passes, net of
royalties.
Fuel Cost Deferrals
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by the electric utilities' regulators. These
clauses allow the utilities to recover fuel costs and portions of purchased
power costs through surcharges on customer rates.
Excise Taxes
PEC and PEF collect from customers certain excise taxes levied by the state
or local government upon the customers. PEC and PEF account for excise
taxes on a gross basis. For the years ended December 31, 2003, 2002 and
2001, gross receipts tax, franchise taxes and other excise taxes of
approximately $217 million, $211 million and $210 million, respectively,
are included in taxes other than on income in the accompanying Consolidated
Statements of Income. These approximate amounts are also included in
utility revenues.
Stock-Based Compensation
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. The exercise price at which options
are granted by the Company equals the market price at the grant date, and
accordingly, no compensation expense has been recognized for stock option
grants. For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair
value of the Company's stock options is amortized to expense over the
options' vesting period. The following table illustrates the effect on net
income and earnings per share if the fair value method had been applied to
all outstanding and unvested awards in each period:
(in millions except per share data) 2003 2002 2001
--------- --------- ---------
Net income, as reported $ 782 $ 528 $ 542
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 11 8 2
--------- -------- ---------
Pro forma net income $ 771 $ 520 $ 540
========= ========= =========
Earnings per share
Basic - as reported $ 3.30 $ 2.43 $ 2.65
Basic - pro forma $ 3.25 $ 2.40 $ 2.64
Diluted - as reported $ 3.28 $ 2.42 $ 2.64
Diluted - pro forma $ 3.24 $ 2.39 $ 2.63
81
Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. The Company capitalizes all construction-related direct labor
and material costs of units of property as well as indirect construction
costs. The cost of renewals and betterments is also capitalized.
Maintenance and repairs of property, and replacements and renewals of items
determined to be less than units of property, are charged to maintenance
expense as incurred. The cost of units of property replaced or retired,
less salvage, is charged to accumulated depreciation. Removal and
decommissioning costs were charged to regulatory liabilities in 2003 and
cost of removal in 2002. The Company follows the guidance in SFAS No. 143,
"Accounting for Asset Retirement Obligations," to account for legal
obligations associated with the retirement of certain tangible long-lived
assets.
Depreciation and Amortization - Utility Plant
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated salvage (See Note 5A). The North Carolina Utilities Commission
(NCUC), the Public Service Commission of South Carolina (SCPSC) and the
Florida Public Service Commission (FPSC) can also grant approval to
accelerate or reduce depreciation and amortization of utility assets (See
Note 7).
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE) and costs
associated with obligations to the DOE for the decommissioning and
decontamination of enrichment facilities, is computed primarily on the
units-of-production method and charged to fuel used in electric generation
in the accompanying Consolidated Statements of Income. In the Company's
retail jurisdictions, provisions for nuclear decommissioning costs are
approved by the NCUC, the SCPSC and the FPSC and are based on site-specific
estimates that include the costs for removal of all radioactive and other
structures at the site. In the wholesale jurisdictions, the provisions for
nuclear decommissioning costs are approved by the Federal Energy Regulatory
Commission (FERC).
Cash and Cash Equivalents
The Company considers cash and cash equivalents to include unrestricted
cash on hand, cash in banks and temporary investments purchased with a
maturity of three months or less.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts receivable, which
totaled approximately $28 million and $40 million at December 31, 2003 and
2002, respectively, and is included in accounts receivable on the
Consolidated Balance Sheets.
Inventory
The Company accounts for inventory using the average-cost method.
Regulatory Assets and Liabilities
The Company's regulated operations are subject to SFAS No. 71, which allows
a regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, the Company records assets and liabilities that result from
the regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the accompanying
Consolidated Balance Sheets as regulatory assets and regulatory liabilities
(See Note 7A).
Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If an impairment is recognized on an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis using the
estimated useful lives disclosed in Note 5B. Depletion of mineral rights is
provided on the units-of-production method based upon the estimates of
recoverable amounts of clean mineral.
The Company uses the full cost method to account for its natural gas and
oil properties. Under the full cost method, substantially all productive
and nonproductive costs incurred in connection with the acquisition,
exploration and development of natural gas and oil reserves are
capitalized. These capitalized costs include the costs of all unproved
properties, internal costs directly related to acquisition and exploration
activities. The amortization base also includes the estimated future cost
82
to develop proved reserves. Except for costs of unproved properties and
major development projects in progress, all costs are amortized using the
units-of-production method over the life of the Company's proved reserves.
Goodwill and Intangible Assets
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets" (SFAS No. 142), and no longer amortizes goodwill.
Instead, goodwill is subject to at least an annual assessment for
impairment by applying a two-step fair-value-based test. This assessment
could result in periodic impairment charges. Prior to the adoption of SFAS
No. 142, the Company amortized goodwill on a straight-line basis over a
period not exceeding 40 years. Intangible assets are being amortized based
on the economic benefit of their respective lives.
Unamortized Debt Premiums, Discounts and Expenses
Long-term debt premiums, discounts and issuance expenses for the utilities
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utilities are amortized over the applicable life
using the straight-line method consistent with ratemaking treatment.
Income Taxes
The Company and its affiliates file a consolidated federal income tax
return. Deferred income taxes have been provided for temporary differences.
These occur when there are differences between the book and tax carrying
amounts of assets and liabilities. Investment tax credits related to
regulated operations have been deferred and are being amortized over the
estimated service life of the related properties. Credits for the
production and sale of synthetic fuel are deferred to the extent they
cannot be or have not been utilized in the annual consolidated federal
income tax returns.
Derivatives
Effective January 1, 2001, the Company adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS No. 133), as
amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133, as amended,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and
for hedging activities. SFAS No. 133 requires that an entity recognize all
derivatives as assets or liabilities in the balance sheet and measure those
instruments at fair value. During 2003, the FASB reconsidered an
interpretation of SFAS No. 133. See Note 17 for the effect of the
interpretation and additional information regarding risk management
activities and derivative transactions.
Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies" (SFAS No. 5), have been met.
Environmental expenditures are expensed as incurred or capitalized
depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations and that have no future
economic benefits are expensed. Accruals for estimated losses from
environmental remediation obligations generally are recognized no later
than completion of the remedial feasibility study. Such accruals are
adjusted as additional information develops or circumstances change. Costs
of future expenditures for environmental remediation obligations are not
discounted to their present value. Recoveries of environmental remediation
costs from other parties are recognized when their receipt is deemed
probable (See Note 21E).
Impairment of Long-Lived Assets and Investments
The Company reviews the recoverability of long-lived tangible and
intangible assets whenever indicators exist. Examples of these indicators
include current period losses, combined with a history of losses or a
projection of continuing losses, or a significant decrease in the market
price of a long-lived asset group. If an indicator exists for assets to be
held and used, then the asset group is tested for recoverability by
comparing the carrying value to the sum of undiscounted expected future
cash flows directly attributable to the asset group. If the asset group is
not recoverable through undiscounted cash flows or the asset group is to be
disposed of, then an impairment loss is recognized for the difference
between the carrying value and the fair value of the asset group. The
accounting for impairment of assets is based on SFAS No. 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets," which was adopted by
the Company effective January 1, 2002. Prior to the adoption of this
standard, impairments were accounted for under SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of" (SFAS No. 121), which was superseded by SFAS No. 144.
83
The Company reviews its investments to evaluate whether or not a decline in
fair value below the carrying value is an other-than-temporary decline. The
Company considers various factors, such as the investee's cash position,
earnings and revenue outlook, liquidity and management's ability to raise
capital in determining whether the decline is other-than-temporary. If the
Company determines that an other-than-temporary decline exists in the value
of its investments, it is the Company's policy to write-down these
investments to fair value. See Note 9 for a discussion of impairment
evaluations performed and charges taken.
Under the full cost method of accounting for natural gas and oil
properties, total capitalized costs are limited to a ceiling based on the
present value of discounted (at 10%) future net revenues using current
prices, plus the lower of cost or fair market value of unproved properties.
If the ceiling (discounted revenues) is not equal to or greater than total
capitalized costs, the Company is required to write-down capitalized costs
to this level. The Company performs this ceiling test calculation every
quarter. No write-downs were required in 2003, 2002 or 2001.
Subsidiary Stock Transactions
Gains and losses realized as a result of common stock sales by the
Company's subsidiaries are recorded in the Consolidated Statements of
Income, except for any transactions that must be credited directly to
equity in accordance with the provisions of SAB No. 51, "Accounting for
Sales of Stock by a Subsidiary."
2. New Accounting Standards
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS
No. 150, "Accounting for Certain Financial Instruments with Characteristics
of Both Liabilities and Equity" (SFAS No. 150). The adoption of SFAS No.
150 did not have an impact on the Company's financial position or results
of operations as of and for the periods ended December 31, 2003.
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans"
In May 2003, the Emerging Issues Task Force (EITF) reached consensus in
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" (EITF
03-04), to specifically address the accounting for certain cash balance
pension plans. The consensus reached in EITF 03-04 requires certain cash
balance pension plans to be accounted for as defined benefit plans. For
cash balance plans described in EITF 03-04, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. The Company has historically accounted for
its cash balance plan as a defined benefit plan; however, the Company was
required to adopt the measurement provisions of EITF 03-04 at its cash
balance plan's measurement date of December 31, 2003. Any differences in
the measurement of the obligations as a result of applying EITF 03-04 were
reported as a component of actuarial gain or loss. The ongoing effects of
this standard are dependent on other factors that also affect the
determination of actuarial gains and losses and the subsequent amortization
of such gains and losses. However, the adoption of EITF 03-04 is not
expected to have a material effect on the Company's results of operations
or financial position.
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. Interpretations and
implementation issues with regard to SFAS No. 149 continue to evolve. The
statement had no significant impact on the Company's accounting for
contracts entered into subsequent to the statement's effective date (See
Note 17). Future effects, if any, on the Company's results of operations
and financial condition will be dependent on the specifics of future
contracts entered into with regard to guidance provided by the statement.
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities and determining whether such entities should be
consolidated. FIN No. 46 requires an enterprise to consolidate a variable
interest entity when the enterprise (a) absorbs a majority of the variable
interest entity's expected losses, (b) receives a majority of the entity's
expected residual returns, or both, as a result of ownership, contractual
or other financial interests in the entity. Prior to the effective date of
84
FIN No. 46, entities were generally consolidated by an enterprise that had
control through ownership of a majority voting interest in the entity. FIN
No. 46 originally applied immediately to variable interest entities created
or obtained after January 31, 2003. During 2003, the Company did not
participate in the creation of, or obtain a new variable interest in, any
variable interest entity. In December 2003, the FASB issued a revision to
FIN No. 46 (FIN No. 46R), which modified certain requirements of FIN No. 46
and allowed for the optional deferral of the effective date of FIN No. 46R
until March 31, 2004. However, entities subject to FIN No. 46R that are
deemed to be special-purpose entities (as defined in FIN No. 46R) must
implement either FIN No. 46 or FIN No. 46R at December 31, 2003. The
Company elected to apply FIN No. 46 to special-purpose entities as of
December 31, 2003. Because the Company expects additional transitional
guidance to be issued, it has elected to apply FIN No. 46R to
non-special-purpose entities as of March 31, 2004.
Prior to the adoption of FIN No. 46, the Company consolidated the FPC
Capital I trust (the Trust), which holds FPC-obligated mandatorily
redeemable preferred securities. The Trust is a special-purpose entity as
defined in FIN No. 46R, and therefore the Company applied FIN No. 46 to the
Trust at December 31, 2003. The Trust is a variable interest entity, but
the Company does not absorb a majority of the Trust's expected losses and
therefore is not its primary beneficiary. Therefore, the Company
deconsolidated the Trust at December 31, 2003. This deconsolidation
resulted in recording an additional equity investment in the Trust of
approximately $9 million, an increase in outstanding debt of approximately
$8 million and a gain of approximately $1 million relating to the
cumulative effect of a change in accounting principle. See Note 12F for a
discussion of the Company's guarantees with the Trust.
The Company also has investments in 14 limited partnerships accounted for
under the equity method for which it may be the primary beneficiary. These
partnerships invest in and operate low-income housing and historical
renovation properties that qualify for federal and state tax credits. The
Company has not concluded whether it is the primary beneficiary of these
partnerships. These partnerships are partially funded with financing from
third-party lenders, which is secured by the assets of the partnerships.
The creditors of the partnerships do not have recourse to the Company. At
December 31, 2003, the maximum exposure to loss as a result of the
Company's investments in these limited partnerships was approximately $9
million. The Company expects to complete its evaluation of these
partnerships under FIN No. 46R during the first quarter of 2004. If the
Company had consolidated these 14 entities at December 31, 2003, it would
have recorded an increase to both total assets and total liabilities of
approximately $40 million.
The Company also has interests in several other variable interest entities
created before January 31, 2003, for which the Company is not the primary
beneficiary. These arrangements include equity investments in approximately
20 limited partnerships, limited liability corporations and venture capital
funds and two building leases with special-purpose entities. The aggregate
maximum loss exposure at December 31, 2003 under these arrangements totals
approximately $34 million. The creditors of these variable interest
entities do not have recourse to the general credit of the Company in
excess of the aggregate maximum loss exposure.
In February 2004, the Company became aware that certain long-term purchase
power and tolling contracts may be considered variable interests under FIN
No. 46R. The Company has various long-term purchase power and tolling
contracts with other utilities and certain qualifying facility plants. The
Company believes the counterparties to these contracts are not
special-purpose entities and, therefore, FIN No. 46R would not apply to
these contracts until March 31, 2004. The Company has not yet completed its
evaluation of these contracts to determine if the Company needs to
consolidate these counterparties under FIN No. 46R and will continue to
monitor developing practice in this area.
3. Divestitures
A. NCNG Divestiture
On September 30, 2003, the Company completed the sale of North Carolina
Natural Gas Corporation (NCNG) and the Company's equity investment in
Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas
Company, Inc. Net proceeds from the sale of NCNG of $443 million were used
to reduce debt. Based on the net proceeds, the Company recorded an
after-tax loss of $12 million during 2003.
The accompanying consolidated financial statements have been restated for
all periods presented for the discontinued operations of NCNG. The net
income of these operations is reported as discontinued operations in the
Consolidated Statements of Income. Interest expense of $10 million, $16
million and $15 million for the years ended December 31, 2003, 2002 and
2001, respectively, has been allocated to discontinued operations based on
the net assets of NCNG, assuming a uniform debt-to-equity ratio across the
Company's operations. The Company ceased recording depreciation effective
85
October 1, 2002, upon classification of the assets as discontinued
operations. After-tax depreciation expense recorded by NCNG for each of the
years ended December 31, 2002 and 2001 was $9 million and $10 million,
respectively. Results of discontinued operations for years ended December
31 were as follows:
(in millions) 2003 2002 2001
-----------------------------------
Revenues $ 284 $ 300 $ 321
===================================
Earnings before income taxes $ 6 $ 9 $ 4
Income tax expense 2 4 3
-----------------------------------
Net earnings from discontinued operations 4 5 1
Loss on disposal of discontinued operations,
including applicable income tax expense of $1
and $3, respectively ( 12) (29) -
-----------------------------------
Earnings (loss) from discontinued operations $ (8) $ (24) $ 1
===================================
The major balance sheet classes included in assets and liabilities of
discontinued operations in the Consolidated Balance Sheets at December 31,
2002 are as follows:
(in millions)
Utility plant, net $ 399
Current assets 73
Deferred debits and other assets 18
----------
Assets of discontinued operations $ 490
==========
Current liabilities $ 76
Deferred credits and other liabilities 49
----------
Liabilities of discontinued operations $ 125
==========
The sale of ENCNG resulted in net proceeds of $7 million and a pre-tax loss
of $2 million, which is included in other, net on the accompanying
Consolidated Statements of Income for the year ended December 31, 2003. The
Company's equity investment in ENCNG of $8 million at December 31, 2002 is
included in miscellaneous other property and investments in the
accompanying Consolidated Balance Sheets.
B. Railcar Ltd. Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the
Rail Services segment. In accordance with SFAS No. 144, an estimated
pre-tax impairment of $59 million on assets held for sale was recognized in
December 2002 to write-down the assets to fair value less costs to sell.
This impairment has been included in impairment of long-lived assets in the
Consolidated Statements of Income (See Note 9A).
The assets of Railcar Ltd. have been grouped as assets held for sale and
are included in other current assets on the Consolidated Balance Sheets at
December 31, 2003 and 2002. The assets were recorded at approximately $75
million and $24 million at December 31, 2003 and 2002, respectively, which
reflects the Company's estimates of the fair value expected to be realized
from the sale of these assets less costs to sell. The primary component of
assets held for sale at December 31, 2003 was property and equipment of $74
million. The primary component of assets held for sale at December 31, 2002
was current assets of $22 million. The net increase in assets held for sale
from December 31, 2002 to December 31, 2003 was primarily attributable to
the purchase of railcars in 2003 that were subject to off-balance sheet
obligations at December 31, 2002. In addition to the assets held for sale,
the Company is subject to certain commitments under operating leases (See
Note 21C).
In March 2003, the Company signed a letter of intent to sell the majority
of Railcar Ltd. assets to The Andersons, Inc. In November 2003, the asset
purchase agreement was signed, and the transaction closed in February 2004.
Proceeds from the sale were approximately $82 million. The Company was
relieved of the majority of the operating lease commitments when the assets
were sold.
86
C. Mesa Hydrocarbons, Inc. Divestiture
In October 2003, the Company sold certain gas-producing properties owned by
Mesa Hydrocarbons, LLC, a wholly-owned subsidiary of Progress Fuels
Corporation (Progress Fuels), which is included in the Fuels segment. Net
proceeds were approximately $97 million. Because the Company utilizes the
full cost method of accounting for its oil and gas operations, the pre-tax
gain of approximately $18 million was applied to reduce the basis of the
Company's other U.S. oil and gas investments and will prospectively result
in a reduction of the amortization rate applied to those investments as
production occurs.
D. Inland Marine Transportation Divestiture
During 2001, the Company completed the sale of its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc., and related
investments to AEP Resources, Inc., a wholly-owned subsidiary of American
Electric Power, for a sales price of $270 million. Of the $270 million
purchase price, $230 million was used to pay early termination of certain
off-balance sheet arrangements for assets leased by the business. In
connection with the sale, the Company entered into environmental
indemnification provisions covering both known and unknown sites (See Note
21E). The Company adjusted the FPC purchase price allocation to reflect a
$15 million net realizable value of the Inland Marine Transportation
business.
E. Required Divestiture
The U.S. Securities and Exchange Commission (SEC) original order approving
the FPC merger required the Company to divest of Rail Services and certain
immaterial, nonregulated investments of FPC by November 30, 2003. Although
the Company has been actively marketing these investments, an acceptable
divestiture opportunity was not found by that date. Therefore, the Company
sought and in October 2003 was granted approval of a three-year extension
from the SEC until 2006.
4. Acquisitions and Business Combinations
A. Progress Telecommunications Corporation
In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, Inc. (Caronet), both wholly-owned subsidiaries of Progress Energy,
and EPIK Communications, Inc. (EPIK), a wholly-owned subsidiary of Odyssey
Telecorp, Inc. (Odyssey), contributed substantially all of their assets and
transferred certain liabilities to Progress Telecom, LLC (PTC LLC), a
subsidiary of PTC. Subsequently, the stock of Caronet was sold to an
affiliate of Odyssey for $2 million in cash and Caronet became a
wholly-owned subsidiary of Odyssey. Following consummation of all the
transactions described above, PTC holds a 55% ownership interest in, and is
the parent of PTC LLC. Odyssey holds a combined 45% ownership interest in
PTC LLC through EPIK and Caronet. The accounts of PTC LLC are included in
the Company's Consolidated Financial Statements since the transaction date.
The minority interest is included in other liabilities and deferred credits
in the Consolidated Balance Sheets.
The transaction was accounted for as a partial acquisition of EPIK through
the issuance of the stock of a consolidated subsidiary. The contributions
of PTC's and Caronet's net assets were recorded at their carrying values of
approximately $31 million. EPIK's contribution was recorded at its
estimated fair value of $22 million using the purchase method, and was
initially allocated as follows: property and equipment - $27 million; other
current assets - $9 million; current liabilities - $21 million; and
goodwill - $7 million. The goodwill was assigned to the Company's Other
business segment and will not be deductible for tax purposes. The purchase
price allocation is a preliminary estimate, based on available information,
internal estimates and certain assumptions management believes are
reasonable. Accordingly, the purchase price allocation is subject to
finalization in 2004 pending the completion of internal and external
appraisals of assets acquired. No gain or loss was recognized on the
transaction. The pro forma results of operations reflecting the acquisition
would not be materially different than the reported results of operations
for the years ended December 31, 2002 or 2001.
87
B. Acquisition of Natural Gas Reserves
During 2003, Progress Fuels entered into several independent transactions
to acquire approximately 200 natural gas-producing wells with proven
reserves of approximately 190 billion cubic feet (Bcf) from Republic
Energy, Inc. and three other privately-owned companies, all headquartered
in Texas. The total cash purchase price for the transactions was $168
million.
C. Wholesale Energy Contract Acquisition
In May 2003, PVI entered into a definitive agreement with Williams Energy
Marketing and Trading, a subsidiary of The Williams Companies, Inc., to
acquire a long-term full-requirements power supply agreement at fixed
prices with Jackson Electric Membership Corporation (Jackson), located in
Jefferson, Georgia. The agreement calls for a $188 million cash payment to
Williams Energy Marketing and Trading in exchange for assignment of the
Jackson supply agreement. The $188 million cash payment was recorded as an
intangible asset and is being amortized based on the economic benefit of
the contract (See Note 8). The power supply agreement terminates in 2015,
with a first refusal right to extend for five years. The agreement includes
the use of 640 megawatts (MW) of contracted Georgia System generation
comprised of nuclear, coal, gas and pumped-storage hydro resources. PVI
expects to supplement the acquired resources with its own intermediate and
peaking assets in Georgia to serve Jackson's forecasted 1,100 MW peak
demand in 2005 growing to a forecasted 1,700 MW demand by 2015.
D. Generation Acquisition
In February 2002, PVI acquired 100% of two electric generating projects
located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc.
The two projects consist of 1) Walton County Power, LLC in Monroe, Georgia,
a 460 MW natural gas-fired plant placed in service in June 2001 and 2)
Washington County Power, LLC in Washington County, Georgia, a 600 MW
natural gas-fired plant placed in service in June 2003. The Walton and
Washington projects have been accounted for using the purchase method of
accounting and, accordingly, have been included in the consolidated
financial statements since the acquisition date.
In the final allocation, the aggregate cash purchase price of approximately
$348 million was allocated to diversified business property, intangibles
and goodwill for $250 million, $33 million and $64 million, respectively
(See Note 8). Of the acquired intangible assets, $33 million was assigned
to tolling and power sale agreements with LG&E Energy Marketing, Inc. for
each project and is being amortized through December 31, 2004. Goodwill was
assigned to the CCO segment and will be deductible for tax purposes.
The pro forma results of operations reflecting the acquisition would not be
materially different than the reported results of operations for the years
ended December 31, 2002 or 2001.
E. Westchester Acquisition
In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired
100% of Westchester Gas Company (Westchester). The acquisition included
approximately 215 natural gas-producing wells, 52 miles of intrastate gas
pipeline and 170 miles of gas-gathering systems located within a 25-mile
radius of Jonesville, Texas, on the Texas-Louisiana border.
The aggregate purchase price of approximately $153 million consisted of
cash consideration of approximately $22 million and the issuance of 2.5
million shares of Progress Energy common stock then valued at approximately
$129 million. The purchase price included approximately $2 million of
direct transaction costs. The final purchase price was allocated to oil and
gas properties, intangible assets, diversified business property, net
working capital and deferred tax liabilities for approximately $152
million, $9 million, $32 million, $5 million and $45 million, respectively.
The $9 million intangible assets recorded relates to customer contracts
acquired as part of the acquisition and are being amortized over their
respective lives (See Note 8).
The acquisition has been accounted for using the purchase method of
accounting and, accordingly, the results of operations for Westchester have
been included in Progress Energy's consolidated financial statements since
the date of acquisition. The pro forma results of operations reflecting the
acquisition would not be materially different than the reported results of
operations for the years ended December 31, 2002 or 2001.
88
5. Property, Plant and Equipment
A. Utility Plant
The balances of electric utility plant in service at December 31 are listed
below, with a range of depreciable lives for each:
(in millions) 2003 2002
------------- -----------
Production plant (7-33 years) $ 12,039 $ 11,063
Transmission plant (30-75 years) 2,167 2,104
Distribution plant (12-50 years) 6,432 6,073
General plant and other (8-75 years) 1,037 917
------------- -----------
Utility plant in service $ 21,675 $ 20,157
============= ===========
Generally, electric utility plant at PEC and PEF, other than nuclear fuel,
is pledged as collateral for the first mortgage bonds of PEC and PEF,
respectively.
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The
composite AFUDC rate for PEC's electric utility plant was 4.0% in 2003 and
6.2% in 2002 and 2001. The composite AFUDC rate for PEF's electric utility
plant was 7.8% in 2003, 2002 and 2001.
Depreciation provisions on utility plant, as a percent of average
depreciable property other than nuclear fuel, were 2.5%, 2.6% and 2.8% in
2003, 2002 and 2001, respectively. The depreciation provisions related to
utility plant were $517 million, $488 million and $530 million in 2003,
2002 and 2001, respectively. In addition to utility plant depreciation
provisions, depreciation and amortization expense also includes
decommissioning cost provisions, asset retirement obligation (ARO)
accretion, cost of removal provisions (See Note 5D) and regulatory approved
expenses (See Note 7).
PEC filed a new depreciation study in 2004 that provides support for
reducing depreciation expense on an annual basis by approximately $45
million. The reduction is primarily attributable to assumption changes for
nuclear generation, offset by increases for distribution assets. The new
rates are primarily effective January 1, 2004.
Amortization of nuclear fuel costs, for the years ended December 31, 2003,
2002 and 2001 were $143 million, $141 million and $130 million,
respectively.
B. Diversified Business Property
The balances of diversified business property at December 31 are listed
below, with a range of depreciable lives for each:
89
(in millions) 2003 2002
--------------- ----------------
Equipment (3 - 25 years) $ 246 $ 299
Nonregulated generation plant and equipment (3 - 40 years) 1,299 549
Land and mineral rights 93 90
Buildings and plants (5 - 40 years) 153 153
Oil and gas properties (units-of-production) 412 265
Telecommunications equipment (5 - 20 years) 63 43
Rail equipment (3 - 20 years) 125 48
Marine equipment (3 - 35 years) 83 80
Computers, office equipment and software (3 - 10 years) 36 33
Construction work in progress 49 644
Accumulated depreciation (401) (320)
--------------- ----------------
Diversified business property, net $ 2,158 $ 1,884
=============== ================
The Company's nonregulated businesses capitalize interest costs under SFAS
No. 34, "Capitalizing Interest Costs." During the years ended December 31,
2003 and 2002, respectively, the Company capitalized $20 million and $38
million of its interest expense of $652 million and $679 million related to
the expansion of its nonregulated generation portfolio at PVI. Capitalized
interest is included in diversified business property, net on the
Consolidated Balance Sheets. Diversified business depreciation expense was
$120 million, $85 million and $61 million for December 31, 2003, 2002 and
2001, respectively.
C. Joint Ownership of Generating Facilities
PEC and PEF hold ownership interests in certain jointly owned generating
facilities. Each is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. Each
also pays its ownership share of additional construction costs, fuel
inventory purchases and operating expenses. PEC's and PEF's share of
expenses for the jointly owned facilities is included in the appropriate
expense category. The co-owner of Intercession City Unit P11 (P11) has
exclusive rights to the output of the unit during the months of June
through September. PEF has that right for the remainder of the year. PEC's
and PEF's ownership interests in the jointly owned generating facilities
are listed below with related information at December 31, ($ in millions):
- -----------------------------------------------------------------------------------------------------------------
2003
- -----------------------------------------------------------------------------------------------------------------
Company Construction
Ownership Plant Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Progress
- -----------------------------------------------------------------------------------------------------------------
PEC Mayo Plant 83.83% $ 464 $ 242 $ 50
PEC Harris Plant 83.83% 3,248 1,370 7
PEC Brunswick Plant 81.67% 1,611 884 21
PEC Roxboro Unit 4 87.06% 323 139 1
PEF Crystal River Unit 3 91.78% 1,069 432 49
PEF Intercession City Unit P11 66.67% 22 6 6
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
2002
- -----------------------------------------------------------------------------------------------------------------
Company Construction
Ownership Plant Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Progress
- -----------------------------------------------------------------------------------------------------------------
PEC Mayo Plant 83.83% $ 464 $ 232 $ 14
PEC Harris Plant 83.83% 3,160 1,331 6
PEC Brunswick Plant 81.67% 1,477 811 26
PEC Roxboro Unit 4 87.06% 316 134 8
PEF Crystal River Unit 3 91.78% 777 375 28
PEF Intercession City Unit P11 66.67% 22 5 4
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Shearon Harris
Nuclear Plant (Harris Plant).
90
D. Decommissioning, Dismantlement and Cost of Removal Provisions
Decommissioning cost provisions, which are included in depreciation and
amortization expense, were $31 million, $31 million and $39 million in
2003, 2002 and 2001, respectively. The PEF rate case settlement required
PEF to suspend accruals on its reserves for nuclear decommissioning and
fossil dismantlement through December 31, 2005 (See Note 7D). Management
believes that decommissioning costs that have been and will be recovered
through rates by PEC and PEF will be sufficient to provide for the costs of
decommissioning.
PEF's provision for fossil plant dismantlement was previously suspended per
a 1997 FPSC settlement agreement, but resumed mid-2001. The 2001 annual
provision, approved by the FPSC, was $9 million. The accrual for fossil
dismantlement reserves was suspended again in 2002 by the Florida rate case
settlement (See Note 7D).
Cost of removal provisions, which are included in depreciation and
amortization expense, were $158 million, $149 million and $143 million in
2003, 2002 and 2001, respectively. These amounts represent the expense
recognized for the disposal or removal of utility assets. The FASB issued
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143),
that changed the accounting for the decommissioning, dismantlement and cost
of removal provisions (See Note 5F).
E. Insurance
PEC and PEF are members of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, each
company is insured for $500 million at each of its respective nuclear
plants. In addition to primary coverage, NEIL also provides
decontamination, premature decommissioning and excess property insurance
with limits of $2.0 billion on the Brunswick and Harris Plants, and $1.1
billion on the Robinson and Crystal River Unit No. 3 (CR3) Plants.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. Both PEC and PEF are insured
thereunder, following a twelve-week deductible period, for 52 weeks in the
amount of $3 million per week at the Brunswick and Harris Plants, $2.5
million per week at the Robinson Plant and $4.5 million per week at the CR3
Plant. An additional 110 weeks of coverage is provided at 80% of the above
weekly amounts. For the current policy period, the companies are subject to
retrospective premium assessments of up to approximately $27 million with
respect to the primary coverage, $31 million with respect to the
decontamination, decommissioning and excess property coverage, and $19
million for the incremental replacement power costs coverage, in the event
covered losses at insured facilities exceed premiums, reserves, reinsurance
and other NEIL resources. Pursuant to regulations of the United States
Nuclear Regulatory Commission (NRC), each company's property damage
insurance policies provide that all proceeds from such insurance be
applied, first, to place the plant in a safe and stable condition after an
accident and, second, to decontaminate, before any proceeds can be used for
decommissioning, plant repair or restoration. Each company is responsible
to the extent losses may exceed limits of the coverage described above.
Both PEC and PEF are insured against public liability for a nuclear
incident up to $10.9 billion per occurrence. Under the current provisions
of the Price Anderson Act, which limits liability for accidents at nuclear
power plants, each company, as an owner of nuclear units, can be assessed
for a portion of any third-party liability claims arising from an accident
at any commercial nuclear power plant in the United States. In the event
that public liability claims from an insured nuclear incident exceed $300
million (currently available through commercial insurers), each company
would be subject to pro rata assessments of up to $101 million for each
reactor owned per occurrence. Payment of such assessments would be made
over time as necessary to limit the payment in any one year to no more than
$10 million per reactor owned. Congress is expected to approve revisions to
the Price Anderson Act during 2004 that could include increased limits and
assessments per reactor owned. The final outcome of this matter cannot be
predicted at this time.
Under the NEIL policies, if there were multiple terrorism losses occurring
within one year, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant.
If terrorism losses occurred beyond the one-year period, a new set of
limits and resources would apply. For nuclear liability claims arising out
of terrorist acts, the primary level available through commercial insurers
is now subject to an industry aggregate limit of $300 million. The second
91
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $300 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts aggregate.
PEC and PEF self-insure their transmission and distribution lines against
loss due to storm damage and other natural disasters. PEF accrues $6
million annually to a storm damage reserve pursuant to a regulatory order
and may defer losses in excess of the reserve (See Note 7A).
F. Asset Retirement Obligations
SFAS No. 143 provides accounting and disclosure requirements for retirement
obligations associated with long-lived assets and was adopted by the
Company effective January 1, 2003. This statement requires that the present
value of retirement costs for which the Company has a legal obligation be
recorded as liabilities with an equivalent amount added to the asset cost
and depreciated over an appropriate period. The liability is then accreted
over time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect, to the date of adoption of
this statement. For assets acquired through acquisition, the cumulative
effect was based on the acquisition date.
Upon adoption of SFAS No. 143, the Company recorded AROs totaling $1,183
million for nuclear decommissioning of irradiated plants at PEC and PEF.
The Company used an expected cash flow approach to measure these
obligations. This amount includes accruals recorded prior to adoption
totaling $775 million, which were previously recorded in cost of removal.
The related asset retirement costs, net of accumulated depreciation,
recorded upon adoption totaled $368 million for regulated operations. The
adoption of this statement had no impact on the income of the regulated
entities, as the effects were offset by the establishment of a regulatory
asset and a regulatory liability pursuant to SFAS No. 71. A regulatory
asset was recorded related to PEC in the amount of $271 million,
representing the cumulative accretion and accumulated depreciation for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect to the date of adoption, less
amounts previously recorded. A regulatory liability was recorded related to
PEF in the amount of $231 million, representing the amount by which
previously recorded accruals exceeded the cumulative accretion and
accumulated depreciation for the time period from the date the liability
would have been recognized had the provisions of this statement been in
effect at the date of the acquisition of the assets by Progress Energy to
the date of adoption.
At December 31, 2003, the asset retirement costs related to nuclear
decommissioning of irradiated plant, net of accumulated depreciation,
totaled $354 million for regulated operations. The ongoing expense
differences between SFAS No. 143 and regulatory cost recovery are being
deferred to the regulatory asset and regulatory liability.
Funds set aside in the Company's nuclear decommissioning trust funds for
the nuclear decommissioning liability totaled $938 million at December 31,
2003 and $797 million at December 31, 2002. Net unrealized gains on the
nuclear decommissioning trust funds were included in regulatory liabilities
in 2003 and cost of removal in 2002.
Upon adoption of SFAS No. 143, the Company also recorded AROs totaling $10
million for synthetic fuel operations of PVI and coal mine operations,
synthetic fuel operations and gas production of Progress Fuels. The Company
used an expected cash flow approach to measure these obligations. This
amount includes accruals recorded prior to adoption totaling $5 million,
which was previously recorded in other liabilities and deferred credits.
The related asset retirement costs, net of accumulated depreciation,
recorded upon adoption totaled $7 million for nonregulated operations. The
cumulative effect of initial adoption of this statement related to
nonregulated operations was $1 million of income, which is included in
cumulative effect of change in accounting principles, net of tax on the
Consolidated Statements of Income for the year ended December 31, 2003.
The AROs for synthetic fuel operations of PVI and coal mine operations,
synthetic fuel operations and gas production of Progress Fuels totaled $20
million at December 31, 2003. The related asset retirement costs, net of
accumulated depreciation, totaled $7 million for nonregulated operations at
December 31, 2003. The following table shows the changes to the asset
retirement obligations during the year ended December 31, 2003. Additions
relate primarily to additional reclamation obligations at coal mine
operations of Progress Fuels.
92
(in millions) Regulated Nonregulated
-------------- ------------
Asset retirement obligations as of January 1, 2003 $ 1,183 $ 10
Additions - 11
Accretion expense 68 1
Deductions - (2)
-------------- ------------
Asset retirement obligations as of December 31, 2003 $ 1,251 $ 20
============== ============
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
The Company has identified but not recognized AROs related to electric
transmission and distribution and telecommunications assets as the result
of easements over property not owned by the Company. These easements are
generally perpetual and only require retirement action upon abandonment or
cessation of use of the property for the specified purpose. The ARO
liability is not estimable for such easements as the Company intends to
utilize these properties indefinitely. In the event the Company decides to
abandon or cease the use of a particular easement, an ARO liability would
be recorded at that time.
The utilities previously recognized removal, decommissioning and
dismantlement costs as a component of accumulated depreciation in
accordance with regulatory treatment. At December 31, 2003, such costs
totaling $2,169 million were included in regulatory liabilities on the
Consolidated Balance Sheets and consist of removal costs of $1,897 million,
removal costs for non-irradiated areas at nuclear facilities of $129
million and amounts previously collected for dismantlement of fossil
generation plants of $143 million. At December 31, 2002, such costs
totaling $2,940 million were included in cost of removal on the
Consolidated Balance Sheets and consist of removal costs of $1,790 million,
decommissioning costs for both the irradiated and non-irradiated areas at
nuclear facilities of $1,008 million and amounts previously collected for
dismantlement of fossil generation plants of $142 million. With the
adoption of SFAS No. 143 in 2003, removal costs related to the irradiated
areas at nuclear facilities are reported as asset retirement obligations on
the 2003 Consolidated Balance Sheet.
PEC filed a request with the NCUC requesting deferral of the difference
between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC initially granted the deferral of the
January 1, 2003 cumulative adjustment. During the third quarter of 2003,
the NCUC issued an order allowing the deferral of the ongoing effects of
SFAS No. 143. In April 2003, the SCPSC approved a joint request by PEC,
Duke Energy Corporation and South Carolina Electric and Gas Company for an
accounting order to authorize the deferral of all cumulative and
prospective effects related to the adoption of SFAS No. 143. Therefore,
SFAS No. 143 had no impact on the income of PEC for the year ended December
31, 2003.
In January 2003, the Staff of the FPSC issued a notice of proposed rule
development to adopt provisions relating to accounting for asset retirement
obligations under SFAS No. 143. Accompanying the notice was a draft rule
presented by the Staff which adopts the provisions of SFAS No. 143 along
with the requirement to record the difference between amounts prescribed by
the FPSC and those used in the application of SFAS No. 143 as regulatory
assets or regulatory liabilities, which was accepted by all parties. A
final order was issued in the third quarter of 2003. Therefore, the
adoption of the statement had no impact on the income of PEF due to the
establishment of a regulatory liability pursuant to SFAS No. 71.
6. Inventory
At December 31, inventory was comprised of:
(in millions) 2003 2002
-------------- -------------
Fuel $ 250 $ 313
Rail equipment and parts 132 155
Materials and supplies 386 363
Other 40 44
-------------- -------------
Total inventory $ 808 $ 875
============== =============
93
7. Regulatory Matters
A. Regulatory Assets and Liabilities
As regulated entities, the utilities are subject to the provisions of SFAS
No. 71. Accordingly, the utilities record certain assets and liabilities
resulting from the effects of the ratemaking process which would not be
recorded under GAAP for nonregulated entities. The utilities' ability to
continue to meet the criteria for application of SFAS No. 71 may be
affected in the future by competitive forces and restructuring in the
electric utility industry. In the event that SFAS No. 71 no longer applied
to a separable portion of the Company's operations, related regulatory
assets and liabilities would be eliminated unless an appropriate regulatory
recovery mechanism was provided. Additionally, these factors could result
in an impairment of utility plant assets as determined pursuant to SFAS No.
144.
At December 31, the balances of regulatory assets (liabilities) were as
follows:
(in millions) 2003 2002
----------------- ---------------
Deferred fuel cost $ 317 $ 184
----------------- ---------------
Deferred impact of ARO (Note 5F) 291 -
Income taxes recoverable through future rates (Note 14) 136 155
Deferred purchased power contract termination costs (Note 7B) - 47
Loss on reacquired debt (Note 1C) 55 33
Deferred DOE enrichment facilities-related costs (Note 1C) 24 31
Storm deferral (Note 7B) 21 -
Other postretirement benefits (Note 16B) 9 11
Other 76 70
----------------- ---------------
Total long-term regulatory assets 612 347
----------------- ---------------
Non-ARO cost of removal (Note 5F) (2,169) -
Deferred impact of ARO (Note 5F) (212) -
Net nuclear decommissioning trust unrealized gains (Note 5F) (204) -
Defined benefit retirement plan (Note 16B) (211) (51)
Storm reserve (Note 5E) (41) (36)
Clean air compliance (Note 7B) (74) -
Other (27) (33)
----------------- ---------------
Total long-term regulatory liabilities (2,938) (120)
----------------- ---------------
Net regulatory assets(liabilities) $ (2,009) $ 411
================= ===============
Except for portions of deferred fuel, all regulatory assets earn a return
or the cash has not yet been expended, in which case the assets are offset
by liabilities that do not incur a carrying cost. The Company expects to
fully recover these assets and refund the liabilities through customer
rates under current regulatory practice.
B. Retail Rate Matters
The NCUC and SCPSC have approved proposals to accelerate cost recovery of
PEC's nuclear generating assets beginning January 1, 2000, and continuing
through 2009. The aggregate minimum and maximum amounts of cost recovery
are $530 million and $750 million, respectively. Accelerated cost recovery
of these assets resulted in no additional expense in 2003 and additional
depreciation expense of approximately $53 million and $75 million in 2002
and 2001, respectively. Total accelerated depreciation recorded through
December 31, 2003 was $403 million.
In compliance with a regulatory order, PEF accrues a reserve for
maintenance and refueling expenses anticipated to be incurred during
scheduled nuclear plant outages.
In conjunction with the acquisition of NCNG in 1999, PEC agreed to cap base
retail electric rates in North Carolina and South Carolina through December
2004. The cap on base retail electric rates in South Carolina was extended
to December 2005 in conjunction with regulatory approval to form a holding
company.
94
The NC Clean Air Act of June 2002 (the Clean Air Act), requires state
utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide
(SO2) from coal-fired plants. The NCUC has allowed the utilities to
amortize and recover the costs associated with meeting the new emission
standards over a seven-year period beginning January 1, 2003. PEC
recognized $74 million of clean air amortization during 2003. This
legislation freezes PEC's base rates in North Carolina for five years,
subject to certain conditions (See Note 21E).
In conjunction with the FPC merger, PEC reached a settlement with the
Public Staff of the NCUC in which it agreed to provide credits to its
non-real time pricing customers in the amounts of $3 million in 2002, $5
million in 2003 and $6 million in both 2004 and 2005.
At December 31, 2000, PEF, with the approval of the FPSC, had established a
regulatory liability to defer $63 million of revenues. In 2001, PEF applied
the deferred revenues, plus accrued interest, to reduce its regulatory
asset related to deferred purchased power termination costs. In addition,
PEF recorded accelerated amortization of $34 million to further offset this
regulatory asset during 2001. During 2003, PEF fully amortized this
regulatory asset.
In February 2003, PEF petitioned the FPSC to increase its fuel factors due
to continuing increases in oil and natural gas commodity prices. In March
2003, the FPSC approved PEF's petition. New rates also became effective in
March 2003.
In September 2003, PEF asked the FPSC to approve a cost adjustment in its
annual fuel filing, primarily related to rising costs of fuel that will
increase retail customer bills beginning January 1, 2004. The total amount
of the fuel adjustment requested above current levels was approximately
$322 million. In November 2003, the FPSC approved PEF's request and new
rates became effective January 2004.
PEC obtained SCPSC and NCUC approval of fuel factors in annual
fuel-adjustment proceedings. The SCPSC approved PEC's petition to leave
billing rates unchanged from the prior year by order issued in March 2003.
The NCUC approved an increase of $20 million by order issued in September
2003.
In October 2003, PEC made a filing with the NCUC to seek permission to
defer expenses incurred from Hurricane Isabel and the February 2003 winter
storms. As a result of rising storm costs and the frequency of major storm
damage, PEC asked the NCUC to allow PEC to create a deferred account in
which PEC would place expenses incurred as a result of named tropical
storms, hurricanes and significant winter storms. In December 2003, the
NCUC approved PEC's request to defer the costs and amortize them over a
period of five years beginning in the month the storm occurs. PEC charged
approximately $24 million in 2003 from Hurricane Isabel and from current
year ice storms to the deferred account, of which $3 million was amortized
during 2003.
PEC retains funds internally to meet decommissioning liability. The NCUC
order issued February 2004 found that by January 1, 2008 PEC must begin
transitioning these amounts to external funds. The transition of $131
million must be completed by December 31, 2017, and at least 10% must be
transitioned each year. PEC has exclusively utilized external funding for
its decommissioning liability since 1994.
C. Regional Transmission Organizations and Standard Market Design
In 2000, the FERC issued Order 2000 regarding regional transmission
organizations (RTOs). This Order set minimum characteristics and functions
that RTOs must meet, including independent transmission service (ISOs). In
July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket No.
RM01-12-000, Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market Design (SMD NOPR). If
adopted as proposed, the rules set forth in the SMD NOPR would materially
alter the manner in which transmission and generation services are provided
and paid for. PEC and PEF, as subsidiaries of Progress Energy, filed
comments in November 2002 and supplemental comments in January 2003. In
April 2003, the FERC released a White Paper on the Wholesale Market
Platform. The White Paper provides an overview of what the FERC currently
intends to include in a final rule in the SMD NOPR docket. The White Paper
retains the fundamental and most protested aspects of SMD NOPR, including
mandatory RTOs and the FERC's assertion of jurisdiction over certain
aspects of retail service. The FERC has not yet issued a final rule on SMD
NOPR. The Company cannot predict the outcome of these matters or the effect
that they may have on the GridFlorida and GridSouth proceedings currently
ongoing before the FERC. It is unknown what impact the future proceedings
will have on the Company's earnings, revenues or prices.
95
The Company has $33 million and $4 million invested in GridSouth and
GridFlorida, respectively, at December 31, 2003. Given the regulatory
uncertainty of the ultimate timing, structure and operations of GridSouth,
GridFlorida or an alternate combined transmission structure, the Company
cannot predict the effect on future consolidated results of operations,
cash flows or financial condition. Furthermore, the SMD NOPR presents
several uncertainties, including what percentage of the investments in
GridSouth and GridFlorida will be recovered, how the elimination of
transmission charges, as proposed in the SMD NOPR, will impact the Company,
and what amount of capital expenditures will be necessary to create a new
wholesale market.
D. PEF Rate Case Settlement
The FPSC initiated a rate proceeding in 2001 regarding PEF's future base
rates. In March 2002, the parties in PEF's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC in April 2002. The
Agreement is generally effective from May 2002 through December 2005;
provided, however, that if PEF's base rate earnings fall below a 10% return
on equity, PEF may petition the FPSC to amend its base rates.
The Agreement provides that PEF will reduce its retail revenues from the
sale of electricity by an annual amount of $125 million. The Agreement also
provides that PEF will operate under a Revenue Sharing Incentive Plan (the
Plan) through 2005, and thereafter until terminated by the FPSC, that
establishes annual revenue caps and sharing thresholds. The Plan provides
that retail base rate revenues between the sharing thresholds and the
retail base rate revenue caps will be divided into two shares - a 1/3 share
to be received by PEF's shareholders, and a 2/3 share to be refunded to
PEF's retail customers; provided, however, that for the year 2002 only, the
refund to customers was limited to 67.1% of the 2/3 customer share. The
retail base rate revenue sharing threshold amounts for 2003 and 2002 were
$1,333 million and $1,296 million, respectively, and will increase $37
million each year thereafter. The Plan also provides that all retail base
rate revenues above the retail base rate revenue caps established for each
year will be refunded to retail customers on an annual basis. For 2002, the
refund to customers was limited to 67.1% of the retail base rate revenues
that exceeded the 2002 cap. The retail base revenue cap for 2003 and 2002
was $1,393 million and $1,356 million, respectively, and will increase $37
million each year thereafter. Any amounts above the retail base revenue
caps will be refunded 100% to customers. At December 31, 2003, $17 million
has been accrued and will be refunded to customers by March 2004.
Approximately $5 million was originally returned in March 2003 related to
2002 revenue sharing. However, in February 2003, the parties to the
Agreement filed a motion seeking an order from the FPSC to enforce the
Agreement. In this motion, the parties disputed PEF's calculation of retail
revenue subject to refund and contended that the refund should be
approximately $23 million. In July 2003, the FPSC ruled that PEF must
provide an additional $18 million to its retail customers related to the
2002 revenue sharing calculation. PEF recorded this refund in the second
quarter of 2003 as a charge against electric operating revenue and refunded
this amount by October 2003.
The Agreement also provides that beginning with the in-service date of
PEF's Hines Unit 2 and continuing through December 2005, PEF will be
allowed to recover through the fuel cost recovery clause a return on
average investment and depreciation expense for Hines Unit 2, to the extent
such costs do not exceed the Unit's cumulative fuel savings over the
recovery period. Hines Unit 2 is a 516 MW combined-cycle unit that was
placed in service in December 2003.
PEF will suspend accruals on its reserves for nuclear decommissioning and
fossil dismantlement through December 2005. Additionally, for each calendar
year during the term of the Agreement, PEF will record a $63 million
depreciation expense reduction, and may, at its option, record up to an
equal annual amount as an offsetting accelerated depreciation expense. In
addition, PEF is authorized, at its discretion, to accelerate the
amortization of certain regulatory assets over the term of the Agreement.
In 2003, PEF recorded $16 million of accelerated amortization of a
regulatory liability related to a settled tax matter. There was no
accelerated depreciation or amortization expense recorded for the year
ended December 31, 2002.
Under the terms of the Agreement, PEF agreed to continue the implementation
of its four-year Commitment to Excellence Reliability Plan and expects to
achieve a 20% improvement in its annual System Average Interruption
Duration Index by no later than 2004. If this improvement level is not
achieved for calendar years 2004 or 2005, PEF will provide a refund of $3
million for each year the level is not achieved to 10% of its total retail
customers served by its worst performing distribution feeder lines.
96
The Agreement also provided that, PEF was required to refund to customers
$35 million of revenues PEF collected during the interim period since March
2001. This one-time retroactive revenue refund was recorded in the first
quarter of 2002 and was returned to retail customers during 2002. Any
additional refunds under the Agreement are recorded when they become
probable.
8. Goodwill and Other Intangible Assets
Effective January 2002, the Company adopted SFAS No. 142. As required by
SFAS No. 142, the results for the prior year periods have not been
restated. A reconciliation of net income as if SFAS No. 142 had been
adopted is presented below for the year ended December 31, 2001. The
goodwill amortization used in the reconciliation includes $6 million
related to NCNG, which is included in discontinued operations.
Basic earnings per Diluted earnings per
(in millions, except per share data) Net income common share common share
---------- ------------------ --------------------
Reported $ 542 $ 2.65 $2.64
Goodwill amortization 96 0.47 0.47
---------- ------------------ --------------------
Adjusted $ 638 $ 3.12 $3.11
========== ================== ====================
The changes in the carrying amount of goodwill for the years ended December
31, 2002 and 2003, by reportable segment, are as follows:
(in millions) PEC Electric PEF CCO Other Total
--------------------------------------------------
Balance as of January 1, 2002 $ 1,922 $ 1,733 $ - $ 35 $ 3,690
Acquisitions (Note 4D) - - 64 - 64
Divestitures - - - (2) (2)
Discontinued operations (Note 3A) - - - (33) (33)
--------------------------------------------------
Balance as of December 31, 2002 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
Acquisitions (Note 4A) - - - 7 7
--------------------------------------------------
Balance as of December 31, 2003 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726
==================================================
The Company performed the annual goodwill impairment test for the CCO
segment in the first quarter of 2003, and the annual goodwill impairment
test for the PEC Electric and PEF segments in the second quarter of 2003,
which indicated no impairment. The first annual impairment test for the
Other segment will be performed in 2004, since the goodwill was acquired in
2003.
The gross carrying amount and accumulated amortization of the Company's
intangible assets at December 31 are as follows:
2003 2002
------------------------------- -------------------------------
(in millions) Gross Carrying Accumulated Gross Carrying Accumulated
Amount Amortization Amount Amortization
------------------------------- -------------------------------
Synthetic fuel intangibles $ 140 $ (64) $ 140 $ (45)
Power agreements acquired 221 (20) 33 (6)
Other 62 (12) 41 (8)
------------------------------- -------------------------------
Total $ 423 $ (96) $ 214 $ (59)
=============================== ===============================
All of the Company's intangibles are subject to amortization. Synthetic
fuel intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Code
(Section 29) in December 2007 (See Note 14). In May 2003, PVI acquired a
long-term full-requirements power supply agreement at fixed prices for $188
million. The intangible related to this power agreement is being amortized
based on the economic benefits of the contract (See Note 4C). As part of
the acquisition of generating assets from LG&E Energy Corp. in February
2002, power agreements of $33 million were recorded and are amortized based
on the economic benefits of the contracts through December 2004, which
approximates straight-line (See Note 4D). Other intangibles are primarily
acquired customer contracts and permits that are amortized over their
respective lives. Of the increase in other intangible assets, $9 million
relates to customer contracts acquired as part of the Westchester
acquisition, which was identified as an intangible in the final purchase
price allocation (See Note 4E).
97
Amortization expense recorded on intangible assets for the years ended
December 31, 2003, 2002 and 2001 was, in millions, $37, $33 and $22,
respectively. The estimated annual amortization expense for intangible
assets for 2004 through 2008, in millions, is approximately $42, $35, $36,
$36 and $17, respectively.
9. Impairments of Long-Lived Assets and Investments
Effective January 1, 2002, the Company adopted SFAS No. 144, which provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." In 2003, 2002 and 2001, the Company recorded pre-tax
long-lived asset and investment impairments and other charges of
approximately $38 million, $414 million and $209 million, respectively.
A. Long-Lived Assets
Due to the reduction in coal production the Company evaluated Kentucky May
Coal Mine's long-lived assets in 2003. Fair value was determined based on
discounted cash flows. As a result of this review, the Company recorded
asset impairments of $17 million on a pre-tax basis during the fourth
quarter of 2003.
An estimated impairment of assets held for sale of $59 million is included
in the 2002 amount, which relates to Railcar Ltd. (See Note 3B).
Due to the decline of the telecommunications industry and continued
operating losses, the Company initiated an independent valuation study
during 2002 to assess the recoverability of the long-lived assets of PTC
and Caronet. Based on this assessment, the Company recorded asset
impairments of $305 million on a pre-tax basis and other charges of $25
million on a pre-tax basis primarily related to inventory adjustments in
the third quarter of 2002. This write-down constitutes a significant
reduction in the book value of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, using market approaches as supporting information.
Due to historical losses at Strategic Resource Solutions Corp. (SRS) and
the decline in the market value for technology companies, the Company
evaluated the long-lived assets of SRS in 2001. Fair value was determined
based on discounted cash flows. As a result of this review, the Company
recorded asset impairments of $43 million and other charges of $2 million
on a pre-tax basis during the fourth quarter of 2001.
B. Investments
The Company continually reviews its investments to determine whether a
decline in fair value below the cost basis is other than temporary. In
2003, PEC's affordable housing investment (AHI) portfolio was reviewed and
deemed to be impaired based on various factors including continued
operating losses of the AHI portfolio and management performance issues
arising at certain properties within the AHI portfolio. As a result, PEC
recorded an impairment of $18 million on a pre-tax basis during the fourth
quarter of 2003. PEC also recorded an impairment of $3 million for a cost
investment.
In 2001, the Company obtained a valuation study to assess its investment in
Interpath Communications Inc. (Interpath) based on current valuations in
the technology sector. As a result, the Company recorded an impairment for
other-than-temporary declines in the fair value of its investment in
Interpath. Investment impairments were also recorded related to certain
investments of SRS. Investment write-downs totaled $164 million on a
pre-tax basis for the year ended December 31, 2001. In May 2002, Interpath
merged with a third party. As a result, the Company reviewed the Interpath
investment for impairment and wrote off the remaining amount of its
cost-basis investment in Interpath, recording a pre-tax impairment of $25
million in the third quarter of 2002. In the fourth quarter of 2002, the
Company sold its remaining interest in Interpath for a nominal amount.
98
10. Equity
A. Common Stock
In November 2002, the Company issued 14.7 million shares of common stock
for net cash proceeds of approximately $600 million, which were primarily
used to retire commercial paper. In April 2002, the Company issued 2.5
million shares of common stock, valued at approximately $129 million, in
conjunction with the purchase of Westchester (See Note 4E). In August 2001,
the Company issued 12.6 million shares of common stock for net cash
proceeds of $489 million, which were primarily used to retire commercial
paper.
At December 31, 2003, the Company had approximately 53 million shares of
common stock authorized by the Board of Directors that remained unissued
and reserved, primarily to satisfy the requirements of the Company's stock
plans. In 2002, the Board of Directors authorized meeting the requirements
of the Progress Energy 401(k) Savings and Stock Ownership Plan and the
Investor Plus Stock Purchase Plan with original issue shares. Prior to that
authorization, the Company met the requirements of these stock plans with
issued and outstanding shares held by the Trustee of the Progress Energy
401(k) Savings and Stock Ownership Plan (previously known as the Progress
Energy, Inc. Stock Purchase-Savings Plan) or with open market purchases of
common stock shares, as appropriate. During 2003 and 2002, respectively,
the Company issued approximately 8 million and 2 million shares under these
plans for net proceeds of approximately $309 million and $86 million. The
Company continues to meet the requirements of the restricted stock plan
with issued and outstanding shares.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. At December 31, 2003,
there were no significant restrictions on the use of retained earnings.
B. Stock-Based Compensation
Employee Stock Ownership Plan
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
Plan (401(k)) for which substantially all full-time non-bargaining unit
employees and certain part-time non-bargaining unit employees within
participating subsidiaries are eligible. Participating subsidiaries within
the Company as of January 1, 2003 were PEC, PEF, PTC, Progress Fuels
(Corporate) and Progress Energy Service Company. Effective December 19,
2003 (the PTC LLP/EPIK merger date), PTC no longer participates in the
401(k) plan. The 401(k), which has Company matching and incentive goal
features, encourages systematic savings by employees and provides a method
of acquiring Company common stock and other diverse investments. The
401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that
can enter into acquisition loans to acquire Company common stock to satisfy
401(k) common share needs. Qualification as an ESOP did not change the
level of benefits received by employees under the 401(k). Common stock
acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in
a suspense account. The common stock is released from the suspense account
and made available for allocation to participants as the ESOP loan is
repaid. Such allocations are used to partially meet common stock needs
related to Company matching and incentive contributions and/or reinvested
dividends. All or a portion of the dividends paid on ESOP suspense shares
and on ESOP shares allocated to participants may be used to repay ESOP
acquisition loans. To the extent used to repay such loans, the dividends
are deductible for income tax purposes. Also, beginning in 2002, the
dividends paid on ESOP shares which are either paid directly to
participants or used to purchase additional shares which are then allocated
to participants are fully deductible for income tax purposes.
There were 4.0 million and 4.6 million ESOP suspense shares at December 31,
2003 and 2002, respectively, with a fair value of $183 million and $200
million, respectively. ESOP shares allocated to plan participants totaled
13.1 million and 13.6 million in December 31, 2003 and 2002, respectively.
The Company's matching and incentive goal compensation cost under the
401(k) is determined based on matching percentages and incentive goal
attainment as defined in the plan. Such compensation cost is allocated to
participants' accounts in the form of Company common stock, with the number
of shares determined by dividing compensation cost by the common stock
market value at the time of allocation. The Company currently meets common
stock share needs with open market purchases, with shares released from the
ESOP suspense account and with newly issued shares. Costs for incentive
goal compensation are accrued during the fiscal year and typically paid in
shares in the following year; while costs for the matching component are
typically met with shares in the same year incurred. Matching and incentive
cost which were met and will be met with shares released from the suspense
account totaled approximately $20 million, $20 million and $18 million for
the years ended December 31, 2003, 2002 and 2001, respectively. Total
99
matching and incentive cost totaled approximately $35 million, $30 million
and $29 million for the years ended December 31, 2003, 2002 and 2001,
respectively, including 2001 amounts incurred under the previous Florida
Progress Corporation (Florida Progress) Plan. The Company has a long-term
note receivable from the 401(k) Trustee related to the purchase of common
stock from the Company in 1989. The balance of the note receivable from the
401(k) Trustee is included in the determination of unearned ESOP common
stock, which reduces common stock equity. ESOP shares that have not been
committed to be released to participants' accounts are not considered
outstanding for the determination of earnings per common share. Interest
income on the note receivable and dividends on unallocated ESOP shares are
not recognized for financial statement purposes.
Stock Option Agreements
Pursuant to the Company's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, amended and restated as of July 10, 2002, the Company may
grant options to purchase shares of common stock to directors, officers and
eligible employees for up to 5 million and 15 million shares, respectively.
Generally, options granted to employees vest one-third per year with 100%
vesting at the end of year three while options granted to directors vest
100% at the end of one year. The options expire ten years from the date of
grant. All option grants have an exercise price equal to the fair market
value of the Company's common stock on the grant date. The Company measures
compensation expense for stock options as the difference between the market
price of its common stock and the exercise price of the option at the grant
date. The exercise price at which options are granted by the Company equals
the market price at grant date and accordingly, no compensation expense has
been recognized for any options granted during 2003, 2002 and 2001.
The pro forma information presented in Note 1 regarding net income and
earnings per share is required by SFAS No. 148. Under this statement,
compensation cost is measured at the grant date based on the fair value of
the award and is recognized over the vesting period. The pro forma amounts
presented in Note 1 have been determined as if the Company had accounted
for its employee stock options under SFAS No. 123. The fair value for these
options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions:
2003 2002 2001
------------------------------
Risk-free interest rate 4.25% 4.14% 4.83%
Dividend yield 4.75% 5.20% 5.21%
Volatility factor 22.28% 24.98% 26.47%
Weighted-average expected life of the options (in years) 10 10 10
The option valuation model requires the input of highly subjective
assumptions, primarily stock price volatility, changes in which can
materially affect the fair value estimate.
The options outstanding at December 31, 2003, 2002 and 2001 had a
weighted-average remaining contractual life of 8.70, 9.32 and 9.75 years,
respectively, and had exercise prices that ranged from $40.41 to $51.85. At
December 31, 2003, 92 thousand options have been exercised, while no
options have expired. The tabular information for the option activity is as
follows:
2003 2002 2001
-----------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Average Average Average
Number of Exercise Number of Exercise Number of Exercise
(option quantities in millions) Options Price Options Price Options Price
- --------------------------------------------------------------------------------------------------------------------
Options outstanding, January 1 5.2 $ 42.84 2.3 $ 43.49 -
Granted 3.0 $ 44.70 2.9 $ 42.34 2.4 $ 43.49
Forfeited (0.1) $ 43.64 - $ 43.71 (0.1) $ 43.49
Canceled (0.1) $ 43.62 - - - -
Exercised - $ 43.00 - - - -
Options outstanding, December 31 8.0 $ 43.54 5.2 $ 42.84 2.3 $ 43.49
Options exercisable, December 31
with a remaining contractual life of
8.75 years 2.4 $ 43.09 0.8 $ 43.49 - -
Weighted-average grant date fair value
of options granted during the year $ 7.16 $ 6.83 $ 8.05
100
Other Stock-Based Compensation Plans
The Company has additional compensation plans for officers and key
employees of the Company that are stock-based in whole or in part. The two
primary programs are the Performance Share Sub-Plan (PSSP) and the
Restricted Stock Awards program (RSA), both of which were established
pursuant to the Company's 1997 Equity Incentive Plan and were continued
under the Company's 2002 Equity Incentive Plan, as amended and restated as
of July 10, 2002.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares that vest over a three-year consecutive period.
Each performance share has a value that is equal to, and changes with, the
value of a share of the Company's common stock, and dividend equivalents
are accrued on, and reinvested in, the performance shares. The PSSP has two
equally weighted performance measures, both of which are based on the
Company's results as compared to a peer group of utilities. Compensation
expense is recognized over the vesting period based on the expected
ultimate cash payout. Compensation expense is reduced by any forfeitures.
The RSA program allows the Company to grant shares of restricted common
stock to officers and key employees of the Company. The restricted shares
generally vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period, with
corresponding increases in common stock equity. The weighted-average price
of restricted shares at the grant date was $39.53, $44.27 and $41.86 in
2003, 2002 and 2001, respectively. Compensation expense is reduced by any
forfeitures. Restricted shares are not included as shares outstanding in
the basic earnings per share calculation until the shares are no longer
forfeitable. Changes in restricted stock shares outstanding were:
2003 2002 2001
--------- --------- ---------
Beginning balance 950,180 674,511 653,344
Granted 180,200 365,920 113,651
Vested (151,677) (75,200) (70,762)
Forfeited (33,820) (15,051) (21,722)
--------- --------- ---------
Ending balance 944,883 950,180 674,511
========= ========= =========
The total amount expensed for other stock-based compensation plans was $27
million, $17 million and $14 million in 2003, 2002 and 2001, respectively.
C. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average number of
common shares outstanding. Diluted earnings per share includes the effect
of the non-vested portion of restricted stock awards and the effect of
stock options outstanding.
A reconciliation of the weighted-average number of common shares
outstanding for basic and dilutive purposes is as follows:
(in millions) 2003 2002 2001
-------- --------- --------
Weighted-average common shares - basic 237.2 217.2 204.7
Restricted stock awards 1.0 .8 .6
Stock options - .2 -
-------- --------- --------
Weighted-average shares - fully diluted 238.2 218.2 205.3
======== ========= ========
101
There are no adjustments to net income or to income from continuing
operations between the calculations of basic and fully diluted earnings per
common share. ESOP shares that have not been committed to be released to
participants' accounts are not considered outstanding for the determination
of earnings per common share. The weighted-average of these shares totaled
4.1 million, 4.8 million and 5.4 million for the years ended December 31,
2003, 2002 and 2001, respectively. There were 5.3 million and 92 thousand
stock options outstanding at December 31, 2003 and 2002, respectively,
which were not included in the weighted-average number of shares for
computing the fully diluted earnings per share because they were
antidilutive.
D. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows:
(in millions) 2003 2002
----------- -----------
Loss on cash flow hedges $ (35) $ (42)
Minimum pension liability adjustments (15) (192)
Foreign currency translation and other - (4)
----------- -----------
Total accumulated other comprehensive loss $ (50) $(238)
=========== ===========
11. Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption
All of the Company's preferred stock was issued by its subsidiaries and was
not subject to mandatory redemption. Preferred stock outstanding at
December 31, 2003 and 2002 consisted of the following:
(in millions, except share data and par value)
Progress Energy Carolinas, Inc.
Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
20,000,000 shares, cumulative, $100 par value Serial Preferred Stock:
$5.00 Preferred - 236,997 shares outstanding (redemption price $110.00) $ 24
$4.20 Serial Preferred - 100,000 shares outstanding (redemption price $102.00) 10
$5.44 Serial Preferred - 249,850 shares outstanding (redemption price $101.00) 25
-------
$ 59
-------
Progress Energy Florida, Inc.
Authorized - 4,000,000 shares, cumulative, $100 par value Preferred Stock;
5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000
shares, $100 par value Preference Stock $100 par value Preferred Stock:
4.00% - 39,980 shares outstanding (redemption price $104.25) $ 4
4.40% - 75,000 shares outstanding (redemption price $102.00) 8
4.58% - 99,990 shares outstanding (redemption price $101.00) 10
4.60% - 39,997 shares outstanding (redemption price $103.25) 4
4.75% - 80,000 shares outstanding (redemption price $102.00) 8
-------
$ 34
-------
Total Preferred Stock of Subsidiaries $ 93
=======
102
12. Debt and Credit Facilities
A. Debt and Credit
At December 31, the Company's long-term debt consisted of the following
(maturities and weighted-average interest rates at December 31, 2003):
(in millions) 2003 2002
--------------- --------------
Progress Energy, Inc.
Senior unsecured notes, maturing 2004-2031 6.86% $ 4,800 $ 4,800
Unamortized fair value hedge gain, net 19 34
Unamortized premium and discount, net (27) (31)
--------------- --------------
4,792 4,803
--------------- --------------
Progress Energy Carolinas, Inc.
First mortgage bonds, maturing 2004-2033 6.42% 1,900 1,550
Pollution control obligations, maturing 2010-2024 1.69% 708 708
Unsecured notes, maturing 2012 6.50% 500 500
Medium-term notes, maturing 2008 6.65% 300 300
Miscellaneous notes - 6
Unamortized premium and discount, net (22) (16)
--------------- --------------
3,386 3,048
--------------- --------------
Progress Energy Florida, Inc.
First mortgage bonds, maturing 2004-2033 5.60% 1,330 810
Pollution control obligations, maturing 2018-2027 1.04% 241 241
Medium-term notes, maturing 2004-2028 6.75% 379 417
Unamortized premium and discount, net (3) (7)
--------------- --------------
1,947 1,461
--------------- --------------
Florida Progress Funding Corporation (See Note 12F)
Debt to affiliated trust, maturing 2039 7.10% 309 -
Mandatorily redeemable preferred securities, maturing 2039 - 300
Unamortized premium and discount, net (39) (39)
--------------- --------------
270 261
--------------- --------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2004-2008 6.78% 165 223
Miscellaneous notes 1 1
--------------- --------------
166 224
--------------- --------------
Progress Genco Ventures, LLC
Variable rate project financing, maturing 2007 3.04% 241 225
--------------- --------------
Current portion of long-term debt (868) (275)
--------------- --------------
Total long-term debt $ 9,934 $ 9,747
=============== ==============
At December 31, 2003 and 2002, the Company had $4 million and $695 million,
respectively, of outstanding commercial paper and other short-term debt
classified as short-term obligations. The weighted-average interest rates
of such short-term obligations at December 31, 2003 and 2002 were 2.25% and
1.67%, respectively.
At December 31, 2003, the Company had committed lines of credit which are
used to support its commercial paper borrowings and had no outstanding
loans. The Company is required to pay minimal annual commitment fees to
maintain its credit facilities. The following table summarizes the
Company's credit facilities:
103
(in millions)
Company Description Total
----------------------------------------------------------------------------------
Progress Energy, Inc. 364-Day (expiring 11/10/04) $ 250
Progress Energy, Inc. 3-Year (expiring 11/13/04) 450
Progress Energy Carolinas, Inc. 364-Day (expiring 7/29/04) 165
Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285
Progress Energy Florida, Inc. 364-Day (expiring 3/31/04) 200
Progress Energy Florida, Inc. 3-Year (expiring 4/1/06) 200
------------
Total credit facilities $ 1,550
============
Progress Energy and PEF each have an uncommitted bank bid facility
authorizing them to borrow and reborrow, and have loans outstanding at any
time, up to $300 million and $100 million, respectively. These bank bid
facilities were not drawn at December 31, 2003.
The combined aggregate maturities of long-term debt for 2004 through 2008
are approximately $868 million, $348 million, $908 million, $915 million
and $827 million, respectively.
B. Covenants and Default Provisions
Financial Covenants
Progress Energy's, PEC's and PEF's credit lines and the bank facility of
Progress Genco Ventures, LLC (Genco), a PVI subsidiary, contain various
terms and conditions that could affect the Company's ability to borrow
under these facilities. These include maximum debt to total capital ratios,
interest coverage tests, material adverse change clauses and cross-default
provisions.
All of the credit facilities and the Genco's bank facility include a
defined maximum total debt to total capital ratio. At December 31, 2003,
the maximum and calculated ratios for these four companies, pursuant to the
terms of the agreements, are as follows:
Company Maximum Ratio Actual Ratio (a)
--------------------------------------------------------------------
Progress Energy, Inc. 68% 61.5%
Progress Energy Carolinas, Inc. 65% 51.4%
Progress Energy Florida, Inc. 65% 51.5%
Progress Genco Ventures, LLC 40% 24.6%
(a) Indebtedness as defined by the bank agreements includes certain
letters of credit and guarantees which are not recorded on the
Consolidated Balance Sheets.
Progress Energy's 364-day credit facility and both PEF's 364-day and 3-year
credit facilities have a financial covenant for interest coverage. The
covenants require Progress Energy's and PEF's Earnings before interest,
taxes, and depreciation and amortization to interest expense ratio to be at
least 2.5 to 1 and 3 to 1, respectively. For the year ended December 31,
2003, the ratios were 3.74 to 1 and 9.22 to 1 for the Company and PEF,
respectively. Genco's bank facility requires a minimum 1.25 to 1 debt
service coverage ratio. For the year ended December 31, 2003, Genco's debt
service coverage was 6.35 to 1.
Material Adverse Change Clause
The credit facilities of Progress Energy, PEC, PEF and Genco include a
provision under which lenders could refuse to advance funds in the event of
a material adverse change in the borrower's financial condition.
Cross-Default Provisions
Progress Energy's, PEC's and PEF's credit lines include cross-default
provisions for defaults of indebtedness in excess of $10 million. Progress
Energy's cross-default provisions only apply to defaults of indebtedness by
Progress Energy and its significant subsidiaries (i.e., PEC, FPC, PEF, PVI,
Progress Fuels and Progress Capital Holdings, Inc. (PCH)). PEC's and PEF's
cross-default provisions only apply to defaults of indebtedness by PEC and
PEF and their subsidiaries, respectively, not other affiliates of PEC or
PEF. The Genco credit facility includes a similar provision for defaults by
Progress Energy or PVI.
104
Additionally, certain of Progress Energy's long-term debt indentures
contain cross-default provisions for defaults of indebtedness in excess of
$25 million; these provisions only apply to other obligations of Progress
Energy, not its subsidiaries. In the event that these indenture
cross-default provisions are triggered, the debt holders could accelerate
payment of approximately $4,800 million in long-term debt. Certain
agreements underlying the Company's indebtedness also limit its ability to
incur additional liens or engage in certain types of sale and leaseback
transactions.
Other Restrictions
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's
subsidiaries as outlined below.
PEC's mortgage indenture provides that, as long as any first mortgage bonds
are outstanding, cash dividends and distributions on its common stock and
purchases of its common stock are restricted to aggregate net income
available for PEC since December 31, 1948, plus $3 million, less the amount
of all preferred stock dividends and distributions, and all common stock
purchases, since December 31, 1948. At December 31, 2003, none of PEC's
retained earnings were restricted.
In addition, PEC's Articles of Incorporation provide that cash dividends on
common stock shall be limited to 75% of net income available for dividends
if common stock equity falls below 25% of total capitalization, and to 50%
if common stock equity falls below 20%. At December 31, 2003, PEC's common
stock equity was approximately 50.7% of total capitalization.
PEF's mortgage indenture provides that it will not pay any cash dividends
upon its common stock, or make any other distribution to the stockholders,
except a payment or distribution out of net income of PEF subsequent to
December 31, 1943. At December 31, 2003, none of PEF's retained earnings
were restricted.
In addition, PEF's Articles of Incorporation provide that no cash dividends
or distributions on common stock shall be paid, if the aggregate amount
thereof since April 30, 1944, including the amount then proposed to be
expended, plus all other charges to retained earnings since April 30, 1944,
exceed (a) all credits to retained earnings since April 30, 1944, plus (b)
all amounts credited to capital surplus after April 30, 1944, arising from
the donation to PEF of cash or securities or transfers of amounts from
retained earnings to capital surplus.
PEF's Articles of Incorporation also provide that cash dividends on common
stock shall be limited to 75% of net income available for dividends if
common stock equity falls below 25% of total capitalization, and to 50% if
common stock equity falls below 20%. On December 31, 2003, PEF's common
stock equity was approximately 52.5% of total capitalization.
Genco is required to hedge 75% of the amount outstanding under its bank
facility through September 2005 and 50% thereafter, pursuant to the term of
the agreement for expansion of its nonregulated generation portfolio. At
December 31, 2003, Genco held interest rate cash flow hedges with a
notional amount of $195 million and a total fair value of $11 million
liability position related to this covenant. See additional discussion of
interest rate cash flow hedges in Note 17.
C. Secured Obligations
PEC's and PEF's first mortgage bonds are secured by their respective
mortgage indentures. Each mortgage constitutes a first lien on
substantially all of the fixed properties of the respective company,
subject to certain permitted encumbrances and exceptions. Each mortgage
also constitutes a lien on subsequently acquired property. At December 31,
2003, PEC and PEF had a total of approximately $4,179 million of first
mortgage bonds outstanding, including those related to pollution control
obligations. Each mortgage allows the issuance of additional mortgage bonds
upon the satisfaction of certain conditions.
Genco obtained a bank facility to be used exclusively for expansion of its
nonregulated generation portfolio. Borrowings under this facility are
secured by the assets in the generation portfolio. The facility is for up
to $260 million, of which $241 million had been drawn at December 31, 2003.
Borrowings under the facility are restricted for the operations,
construction, repayments and other related charges of the credit facility
for the development projects. Cash held and restricted to operations was
$24 million and $21 million at December 31, 2003 and 2002, respectively,
and is included in other current assets. Cash held and restricted for
long-term purposes was $9 million and $37 million at December 31, 2003 and
2002, respectively, and is included in other assets and deferred debits on
the Consolidated Balance Sheets.
105
D. Guarantees of Subsidiary Debt
FPC has guaranteed the outstanding debt obligations for PCH, a wholly-owned
subsidiary of Florida Progress. At December 31, 2003 and 2002, PCH had $165
million and $223 million, respectively; in medium-term notes outstanding
which are recorded on the Company's accompanying Consolidated Balance
Sheets.
E. Hedging Activities
Progress Energy uses interest rate derivatives to adjust the fixed and
variable rate components of its debt portfolio and to hedge cash flow risk
related to commercial paper and to fixed rate debt to be issued in the
future. See discussion of risk management activities and derivative
transactions at Note 17.
F. FPC-Obligated Mandatorily Redeemable Preferred Securities of an
Unconsolidated Subsidiary Holding Solely FPC Guaranteed Notes
In April 1999, FPC Capital I (the Trust), an indirect wholly-owned
subsidiary of FPC, issued 12 million shares of $25 par cumulative
FPC-obligated mandatorily redeemable preferred securities (Preferred
Securities) due 2039, with an aggregate liquidation value of $300 million
and an annual distribution rate of 7.10%. Prior to the adoption of FIN No.
46, the Company consolidated the Trust, which holds the Preferred
Securities. The Trust is a special-purpose entity, and therefore the
Company applied FIN No. 46 to the Trust at December 31, 2003 (See Note 2).
The adoption of FIN No. 46 required the Company to deconsolidate the Trust
at December 31, 2003.
The existence of the Trust is for the sole purpose of issuing the Preferred
Securities and the common securities and using the proceeds thereof to
purchase from Florida Progress Funding Corporation (Funding Corp.) its
7.10% Junior Subordinated Deferrable Interest Notes (subordinated notes)
due 2039, for a principal amount of $309 million. The subordinated notes
and the Notes Guarantee (as discussed below) are the sole assets of the
Trust. Funding Corp.'s proceeds from the sale of the subordinated notes
were advanced to Progress Capital and used for general corporate purposes
including the repayment of a portion of certain outstanding short-term bank
loans and commercial paper.
FPC has fully and unconditionally guaranteed the obligations of Funding
Corp. under the subordinated notes (the Notes Guarantee). In addition, FPC
has guaranteed the payment of all distributions related to the $300 million
Preferred Securities required to be made by the Trust, but only to the
extent that the Trust has funds available for such distributions (Preferred
Securities Guarantee). The Preferred Securities Guarantee, considered
together with the Notes Guarantee, constitutes a full and unconditional
guarantee by FPC of the Trust's obligations under the Preferred Securities.
The subordinated notes may be redeemed at the option of Funding Corp.
beginning in 2004 at par value plus accrued interest through the redemption
date. The proceeds of any redemption of the subordinated notes will be used
by the Trust to redeem proportional amounts of the Preferred Securities and
common securities in accordance with their terms. Upon liquidation or
dissolution of Funding Corp., holders of the Preferred Securities would be
entitled to the liquidation preference of $25 per share plus all accrued
and unpaid dividends thereon to the date of payment.
Prior to December 2003, these Preferred Securities were classified as
long-term debt on the Company's Consolidated Balance Sheets. After
deconsolidation of the Trust at December 31, 2003, FPC's subordinated notes
payable to the Trust are classified as affiliate long-term debt on the
Company's December 31, 2003 Consolidated Balance Sheet.
13. Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents and short-term
obligations approximate fair value due to the short maturities of these
instruments. At December 31, 2003 and 2002, investments in company-owned
life insurance and other benefit plan assets, with carrying amounts of
approximately $162 million and $150 million, respectively, are included in
miscellaneous other property and investments and approximate fair value due
to the short maturity of the instruments. Other instruments are presented
at fair value in accordance with GAAP. The carrying amount of the Company's
long-term debt, including current maturities, was $10,802 million and
$10,022 million at December 31, 2003 and 2002, respectively. The estimated
fair value of this debt, as obtained from quoted market prices for the same
or similar issues, was $11,917 million and $10,974 million at December 31,
2003 and 2002, respectively.
106
External trust funds have been established to fund certain costs of nuclear
decommissioning (See Note 5D). These nuclear decommissioning trust funds
are invested in stocks, bonds and cash equivalents. Nuclear decommissioning
trust funds are presented on the Consolidated Balance Sheets at amounts
that approximate fair value. Fair value is obtained from quoted market
prices for the same or similar investments.
14. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. To the extent that the establishment of deferred income taxes
under SFAS No. 109, "Accounting for Income Taxes" is different from the
recovery of taxes by PEC and PEF through the ratemaking process, the
differences are deferred pursuant to SFAS No. 71. A regulatory asset or
liability has been recognized for the impact of tax expenses or benefits
that are recovered or refunded in different periods by the utilities
pursuant to rate orders.
Accumulated deferred income tax (assets) liabilities at December 31 are:
(in millions) 2003 2002
----------- ------------
Accumulated depreciation and property cost differences $ 1,524 $ 1,624
Deferred costs, net (49) (73)
Federal income tax credit carry forward (682) (472)
Minimum pension liability adjustment (9) (117)
Miscellaneous other temporary differences, net (153) (111)
Valuation allowance 42 47
----------- ------------
Net accumulated deferred income tax liability $ 673 $ 898
=========== ============
Total deferred income tax liabilities were $2,427 million and $2,430
million at December 31, 2003 and 2002, respectively. Total deferred income
tax assets were $1,754 million and $1,532 million at December 31, 2003 and
2002, respectively. At December 31, 2003 and 2002, the Company had net
noncurrent deferred tax liabilities of $737 million and $858 million. At
December 31, 2003, the Company had a net current deferred tax asset of $64
million which is included on the Consolidated Balance Sheets under the
caption prepayments and other current assets. At December 31, 2002, the
Company had a net current deferred tax liability of $40 million which is
included on the Consolidated Balance Sheets under the caption other current
liabilities.
The federal income tax credit carry forward at December 31, 2003 consists
of $659 million of alternative minimum tax credit with an indefinite
carry-forward period and $23 million of general business credit with a
carry-forward period that will begin to expire in 2020.
The Company established additional valuation allowances of $5 million, $12
million and $24 million during 2003, 2002 and 2001, respectively, due to
the uncertainty of realizing certain future state tax benefits. The overall
decrease in the 2003 valuation allowance balance is largely due to the
Company's sale of its wholly-owned subsidiary Caronet. The Company believes
it is more likely than not that the results of future operations will
generate sufficient taxable income to allow for the utilization of the
remaining deferred tax assets.
107
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
2003 2002 2001
------------ ------------- -------------
Effective income tax rate (15.5)% (40.0)% (40.0)%
State income taxes, net of federal benefit (3.3) (8.2) (7.7)
AFUDC amortization (2.0) (5.2) (5.0)
Federal tax credits 50.3 78.0 94.5
Goodwill amortization and write-offs - - (11.4)
Investment tax credit amortization 2.3 4.7 5.9
ESOP dividend deduction 2.1 3.8 1.9
Interpath investment impairment - - (2.1)
Other differences, net 1.1 1.9 (1.1)
------------ ------------- -------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
============ ============= =============
Income tax expense (benefit) applicable to continuing operations is
comprised of:
(in millions) 2003 2002 2001
------------- ------------- ------------
Current - federal $ 129 $ 195 $ 184
state 54 67 52
Deferred - federal (255) (379) (357)
state (21) (23) (10)
Investment tax credit (16) (18) (23)
------------- ------------ ------------
Total income tax expense (benefit) $ (109) $ (158) $ (154)
============= ============ ============
The Company, through its subsidiaries, is a majority owner in five entities
and a minority owner in one entity that owns facilities that produce
synthetic fuel as defined under the Internal Revenue Code (Code). The
production and sale of the synthetic fuel from these facilities qualifies
for tax credits under Section 29 if certain requirements are satisfied,
including a requirement that the synthetic fuel differs significantly in
chemical composition from the coal used to produce such synthetic fuel and
that the fuel was produced from a facility that was placed in service
before July 1, 1998. Total Section 29 credits generated to date (including
FPC prior to its acquisition by the Company) are approximately $1,243
million. All entities have received private letter rulings (PLRs) from the
Internal Revenue Service (IRS) with respect to their synthetic fuel
operations. The PLRs do not limit the production on which synthetic fuel
credits may be claimed. Should the tax credits be denied on future audits,
and the Company fails to prevail through the IRS or legal process, there
could be a significant tax liability owed for previously taken Section 29
credits, with a significant impact on earnings and cash flows.
One of the Company's synthetic fuel entities, Colona Synfuel Limited
Partnership, L.L.L.P. (Colona), is being audited by the IRS. The audit of
Colona was expected. The Company is audited regularly in the normal course
of business as are most similarly situated companies. The Company
(including FPC prior to its acquisition by the Company) has been allocated
approximately $317 million in tax credits to date from this synthetic fuel
entity.
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities, including Colona, were accepted into the IRS's Pre-Filing
Agreement (PFA) program. The PFA program allows taxpayers to voluntarily
accelerate the IRS exam process in order to seek resolution of specific
issues. Either the Company or the IRS can withdraw from the program at any
time, and issues not resolved through the program may proceed to the next
level of the IRS exam process. While the ultimate outcome is uncertain, the
Company believes that participation in the PFA program will likely shorten
the tax exam process.
In June 2003, the Company was informed that IRS field auditors had raised
questions regarding the chemical change associated with coal-based
synthetic fuel manufactured at its Colona facility and the testing process
by which the chemical change is verified. (The questions arose in
connection with the Company's participation in the PFA program.) The
chemical change and the associated testing process were described as part
of the PLR request for Colona. Based on that application, the IRS ruled in
Colona's PLR that the synthetic fuel produced at Colona undergoes a
significant chemical change and thus qualifies for tax credits under
Section 29.
108
In October 2003, the National Office of the IRS informed the Company that
it had rejected the IRS field auditors' challenges regarding whether the
synthetic fuel produced at the Company's Colona facility was the result of
a significant chemical change. The National Office had concluded that the
experts, engaged by Colona who test the synthetic fuel for chemical change,
use reasonable scientific methods to reach their conclusions. Accordingly,
the National Office will not take any adverse action on the PLR that has
been issued for the Colona facility.
Although this ruling applies only to the Colona facility, the Company
believes that the National Office's reasoning would be equally applicable
to the other Progress Energy facilities. The Company applies essentially
the same chemical process and uses the same independent laboratories to
confirm chemical change in the synthetic fuel manufactured at each of its
other facilities.
In February 2004, subsidiaries of the Company finalized execution of the
Colona Closing Agreement with the Internal Revenue Service concerning their
Colona synthetic fuel facilities. The Colona Closing Agreement provided
that the Colona facilities were placed in service before July 1, 1998,
which is one of the qualification requirements for tax credits under
Section 29. The Colona Closing Agreement further provides that the fuel
produced by the Colona facilities in 2001 is a "qualified fuel" for
purposes of the Section 29 tax credits. This action concludes the IRS PFA
program with respect to Colona.
Although the execution of the Colona Closing Agreement is a significant
event, the audits of the Company's facilities are not yet completed and the
PFA process continues with respect to the four synthetic fuel facilities
owned by other affiliates of Progress Energy and FPC. Currently, the focus
of that process is to determine that the facilities were placed in service
before July 1, 1998. In management's opinion, Progress Energy is complying
with all the necessary requirements to be allowed such credits under
Section 29, although it cannot provide certainty, that it will prevail if
challenged by the IRS on credits taken. Accordingly, the Company has no
current plans to alter its synthetic fuel production schedule as a result
of these matters.
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29. The investigation is examining the
utilization of the credits, the nature of the technologies and fuels
created, the use of the synthetic fuel and other aspects of Section 29 and
is not specific to the Company's synthetic fuel operations. Progress Energy
is providing information in connection with this investigation. The Company
cannot predict the outcome of this matter.
15. Contingent Value Obligations
In connection with the acquisition of FPC during 2000, the Company issued
98.6 million contingent value obligations (CVOs). Each CVO represents the
right to receive contingent payments based on the performance of four
synthetic fuel facilities purchased by subsidiaries of FPC in October 1999.
The payments, if any, would be based on the net after-tax cash flows the
facilities generate. The CVO liability is adjusted to reflect market price
fluctuations. The liability, included in other liabilities and deferred
credits, at December 31, 2003 and 2002, was $23 million and $14 million,
respectively.
16. Benefit Plans
A. Postretirement Benefits
The Company and some of its subsidiaries have a non-contributory defined
benefit retirement (pension) plan for substantially all full-time
employees. The Company also has supplementary defined benefit pension plans
that provide benefits to higher-level employees. In addition to pension
benefits, the Company and some of its subsidiaries provide contributory
other postretirement benefits (OPEB), including certain health care and
life insurance benefits, for retired employees who meet specified criteria.
The Company uses a measurement date of December 31 for its pension and OPEB
plans.
109
The components of net periodic benefit cost for the years ended December 31
are:
Pension Benefits Other Postretirement Benefits
--------------------------------- -----------------------------
(in millions) 2003 2002 2001 2003 2002 2001
--------------------------------- ---------------------------
Service cost $ 52 $ 45 $ 31 $ 15 $ 13 $ 13
Interest cost 108 106 96 33 32 28
Expected return on plan assets (144) (161) (169) (4) (5) (5)
Amortization of actuarial (gain) loss 25 2 (5) 5 1 -
Other amortization, net - - (1) 4 4 5
--------------------------------- ---------------------------
Net periodic cost/(benefit) $ 41 $ (8) $ (48) $ 53 $ 45 $ 41
Additional cost/(benefit) recognition (Note 16B) (18) (7) (16) 2 2 4
--------------------------------- ---------------------------
Net periodic cost/(benefit) recognized $ 23 $ (15) $ (64) $ 55 $ 47 $ 45
================================= ===========================
In addition to the net periodic cost and benefit reflected above, in 2003
the Company recorded curtailment and settlement effects related to the
disposition of NCNG, which are reflected in income/(loss) from discontinued
operations in the Consolidated Statements of Income. These effects included
a pension-related loss of $13 million and an OPEB-related gain of $1
million.
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the projected benefit
obligation or the market-related value of assets are amortized over the
average remaining service period of active participants.
To determine the market-related value of assets, the Company uses a 5-year
averaging method for a portion of its pension assets and fair value for the
remaining portion. The Company has historically used the 5-year averaging
method. When the Company acquired Florida Progress in 2000, it retained the
Florida Progress historical use of fair value to determine market-related
value for Florida Progress pension assets.
Reconciliations of the changes in the plans' benefit obligations and the
plans' funded status are:
Other Postretirement
Pension Benefits Benefits
------------------------ -------------------------
(in millions) 2003 2002 2003 2002
------------------------ -------------------------
Projected benefit obligation at January 1 $ 1,694 $ 1,391 $ 514 $ 401
Service cost 52 45 15 13
Interest cost 108 106 33 32
Disposition of NCNG (39) - (13) -
Benefit payments (94) (91) (24) (24)
Actuarial loss (gain) (66) 243 30 92
--------- ---------- --------- ----------
Obligation at December 31 1,655 1,694 555 514
Fair value of plan assets at December 31 1,631 1,364 65 52
--------- ---------- ---------- ----------
Funded status (24) (330) (490) (462)
Unrecognized transition obligation - 1 25 30
Unrecognized prior service cost 4 5 7 7
Unrecognized net actuarial (gain) loss 388 742 123 108
Minimum pension liability adjustment (23) (497) - -
----------- ---------- ---------- ----------
Prepaid (accrued) cost at December 31, net $ 345 $ (79) $ (335) $ (317)
(Note 16B) ======================== =======================
110
The net prepaid pension cost of $345 million at December 31, 2003 is
recognized in the Consolidated Balance Sheets as prepaid pension cost of
$462 million and accrued benefit cost of $117 million, which is included in
other liabilities and deferred credits. The net accrued pension cost of $79
million at December 31, 2002 is recognized in the Consolidated Balance
Sheets as prepaid pension cost of $60 million and accrued benefit cost of
$139 million, of which $130 million is included in other liabilities and
deferred credits and $9 million is included in liabilities of discontinued
operations. The defined benefit pension plans with accumulated benefit
obligations in excess of plan assets had projected benefit obligations
totaling $125 million and $1.51 billion at December 31, 2003 and 2002,
respectively. Those plans had accumulated benefit obligations totaling $117
million and $1.35 billion December 31, 2003 and 2002, respectively, no plan
assets at December 31, 2003 and plan assets totaling $1.22 billion at
December 31, 2002. The total accumulated benefit obligation for pension
plans was $1.61 billion and $1.49 billion at December 31, 2003 and 2002,
respectively. The accrued OPEB cost is included in other liabilities and
deferred credits in the Consolidated Balance Sheets.
A minimum pension liability adjustment of $23 million, related to the
supplementary defined benefit pension plans, was recorded at December 31,
2003. This adjustment is offset by a corresponding pre-tax amount in
accumulated other comprehensive loss, a component of common stock equity.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $497 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $5 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, a $178 million charge to a
pension-related regulatory liability (See Note 16B) and a pre-tax charge of
$313 million to accumulated other comprehensive loss, a component of common
stock equity.
Reconciliations of the fair value of plan assets are:
Other Postretirement
Pension Benefits Benefits
------------------------ ----------------------
(in millions) 2003 2002 2003 2002
------------------------ ----------------------
Fair value of plan assets January 1 $ 1,364 $ 1,678 $ 52 $ 56
Actual return on plan assets 391 (228) 12 (5)
Disposition of NCNG (35) - - -
Benefit payments (94) (91) (24) (24)
Employer contributions 5 5 25 25
------------------------ ----------------------
Fair value of plan assets at December 31 $ 1,631 $ 1,364 $ 65 $ 52
======================== ======================
In the table above, substantially all employer contributions represent
benefit payments made directly from Company assets. The remaining benefits
payments were made directly from plan assets. The OPEB benefit payments
represent the net Company cost after participant contributions. Participant
contributions represent approximately 20% of gross benefit payments.
The asset allocation for the Company's plans at the end of 2003 and 2002
and the target allocation for the plans, by asset category, are as follows:
Pension Benefits Other Postretirement Benefits
------------------------------------------ --------------------------------------------
Target Percentage of Plan Assets Target Percentage of Plan Assets at
Allocations at Year End Allocations Year End
----------- ------------------------- ----------- ----------------------------
Asset Category 2004 2003 2002 2004 2003 2002
----------- ---------- ---------- ----------- ----------- ------------
Equity - domestic 50% 49% 47% 35% 35% 32%
Equity - international 15% 22% 20% 10% 16% 14%
Debt - domestic 15% 11% 15% 45% 37% 41%
Debt - international 10% 11% 10% 5% 7% 7%
Other 10% 7% 8% 5% 5% 6%
----------- ---------- ---------- ----------- ----------- ------------
Total 100% 100% 100% 100% 100% 100%
=========== ========== ========== =========== =========== ============
111
The Company sets target allocations among asset classes to provide broad
diversification to protect against large investment losses and excessive
volatility, while recognizing the importance of offsetting the impacts of
benefit cost escalation. In addition, the Company employs external
investment managers who have complementary investment philosophies and
approaches. Tactical shifts (plus or minus 5%) in asset allocation from the
target allocations are made based on the near-term view of the risk and
return tradeoffs of the asset classes.
In 2004, the Company expects to make $24 million of required contributions
directly to pension plan assets and $1 million of discretionary
contributions directly to the OPEB plan assets. The expected benefit
payments for the pension benefit plan for 2004 through 2008 and in total
for 2009-2013, in millions, are approximately $93, $96, $99, $104, $108 and
$608, respectively. The expected benefit payments for the OPEB plan for
2004 through 2008 and in total for 2009-2013, in millions, are
approximately $22, $24, $26, $28, $30 and $180, respectively. The expected
benefit payments include benefit payments directly from plan assets and
benefit payments directly from Company assets. The benefit payment amounts
reflect the net cost to the Company after any participant contributions.
The following weighted-average actuarial assumptions were used in the
calculation of the year-end obligation:
Pension Benefits Other Postretirement Benefits
-------------------- -----------------------------
2003 2002 2003 2002
---------- --------- -----------------------------
Discount rate 6.30% 6.60% 6.30% 6.60%
Rate of increase in future compensation
Bargaining 3.50% 3.50% - -
Non-bargaining - 4.00% - -
Supplementary plans 5.00% 4.00%
Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.50%
Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.50%
Ultimate medical cost trend rate - - 5.25% 5.25%
Year ultimate medical cost trend rate is achieved - - 2009 2009
The Company's primary defined benefit retirement plan for non-bargaining
employees is a "cash balance" pension plan as defined in EITF Issue No.
03-4. Therefore, effective December 31, 2003, the Company began to use the
traditional unit credit method for purposes of measuring the benefit
obligation of this plan and will use that method to measure future benefit
costs. Under the traditional unit credit method, no assumptions are
included about future changes in compensation and the accumulated benefit
obligation and projected benefit obligation are the same.
The following weighted-average actuarial assumptions were used in the
calculation of the net periodic cost:
Pension Benefits Other Postretirement Benefits
---------------------------- -------------------------------
2003 2002 2001 2003 2002 2001
---------------------------- -------------------------------
Discount rate 6.60% 7.50% 7.50% 6.60% 7.50% 7.50%
Rate of increase in future compensation
Bargaining 3.50% 3.50% 3.50% - - -
Non-bargaining and supplementary 4.00% 4.00% 4.00% - - -
Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 8.45% 8.20% 8.70%
Initial medical cost trend rate for pre-Medicare benefits - - - 7.50% 7.50% 7.2% - 7.5%
Initial medical cost trend rate for post-Medicare benefits - - - 7.50% 7.50% 6.2% - 7.5%
Ultimate medical cost trend rate - - - 5.25% 5.00% 5.0% - 5.3%
Year ultimate medical cost trend rate is achieved - - - 2009 2008 2005-2009
The expected long-term rates of return on plan assets were determined by
considering long-term historical returns for the plans and long-term
projected returns based on the plans' target asset allocation. For all
pension plan assets and a substantial portion of OPEB plans assets, those
benchmarks support an expected long-term rate of return between 9.5% and
10.0%. The Company has chosen to use an expected long-term rate of 9.25%
due to the uncertainties of future returns.
112
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2003 would increase by $3 million, and
the OPEB obligation at December 31, 2003, would increase by $38 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for
2003 would decrease by $2 million and the OPEB obligation at December 31,
2003, would decrease by $33 million.
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. In accordance with
guidance issued by the FASB in FASB Staff Position FAS 106-1, the Company
has elected to defer accounting for the effects of the Act due to
uncertainties regarding the effects of the implementation of the Act and
the accounting for certain provisions of the Act. Therefore, OPEB
information presented above and in the financial statements does not
reflect the effects of the Act. When specific authoritative accounting
guidance is issued, it could require plan sponsors to change previously
reported information. The Company is in the early stages of reviewing the
Act and determining its potential effects on the Company.
B. FPC Acquisition
During 2000, the Company completed the acquisition of FPC. FPC's pension
and OPEB liabilities, assets and net periodic costs are reflected in the
above information as appropriate. Certain of FPC's non-bargaining unit
benefit plans were merged with those of the Company effective January 1,
2002.
PEF continues to recover qualified plan pension costs and OPEB costs in
rates as if the acquisition had not occurred. Accordingly, a portion of the
accrued OPEB cost reflected in the table above has a corresponding
regulatory asset at December 31, 2003 and 2002 (See Note 7A). In addition,
a portion of the prepaid pension cost reflected in the table above has a
corresponding regulatory liability (See Note 7A). Pursuant to its rate
treatment, PEF recognized additional periodic pension credits and
additional periodic OPEB costs, as indicated in the net periodic cost
information above.
17. Risk Management Activities and Derivatives Transactions
Under its risk management policy, the Company may use a variety of
instruments, including swaps, options and forward contracts, to manage
exposure to fluctuations in commodity prices and interest rates. Such
instruments contain credit risk if the counterparty fails to perform under
the contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. Potential nonperformance by counterparties is not expected
to have a material effect on the consolidated financial position or
consolidated results of operations of the Company.
A. Commodity Contracts - General
Most of the Company's commodity contracts are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related
to the pricing of contracts that include broad market indices (e.g., CPI).
In particular, that guidance discussed whether the pricing in a contract
that contains broad market indices could qualify as a normal purchase or
sale (the normal purchase or sale term is a defined accounting term, and
may not, in all cases, indicate whether the contract would be "normal" from
an operating entity viewpoint). The FASB issued final superseding guidance
(DIG Issue C20) on this issue effective October 1, 2003 for the Company.
DIG Issue C20 specifies new pricing-related criteria for qualifying as a
normal purchase or sale, and it required a special transition adjustment as
of October 1, 2003.
PEC determined that it had one existing "normal" contract that was affected
by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
a pre-tax fair value loss transition adjustment of $38 million ($23 million
after-tax) in the fourth quarter of 2003, which was reported as a
cumulative effect of a change in accounting principle. The subject contract
meets the DIG Issue C20 criteria for normal purchase or sale and,
therefore, was designated as a normal purchase as of October 1, 2003. The
liability of $38 million associated with the fair value loss is being
amortized to earnings over the term of the related contract.
113
B. Commodity Derivatives - Cash Flow Hedges
The Company held natural gas cash flow hedging instruments at December 31,
2003 and 2002. The objective for holding these instruments is to manage a
portion of the market risk associated with fluctuations in the price of
natural gas for the Company's forecasted sales. At December 31, 2003, the
Company is hedging exposures to the price variability of natural gas
through December 2005.
The total fair value of these instruments at December 31, 2003 and 2002 was
a $12 million and a $10 million liability position, respectively. The
ineffective portion of commodity cash flow hedges was not material in 2003
and 2002. At December 31, 2003, $7 million of after-tax deferred losses in
accumulated other comprehensive income (OCI) are expected to be
reclassified to earnings during the next 12 months as the hedged
transactions occur. Due to the volatility of the commodities markets, the
value in OCI is subject to change prior to its reclassification into
earnings.
C. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity and natural gas contracts,
are entered into for trading purposes and for economic hedging purposes.
While management believes the economic hedges mitigate exposures to
fluctuations in commodity prices, these instruments are not designated as
hedges for accounting purposes and are monitored consistent with trading
positions. The Company manages open positions with strict policies that
limit its exposure to market risk and require daily reporting to management
of potential financial exposures. Gains and losses from such contracts were
not material during 2003, 2002 or 2001, and the Company did not have
material outstanding positions in such contracts at December 31, 2003 or
2002.
D. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company manages its interest rate exposure in part by maintaining its
variable-rate and fixed-rate exposures within defined limits. In addition,
the Company also enters into financial derivative instruments, including,
but not limited to, interest rate swaps and lock agreements to manage and
mitigate interest rate risk exposure.
The Company uses cash flow hedging strategies to hedge variable interest
rates on long-term and short-term debt and to hedge interest rates with
regard to future fixed-rate debt issuances. At December 31, 2003 and 2002,
the Company held interest rate cash flow hedges, with a varying notional
amount and maximum of $195 million, related to variable rate long-term
debt. At December 31, 2003, the Company also held interest rate cash flow
hedges, with a total notional amount of $400 million, related to projected
outstanding balances of commercial paper. At December 31, 2002, the Company
also held an interest rate cash flow hedge, with a notional amount of $35
million, related to the issuance of fixed-rate debt in early 2003. The
total fair value of these hedges at December 31, 2003 and 2002 was a $6
million and a $13 million liability position, respectively. At December 31,
2003, $7 million of after-tax deferred losses in OCI, including amounts in
OCI related to terminated hedges, are expected to be reclassified to
earnings during the next 12 months as the hedged interest payments occur.
Due to the volatility of interest rates, the value in OCI is subject to
change prior to its reclassification into earnings.
The Company uses fair value hedging strategies to manage its exposure to
fixed interest rates on long-term debt. At December 31, 2003, the Company
had open interest rate fair value hedges with notional amounts totaling
$850 million and a total fair value of $4 million liability position. At
December 31, 2002, the Company had open interest rate fair value hedges
with notional amounts totaling $350 million and a total fair value of $5
million asset position. In addition, at December 31, 2003, the Company had
$23 million of net hedging gains related to terminated interest rate fair
value hedges, which is reflected in long-term debt and is being amortized
over periods ending in 2006 through 2008 coinciding with the maturities of
the related debt instruments.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
114
18. Related Party Transactions
Progress Fuels sells coal to PEF for an insignificant profit. These
intercompany revenues are eliminated in consolidation; however, in
accordance with SFAS No. 71, profits on intercompany sales to regulated
affiliates are not eliminated if the sales price is reasonable and the
future recovery of the sales price through the ratemaking process is
probable. The profits for all the years presented were not significant.
The Company sold NCNG to Piedmont Natural Gas Company, Inc. on September
30, 2003 (See Note 3A). Prior to disposition, NCNG sold natural gas to
affiliates. During the years ended December 31, 2003, 2002 and 2001, sales
of natural gas to affiliates amounted to $11 million, $20 million and $19
million, respectively. These revenues are included in discontinued
operations on the Consolidated Statements of Income.
The Company has an outstanding note due to a related trust. The principal
outstanding on this note was $309 million at December 31, 2003 (See Note
12A and F).
19. Financial Information by Business Segment
The Company currently provides services through the following business
segments: PEC Electric, PEF, Fuels, CCO, Rail Services and Other. Prior to
2003, Fuels and CCO were reported together as the Progress Ventures
business segment and corporate costs were included in the Other segment.
These reportable segment changes reflect the current management structure.
PEC Electric and PEF are primarily engaged in the generation, transmission,
distribution and sale of electric energy in portions of North Carolina,
South Carolina and Florida. These electric operations are subject to the
rules and regulations of the FERC, the NCUC, the SCPSC and the FPSC. These
electric operations also distribute and sell electricity to other
utilities, primarily on the east coast of the United States.
Fuels operations, which are located throughout the United States, are
involved in natural gas drilling and production, coal terminal services,
coal mining, synthetic fuel production, fuel transportation and delivery.
CCO's operations, which are located in the southeastern United States,
include nonregulated electric generation operations and marketing
activities.
Rail Services' operations include railcar repair, rail parts reconditioning
and sales, railcar leasing and sales and scrap metal recycling. These
activities include maintenance and reconditioning of salvageable scrap
components of railcars, locomotive repair and right-of-way maintenance.
Rail Services' operations are located in the United States, Canada and
Mexico.
The Other segment, whose operations are in the United States, is composed
of other nonregulated business areas including telecommunications and
energy service operations and other nonregulated subsidiaries that do not
separately meet the disclosure requirements of SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information." Included in this
segment's 2002 losses are asset impairments and certain other after-tax
charges related to the telecommunications operations of $225 million, the
2001 results include asset impairments and other after-tax charges of $153
million.
In addition to these reportable operating segments, the Company has other
corporate activities that include holding company operations, service
company operations and eliminations. These corporate activities have been
included in the Other segment in the past. Additionally, earnings from
wholesale customers on the regulated plants have previously been reported
in both the regulated utilities' results and the results of Progress
Ventures (which referred to Fuels and CCO collectively). This activity is
now included in the regulated utilities results only. The operations of
NCNG, previously reported in the Other segment, were reclassified to
discontinued operations and therefore are not included in the results from
continuing operations during the periods reported. For comparative
purposes, the results have been restated to align with the new business
segment structure. The profit or loss of the identified segments plus the
loss of Corporate represents the Company's total income from continuing
operations.
115
- --------------------------------------------------------------------------------------------------------------
(in millions) PEC Rail
Electric PEF Fuels CCO Services(a) Other Corporate Totals
- --------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2003
Revenues
Unaffiliated $ 3,589 $ 3,152 $ 928 $ 170 $ 846 $ 58 $ - $ 8,743
Intersegment - - 346 - 1 15 (362) -
- --------------------------------------------------------------------------------------------------------------
Total revenues 3,589 3,152 1,274 170 847 73 (362) 8,743
- --------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 562 307 80 42 20 6 23 1,040
Total interest charges, 194 91 23 4 29 (1) 285 625
net
Impairment of long-lived
assets and investments 11 - 17 - - 10 - 38
Income tax (benefit) (b) 240 147 (415) 8 2 (4) (87) (109)
Segment profit (loss) 515 295 235 20 (1) (17) (236) 811
Total assets 10,854 7,306 1,170 1,747 586 304 4,235 26,202
Capital and investment
expenditures 470 548 310 360 103 12 22 1,825
- --------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2002
Revenues
Unaffiliated $ 3,539 $ 3,062 $ 607 $ 92 $ 714 $ 77 $ - $ 8,091
Intersegment - - 329 - 5 14 (348) -
- --------------------------------------------------------------------------------------------------------------
Total revenues 3,539 3,062 936 92 719 91 (348) 8,091
- --------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 524 295 47 20 20 15 17 938
Total interest charges, net 212 106 24 (12) 33 (5) 275 633
Impairment of
long-lived
assets and investments - - - - 59 330 - 389
Income tax (benefit) (b) 237 163 (373) 16 (16) (129) (56) (158)
Segment profit (loss) 513 323 176 27 (42) (243) (202) 552
Total assets 10,139 6,678 934 1,452 529 318 3,668 23,718
Capital and investment
expenditures 624 550 172 682 8 53 20 2,109
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2001
Revenues
Unaffiliated $ 3,344 $ 3,213 $ 559 $ 16 $ 890 $ 107 $ - $ 8,129
Intersegment - - 299 - 1 13 (313) -
- --------------------------------------------------------------------------------------------------------------
Total revenues 3,344 3,213 858 16 891 120 (313) 8,129
- --------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 522 453 34 4 36 18 83 1,150
Total interest charges, net 241 113 24 - 41 (7) 261 673
Impairment of long-lived
assets and investments - - - - - 207 207
Income tax (benefit) 264 183 (424) 3 (6) (57) (117) (154)
Segment profit (loss) 468 309 199 4 (12) (162) (265) 541
Capital and investment
expenditures 824 353 70 195 13 72 - 1,527
- --------------------------------------------------------------------------------------------------------------
(a) Amounts for the year ended December 31, 2001 reflect cumulative operating
results of Rail Services since the acquisition date of November 30, 2000.
(b) Amounts for 2003 and 2002 include income tax benefit reallocation from
holding company to profitable subsidiaries according to an SEC order.
20. Other Income and Other Expense
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items
as discussed below. The components of other, net as shown on the
Consolidated Statements of Income for the years ended December 31, are as
follows:
116
(in millions) 2003 2002 2001
---- ---- ----
Other income
Net financial trading loss $ (2) $ (2) $ (1)
Net energy brokered for resale 2 2 3
Nonregulated energy and delivery services income 22 29 29
Contingent value obligation unrealized gain (Note 15) - 28 -
Investment gains 9 30 3
Income from equity investments 9 9 7
AFUDC equity 14 9 9
Other 26 16 5
-----------------------------
Total other income $ 80 $ 121 $ 55
-----------------------------
Other expense
Nonregulated energy and delivery services expenses 20 29 35
Donations 15 21 23
Investment losses 27 18 4
Contingent value obligation unrealized loss (Note 15) 9 - 1
Loss from minority interest 3 - 3
Other 31 26 23
-----------------------------
Total other expense $ 105 $ 94 $ 89
-----------------------------
Other, net $ (25) $ 27 $ (34)
=============================
Net financial trading loss represents nonasset-backed trades of electricity
and gas. Nonregulated energy and delivery services include power protection
services and mass market programs (surge protection, appliance services and
area light sales) and delivery, transmission and substation work for other
utilities.
21. Commitments and Contingencies
A. Purchase Obligations
The following table reflects Progress Energy's contractual cash obligations
and other commercial commitments in the respective periods in which they
are due:
(in millions)
Contractual Cash Obligations 2004 2005 2006 2007 2008 Thereafter
-------------------------------------------------------------------------------------------
Fuel $ 1,245 $ 628 $ 459 $ 271 $ 151 $ 1,012
Purchased power 427 439 450 459 431 4,711
Construction obligations 112 49 - - - -
Other purchase obligations 28 11 18 11 16 124
-----------------------------------------------------------
Total $ 1,812 $ 1,127 $ 927 $ 741 $ 598 $ 5,847
===========================================================
Fuel and Purchased Power
FPC, PEC and PVI have entered into various long-term contracts for coal,
gas and oil. Payments under these commitments were $1,207 million, $1,359
million and $1,257 million for 2003, 2002 and 2001, respectively. Estimated
annual payments for firm commitments of fuel purchases and transportation
costs under these contracts are approximately $1,245 million, $628 million,
$459 million, $271 million and $151 million for 2004 through 2008,
respectively, with approximately $1,012 million payable thereafter.
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between PEC and the North Carolina Eastern Municipal Power Agency (Power
Agency), PEC is obligated to purchase a percentage of Power Agency's
ownership capacity of, and energy from, the Harris Plant. In 1993, PEC and
Power Agency entered into an agreement to restructure portions of their
contracts covering power supplies and interests in jointly owned units.
Under the terms of the 1993 agreement, PEC increased the amount of capacity
and energy purchased from Power Agency's ownership interest in the Harris
Plant, and the buyback period was extended six years through 2007. The
estimated minimum annual payments for these purchases, which reflect
capacity costs, total approximately $36 million. These contractual
117
purchases totaled $36 million, $36 million and $33 million for 2003, 2002
and 2001, respectively. In 1987, the NCUC ordered PEC to reflect the
recovery of the capacity portion of these costs on a levelized basis over
the original 15-year buyback period, thereby deferring for future recovery
the difference between such costs and amounts collected through rates. At
December 31, 2002, PEC had deferred purchased capacity costs, including
carrying costs accrued on the deferred balances of $17 million. At December
31, 2003, all previously deferred costs have been expensed.
PEC has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 MW of
capacity through 2009 with minimum annual payments of approximately $42
million, representing capital-related capacity costs. Total purchases
(including energy and transmission use charges) under the Rockport
agreement amounted to $66 million, $59 million and $63 million for 2003,
2002 and 2001, respectively.
Effective June 1, 2001, PEC executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 MW of capacity
through 2021 with an original minimum annual payment of approximately $16
million, primarily representing capital-related capacity costs. A separate
long-term agreement for additional power from Broad River commenced June 1,
2002. This agreement provided for the additional purchase of approximately
300 MW of capacity through 2022 with an original minimum annual payment of
approximately $16 million representing capital-related capacity costs.
Total purchases under the Broad River agreements amounted to $37 million,
$38 million and $21 million in 2003, 2002 and 2001, respectively.
PEF has long-term contracts for approximately 474 MW of purchased power
with other utilities, including a contract with The Southern Company for
approximately 414 MW of purchased power annually through 2010. PEF can
lower these purchases to approximately 200 MW annually with a three-year
notice. Total purchases, for both energy and capacity, under these
agreements amounted to $141 million, $159 million and $112 million for
2003, 2002 and 2001, respectively. Total capacity payments were $57
million, $51 million and $54 million for 2003, 2002 and 2001, respectively.
Minimum purchases under these contracts, representing capital-related
capacity costs, are approximately $60 million annually through 2009 and $30
million annually for 2010.
Both PEC and PEF have ongoing purchased power contracts with certain
cogenerators (qualifying facilities) with expiration dates ranging from
2004 to 2025. These purchased power contracts generally provide for
capacity and energy payments. Energy payments for the PEF contracts are
based on actual power taken under these contracts. Capacity payments are
subject to the qualifying facilities (QFs) meeting certain contract
performance obligations. PEF's total capacity purchases under these
contracts amounted to $241 million, $232 million and $226 million for 2003,
2002 and 2001, respectively. Minimum expected future capacity payments
under these contracts at December 31, 2003 are $257 million, $269 million,
$280 million, $289 million and $297 million for 2004 through 2008,
respectively, and $4,147 million thereafter. PEC has various
pay-for-performance contracts with QFs for approximately 400 MW of capacity
expiring at various times through 2009. Payments for both capacity and
energy are contingent upon the QFs' ability to generate. Payments made
under these contracts were $118 million in 2003, $145 million in 2002 and
2001.
Construction Obligations
The Company has purchase obligations related to various capital
construction projects. Total payments under these contracts were $202
million, $164 million and $24 million for 2003, 2002 and 2001,
respectively. Future obligations under these contracts are $112 million and
$49 million for 2004 and 2005, respectively.
Other Purchase Obligations
The Company has entered into various other contractual obligations
primarily related to service contracts for operational services entered
into by the PESC, a PVI parts and services contract, and a PEF service
agreement related to the Hines Complex. Payments under these agreements
were $17 million, $15 million and $15 million for 2003, 2002 and 2001,
respectively. Future obligations under these contracts are $28 million, $11
million, $18 million, $11 million and $16 million for 2004 through 2008,
respectively, and $124 million thereafter.
118
On December 31, 2002, PEC and PVI entered into a contractual commitment to
purchase at least $13 million and $4 million, respectively, of capital
parts by December 31, 2010. At December 31, 2003, no capital parts have
been purchased under this contract.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties) of up
to $11 million on synthetic fuel sales from each plant annually through
2007. The related agreements were amended in December 2001 to require the
payment of minimum annual royalties of approximately $7 million for each
plant through 2007. As a result of the amendment, the Company recorded a
liability (included in other liabilities and deferred credits on the
Consolidated Balance Sheets) and a deferred asset (included in other assets
and deferred debits in the Consolidated Balance Sheets), each of
approximately $94 million and $114 million at December 31, 2003 and 2002,
respectively, representing the minimum amounts due through 2008, discounted
at 6.05%. At December 31, 2003 and 2002, the portions of the asset and
liability recorded that were classified as current were approximately $24
million. The deferred asset will be amortized to expense each year as
synthetic fuel sales are made. The maximum amounts payable under these
agreements remain unchanged. Actual amounts paid under these agreements
were approximately $2 million in 2003, $51 million in 2002 and $46 million
in 2001. Future expected minimum royalty payments are approximately $26
million for 2004 through 2007 and $7 million for 2008. The large decline in
amount paid from 2002 to 2003 is due to the Company's right in the related
agreements and their amendments that allow the Company to escrow those
payments if certain conditions in the agreements are met. The Company has
exercised that right and retained 2003 royalty payments of approximately
$48 million pending the establishment of the necessary escrow accounts.
Once established, those funds will be placed into escrow.
C. Leases
The Company leases office buildings, computer equipment, vehicles, railcars
and other property and equipment with various terms and expiration dates.
Some rental payments for transportation equipment include minimum rentals
plus contingent rentals based on mileage. These contingent rentals are not
significant. Rent expense under operating leases totaled $55 million, $57
million and $63 million for 2003, 2002 and 2001, respectively.
Assets recorded under capital leases at December 31 consist of:
(in millions) 2003 2002
----------- -----------
Buildings $ 30 $ 28
Equipment and other 3 3
Less: Accumulated amortization (10) (10)
----------- -----------
$ 23 $ 21
=========== ===========
Equipment and other capital lease assets were written down in conjunction
with the impairments of PTC and Caronet during the third quarter of 2002
(See Note 9A).
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases at
December 31, 2003 are:
(in millions) Capital Leases Operating Leases
-------------- ----------------
2004 $ 4 $ 38
2005 4 33
2006 4 27
2007 4 22
2008 3 19
Thereafter 31 168
--------------
----------------
$ 50 $ 307
================
Less amount representing imputed interest (20)
--------------
Present value of net minimum lease payments
under capital leases $ 30
==============
119
The Company is also a lessor of land, buildings, railcars and other types
of properties it owns under operating leases with various terms and
expiration dates. The leased buildings and railcars are depreciated under
the same terms as other buildings and railcars included in diversified
business property. In 2003, PEC entered into a new operating lease for a
building, which minimum annual rental payments are included in the table
above, and for 2004 through 2008 are approximately $1 million, $4 million,
$4 million, $4 million and $4 million, respectively, with $96 million
thereafter. Minimum rentals receivable under noncancelable leases for 2004
through 2008 are approximately $4 million, $4 million, $7 million, $8
million and $14 million, respectively, with $51 million receivable
thereafter. These rental receivable totals exclude all leases attributable
to Railcar Ltd. which was sold during the first quarter of 2004 (See Note
3B).
PEC and PEF are lessors of electric poles, streetlights and other
facilities. Rents received are contingent upon usage and totaled $87
million, $81 million and $78 million for 2003, 2002 and 2001, respectively.
D. Guarantees
As a part of normal business, Progress Energy and certain subsidiaries
enter into various agreements providing financial or performance assurances
to third parties. Such agreements include guarantees, standby letters of
credit and surety bonds. These agreements are entered into primarily to
support or enhance the creditworthiness otherwise attributed to
subsidiaries on a stand-alone basis, thereby facilitating the extension of
sufficient credit to accomplish the subsidiaries' intended commercial
purposes. At December 31, 2003, management does not believe conditions are
likely for significant performance under the guarantees of performance
issued by or on behalf of affiliates discussed herein.
Guarantees at December 31, 2003, are summarized in the table below and
discussed more fully in the subsequent paragraphs.
(in millions)
Guarantees issued on behalf of affiliates
Guarantees supporting nonregulated portfolio and energy marketing
activities issued by Progress Energy $ 332
Guarantees supporting nuclear decommissioning 276
Guarantee supporting power supply agreements 307
Standby letters of credit 11
Surety bonds 117
Other guarantees 1
Guarantees issued on behalf of third parties
Other guarantees 13
---------
Total $ 1,057
=========
Guarantees Supporting Nonregulated Portfolio and Energy Marketing
Activities
Progress Energy has issued approximately $332 million of guarantees on
behalf of Progress Ventures (the business unit) and its subsidiaries for
obligations under tolling agreements, transmission agreements, gas
agreements, construction agreements, fuel procurement agreements and
trading operations. Approximately $103 million of these guarantees were
issued during the year to support energy marketing activities. The majority
of the marketing contracts supported by the guarantees contain language
regarding downgrade events, ratings triggers, monthly netting of exposure
and/or payments and offset provisions in the event of a default. Based upon
current business levels at December 31, 2003, if the Company's ratings were
to decline below investment grade, the Company estimates that it may have
to deposit cash or provide letters of credit or other cash collateral of
approximately $56 million for the benefit of the Company's counterparties
to support ongoing operations within a 90-day period.
Guarantees Supporting Nuclear Decommissioning
In 2003, PEC determined that its external funding levels did not fully meet
the nuclear decommissioning financial assurance levels required by the NRC.
Therefore, PEC met the financial assurance requirements by obtaining
guarantees from Progress Energy in the amount of $276 million.
120
Guarantees Supporting Power Supply Agreements
On March 20, 2003, PVI entered into a definitive agreement with Williams
Energy Marketing and Trading, a subsidiary of The Williams Companies, Inc.,
to acquire a long-term full-requirements power supply agreement at fixed
prices with Jackson. The power supply agreement included a performance
guarantee by Progress Energy. The transaction closed during the second
quarter of 2003. The Company issued a payment and performance guarantee to
Jackson related to the power supply agreement of $280 million. In the event
that Progress Energy's credit ratings fall below investment grade, Progress
Energy may be required to provide additional security for this guarantee in
form and amount (not to exceed $280 million) acceptable to Jackson. During
the third quarter of 2003, PVI entered into an agreement with Morgan
Stanley Capital Group Inc. to fulfill Morgan Stanley's obligations to
schedule resources and supply energy to Oglethorpe Power Corporation of
Georgia through March 31, 2005. The Company issued a payment and
performance guarantee to Morgan Stanley related to the power supply
agreement. In the event that Progress Energy's credit ratings fall below
investment grade, Progress Energy estimates that it may have to deposit
cash or provide letters of credit or other cash collateral of approximately
$27 million for the benefit of Morgan Stanley at December 31, 2003.
Standby Letters of Credit
The Company has issued $11 million of standby letters of credit to
financial institutions for the benefit of third parties that have extended
credit to the Company and certain subsidiaries. These letters of credit
have been issued primarily for the purpose of supporting payments of trade
payables, securing performance under contracts and lease obligations and
self-insurance for workers' compensation. If a subsidiary does not pay
amounts when due under a covered contract, the counterparty may present its
claim for payment to the financial institution, which will in turn request
payment from the Company. Any amounts owed by the Company's subsidiaries
are reflected in the accompanying Consolidated Balance Sheets.
Surety Bonds
At December 31, 2003, the Company had $117 million in surety bonds
purchased primarily for purposes such as providing workers' compensation
coverage, obtaining licenses, permits, rights-of-way and project
performance. To the extent liabilities are incurred as a result of the
activities covered by the surety bonds, such liabilities are included in
the accompanying Consolidated Balance Sheets.
Other Guarantees
The Company has other guarantees outstanding of approximately $14 million.
Included in the $14 million are $13 million of guarantees issued on behalf
of third parties of which $3 million is related to obligations on leasing
arrangements and $10 million is in support of synthetic fuel operations at
a third-party plant. The Company estimates it will have to perform under
the guarantees related to the leasing agreements and as such $3 million has
been accrued and is reflected in the accompanying Consolidated Balance
Sheets. The remaining $1 million in affiliate guarantees is related
primarily to prompt performance payments, lease obligations and other
payments subject to contingencies.
E. Claims and uncertainties
1. The Company is subject to federal, state and local regulations
addressing hazardous and solid waste management, air and water quality and
other environmental matters.
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
both electric utilities have some connection. In this regard, both electric
utilities and other potentially responsible parties (PRPs) are
participating in, investigating and, if necessary, remediating former MGP
sites with several regulatory agencies, including, but not limited to, the
U.S. Environmental Protection Agency (EPA), the Florida Department of
Environmental Protection (FDEP) and the North Carolina Department of
Environment and Natural Resources, Division of Waste Management (DWM). In
addition, the Company and its subsidiaries are periodically notified by
121
regulators such as the EPA and various state agencies of their involvement
or potential involvement in sites, other than MGP sites, that may require
investigation and/or remediation. A discussion of these sites by legal
entity follows.
PEC There are nine former MGP sites and other sites associated with PEC
that have required or are anticipated to require investigation and/or
remediation costs. PEC received insurance proceeds to address costs
associated with environmental liabilities related to its involvement with
some MGP sites. All eligible expenses related to these are charged against
a specific fund containing these proceeds. At December 31, 2003,
approximately $9 million remains in this centralized fund with a related
accrual of $9 million recorded for the associated expenses of environmental
issues. PEC does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what is currently
accrued due to the fact that investigations have not been completed at all
sites. This accrual has been recorded on an undiscounted basis. PEC
measures its liability for these sites based on available evidence
including its experience in investigating and remediating environmentally
impaired sites. The process often involves assessing and developing
cost-sharing arrangements with other PRPs. PEC will accrue costs for the
sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, PEC cannot determine the total costs that
may be incurred in connection with the remediation of any of these MGP
sites.
In September 2003, the Company sold NCNG to Piedmont Natural Gas Company,
Inc. As part of the sales agreement, the Company retained responsibility to
remediate five former NCNG MGP sites, all of which also are associated with
PEC, to state standards pursuant to an Administrative Order by consent.
These sites are anticipated to have investigation or remediation costs
associated with them. NCNG had previously accrued approximately $2 million
for probable and reasonably estimable remediation costs at these sites.
These accruals have been recorded on an undiscounted basis. At the time of
the sale, the liability for these costs and the related accrual was
transferred to PEC. PEC does not believe it can provide an estimate of the
reasonably possible total remediation costs beyond the accrual because
investigations have not been completed at all sites. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites.
PEF At December 31, 2003, PEF has accrued $18 million for probable and
estimable costs related to various environmental sites. Of this accrual,
$12 million is for costs associated with the remediation of distribution
transformers which are more fully discussed below. The remaining $6 million
is related to two former MGP sites and other sites associated with PEF that
have required or are anticipated to require investigation and/or
remediation costs. PEF does not believe that it can provide an estimate of
the reasonably possible total remediation costs beyond what is currently
accrued.
In 2002, PEF accrued approximately $3 million for investigation and
remediation associated with distribution transformers and received approval
from the FPSC for annual recovery of these environmental costs through the
Environmental Cost Recovery Clause (ECRC). In September 2003, PEF accrued
an additional $15 million for similar environmental costs as a result of
increased sites and estimated costs per site. PEF plans to seek approval
from the FPSC to recover these costs through the ECRC. As more activity
occurs at these sites, PEF will assess the need to adjust the accruals.
These accruals have been recorded on an undiscounted basis. PEF measures
its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often includes assessing and developing cost-sharing
arrangements with other PRPs. Presently, PEF cannot determine the total
costs that may be incurred in connection with the remediation of all sites.
Florida Progress Corporation In 2001, FPC sold its Inland Marine
Transportation business operated by MEMCO Barge Line, Inc. to AEP
Resources, Inc. FPC established an accrual to address indemnities and
retained an environmental liability associated with the transaction. FPC
estimates that its contractual liability to AEP Resources, Inc., associated
with Inland Marine Transportation, is $4 million at December 31, 2003 and
has accrued such amount. The previous accrual of $10 million was reduced in
2003 based on a change in estimate. This accrual has been determined on an
undiscounted basis. FPC measures its liability for this site based on
estimable and probable remediation scenarios. The Company believes that it
is not reasonably probable that additional costs, which cannot be currently
estimated, will be incurred related to the environmental indemnification
provision beyond the amount accrued. The Company cannot predict the outcome
of this matter.
122
PEC, PEF and Fuels have filed claims with the Company's general liability
insurance carriers to recover costs arising out of actual or potential
environmental liabilities. Some claims have been settled and others are
still pending. While the Company cannot predict the outcome of these
matters, the outcome is not expected to have a material effect on the
consolidated financial position or results of operations.
The Company is also currently in the process of assessing potential costs
and exposures at other environmentally impaired sites. As the assessments
are developed and analyzed, the Company will accrue costs for the sites to
the extent the costs are probable and can be reasonably estimated.
Certain historical sites exist that are being addressed voluntarily by PVI
and FPC. An immaterial accrual has been established to address
investigation expenses related to these sites. The Company cannot determine
the total costs that may be incurred in connection with these sites.
According to current information, these future costs are not expected to be
material to the Company's financial condition or results of operations.
Rail Services is voluntarily addressing certain historical waste sites. An
immaterial accrual has been established to address estimable costs. The
Company cannot determine the total costs that may be incurred in connection
with these sites. According to current information, these future costs are
not expected to be material to the Company's financial condition or results
of operations.
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some
of these proposals establish nationwide caps and emission rates over an
extended period of time. This national multi-pollutant approach to air
pollution control could involve significant capital costs which could be
material to the Company's consolidated financial position or results of
operations. Some companies may seek recovery of the related cost through
rate adjustments or similar mechanisms. Control equipment that will be
installed on North Carolina fossil generating facilities as part of the
North Carolina legislation discussed below may address some of the issues
outlined above. However, the Company cannot predict the outcome of this
matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
Both PEC and PEF were asked to provide information to the EPA as part of
this initiative and cooperated in providing the requested information. The
EPA initiated civil enforcement actions against other unaffiliated
utilities as part of this initiative. Some of these actions resulted in
settlement agreements calling for expenditures by these unaffiliated
utilities, ranging from $1.0 billion to $1.4 billion. A utility that was
not subject to a civil enforcement action settled its New Source Review
issues with the EPA for $300 million. These settlement agreements have
generally called for expenditures to be made over extended time periods,
and some of the companies may seek recovery of the related cost through
rate adjustments or similar mechanisms. The Company cannot predict the
outcome of this matter.
In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
addressing the regional transport of ozone (NOx SIP Call). The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, but not Florida, to further reduce NOx emissions in order to
attain preset state NOx emission levels by May 31, 2004. PEC is currently
installing controls necessary to comply with the rule. Capital expenditures
to meet these measures in North and South Carolina could reach
approximately $370 million, which has not been adjusted for inflation. The
Company has spent approximately $258 million to date related to these
expenditures. Increased operation and maintenance costs relating to the NOx
SIP Call are not expected to be material to the Company's results of
operations. Further controls are anticipated as electricity demand
increases. The Company cannot predict the outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new 8-hour
ozone standard. In October 1999, the District of Columbia Circuit Court of
Appeals ruled against the EPA with regard to the federal 8-hour ozone
standard. The U.S. Supreme Court has upheld, in part, the District of
Columbia Circuit Court of Appeals' decision. Designation of areas that do
not attain the standard is proceeding, and further litigation and
rulemaking on this and other aspects of the standard are anticipated. North
Carolina adopted the federal 8-hour ozone standard and is proceeding with
the implementation process. North Carolina has promulgated final
regulations, which will require PEC to install NOx controls under the
state's 8-hour standard. The costs of those controls are included in the
$370 million cost estimate above. However, further technical analysis and
rulemaking may result in a requirement for additional controls at some
units. The Company cannot predict the outcome of this matter.
123
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule, as originally promulgated, required certain
sources to make reductions in NOx emissions by May 1, 2003. The final rule
also includes a set of regulations that affect NOx emissions from sources
included in the petitions. The North Carolina coal-fired electric
generating plants are included in these petitions. Acceptable state plans
under the NOx SIP Call can be approved in lieu of the final rules the EPA
approved as part of the Section 126 petitions. In April 2002, the EPA
published a final rule harmonizing the dates for the Section 126 rule and
the NOx SIP Call. The new compliance date for all affected sources is now
May 31, 2004, rather than May 1, 2003. The EPA has approved North
Carolina's NOx SIP Call rule and has indicated it will rescind the Section
126 rule in a future rulemaking. The Company expects a favorable outcome of
this matter.
In June 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from
coal-fired power plants. Progress Energy expects its capital costs to meet
these emission targets will be approximately $813 million by 2013. PEC has
expended approximately $30 million of these capital costs through December
31, 2003. PEC currently has approximately 5,100 MW of coal-fired generation
capacity in North Carolina that is affected by this legislation. The
legislation requires the emissions reductions to be completed in phases by
2013, and applies to each utility's total system rather than setting
requirements for individual power plants. The legislation also freezes the
utilities' base rates for five years unless there are extraordinary events
beyond the control of the utilities or unless the utilities persistently
earn a return substantially in excess of the rate of return established and
found reasonable by the NCUC in the utilities' last general rate case.
Further, the legislation allows the utilities to recover from their retail
customers the projected capital costs during the first 7 years of the
ten-year compliance period beginning on January 1, 2003. The utilities must
recover at least 70% of their projected capital costs during the 5-year
rate freeze period. PEC has recognized $74 million in 2003. Pursuant to the
law, PEC entered into an agreement with the state of North Carolina to
transfer to the state all future emissions allowances it generates from
overcomplying with the federal emission limits when these units are
completed. The law also requires the state to undertake a study of mercury
and carbon dioxide emissions in North Carolina. Operation and maintenance
costs will increase due to the additional personnel, materials and general
maintenance associated with the equipment. Operation and maintenance
expenses are recoverable through base rates, rather than as part of this
program. Progress Energy cannot predict the future regulatory
interpretation, implementation or impact of this law.
In 2004, a bill was introduced in the Florida legislature that would
require significant reductions in NOx, SO2 and particulate emissions from
certain coal, natural gas and oil-fired generating units owned or operated
by investor-owned electric utilities, including PEF. The NOx and SO2
reductions would be effective beginning with calendar year 2010 and the
particulate reductions would be effective beginning with calendar year
2012. Under the proposed legislation, the FPSC would be authorized to allow
the utilities to recover the costs of compliance with the emission
reductions over a period not greater than seven years beginning in 2005,
but the utilities' rates may be frozen at 2004 levels for at least five
years of the maximum recovery period. The Company cannot predict the
outcome of this matter.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, the EPA determined
in 2000 that regulation of mercury emissions from coal-fired power plants
was appropriate. In 2003, the EPA proposed two alternative control plans
that would limit mercury emissions from coal-fired power plants. The first,
a Maximum Achievable Control Technology (MACT) standard applicable to every
coal-fired plant, would require compliance in 2008. The second, a national
mercury cap and trade program, would require limits to be met in two
phases, 2010 and 2018. The mercury rule is expected to become final in
December 2004. Achieving compliance with either proposal could involve
significant capital costs which could be material to the Company's
consolidated financial position or results of operations. The Company
cannot predict the outcome of this matter.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
agency estimates the proposal will reduce national nickel emissions to
approximately 103 tons. The rule is expected to become final in December
2004.
In December 2003, the EPA released its proposed Interstate Air Quality Rule
(commonly known as the Fine Particulate Transport Rule and/or the Regional
Transport Rule). The EPA's proposal requires 28 jurisdictions, including
North Carolina, South Carolina, Georgia and Florida, to further reduce NOx
and SO2 emissions in order to attain preset state NOx and SO2 emissions
levels (which have not yet been determined). The rule is expected to become
final in 2004. The installation of controls necessary to comply with the
rule could involve significant capital costs.
124
Water Quality
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams will be
generated at the applicable facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and treatment challenges to PEC in the immediate
and extended future.
After many years of litigation and settlement negotiations the EPA
published regulations in February 2004 for the implementation of Section
316(b) of the Clean Water Act. The purpose of these regulations is to
minimize adverse environmental impacts caused by cooling water intake
structures and intake systems. Over the next several years these
regulations will impact the larger base load generation facilities and may
require the facilities to mitigate the effects to aquatic organisms by
constructing intake modifications or undertaking other restorative
activities. Substantial costs could be incurred by the facilities in order
to comply with the new regulation. The Company cannot predict the outcome
and impacts to the facilities at this time.
The EPA has published for comment a draft Environmental Impact Statement
(EIS) for surface coal mining (sometimes referred to as "mountaintop
mining") and valley fills in the Appalachian coal region, where Progress
Fuels currently operates a surface mine and may operate others in the
future. The final EIS, when published, may affect regulations for the
permitting of mines and the cost of compliance with environmental
regulations. Regulatory changes for mining may also affect the cost of fuel
for the PEC and PEF coal-fueled electric-generating plants. The Company
cannot predict the outcome of this matter.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol;
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to the Company's
consolidated financial position or results of operations if associated
costs cannot be recovered from customers. The Company favors the voluntary
program approach recommended by the administration and is evaluating
options for the reduction, avoidance and sequestration of greenhouse gases.
However, the Company cannot predict the outcome of this matter.
2. As required under the Nuclear Waste Policy Act of 1982, PEC and PEF each
entered into a contract with the DOE under which the DOE agreed to begin
taking spent nuclear fuel by no later than January 31, 1998. All similarly
situated utilities were required to sign the same standard contract.
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that their delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals found
that the delay was not unavoidable, but did not order the DOE to begin
taking spent nuclear fuel, stating that the utilities had a potentially
adequate remedy by filing a claim for damages under the contract.
125
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) ruled that utilities may sue the DOE for damages in the Federal
Court of Claims instead of having to file an administrative claim with the
DOE.
On January 14, 2004, PEC and PEF filed a complaint with the United States
Court of Federal Claims against the DOE claiming that the DOE breached the
Standard Contract for Disposal of Spent Nuclear Fuel by failing to accept
spent nuclear fuel from various Progress Energy facilities on or before
January 31, 1998. Damages due to DOE's breach will likely exceed $100
million. Similar suits have been initiated by over two dozen other
utilities.
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. On November
5, 2003, Congressional negotiators approved $580 million for fiscal year
2004 for the Yucca Mountain project, $123 million more than the previous
year. PEC and PEF cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC including the
installation of onsite dry storage facilities at Robinson (2005) and
Brunswick (2008), PEC's spent nuclear fuel storage facilities will be
sufficient to provide storage space for spent fuel generated on PEC's
system through the expiration of the current operating licenses for all of
PEC's nuclear generating units. PEF currently is storing spent nuclear fuel
onsite in spent fuel pools. PEF is seeking renewal of the current CR3
operating license. CR3 has sufficient storage capacity in place for fuel
consumed through the end of the expiration of the current license in 2016.
If PEF receives approval on its CR3 operating license renewal, additional
dry storage may be necessary.
3. In November of 2001, Strategic Resource Solutions Corp. (SRS) filed a
claim against the San Francisco Unified School District (the District) and
other defendants claiming that SRS is entitled to approximately $10 million
in unpaid contract payments and delay and impact damages related to the
District's $30 million contract with SRS. On March 4, 2002, the District
filed a counterclaim, seeking compensatory damages and liquidated damages
in excess of $120 million, for various claims, including breach of contract
and demand on a performance bond. SRS has asserted defenses to the
District's claims. SRS has amended its claims and asserted new claims
against the District and other parties, including a former SRS employee and
a former District employee.
On March 13, 2003, the City Attorney and the District filed new claims in
the form of a cross-complaint against SRS, Progress Energy, Inc., Progress
Energy Solutions, Inc., and certain individuals, alleging fraud, false
claims, violations of California statutes, and seeking compensatory
damages, punitive damages, liquidated damages, treble damages, penalties,
attorneys' fees and injunctive relief. The filing states that the City and
the District seek "more than $300 million in damages and penalties." PEC
was added as a cross-defendant later in 2003.
The Company, SRS, Progress Energy Solutions, Inc. and PEC all have denied
the District's allegations and cross-claims. Discovery is in progress in
the matter. The case has been assigned to a judge under the Sacramento
County superior court's case management rules, and the judge and the
parties have been conferring on scheduling and processes to narrow or
resolve issues, if possible, and to get the case ready for trial. No trial
date has been set. SRS and the Company are vigorously defending and
litigating all of these claims. In November 2003, PEC filed a motion to
dismiss the plaintiffs' first amended complaint. The Company cannot predict
the outcome of this matter, but will vigorously defend against the
allegations.
126
4. On August 21, 2003, PEC was served as a co-defendant in a purported
class action lawsuit styled as Collins v. Duke Energy Corporation et al,
Civil Action No. 03CP404050, in South Carolina's Circuit Court of Common
Pleas for the Fifth Judicial Circuit. PEC is one of three electric
utilities operating in South Carolina named in the suit. The plaintiffs are
seeking damages for the alleged improper use of electric easements but have
not asserted a dollar amount for their damage claims. The complaint alleges
that the licensing of attachments on electric utility poles, towers and
other structures to nonutility third parties or telecommunication companies
for other than the electric utilities' internal use along the electric
right-of-way constitutes a trespass.
On September 19, 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. On October 6, 2003, the
plaintiffs filed a motion to amend their complaint. PEC believes the
amended complaint asserts the same factual allegations as are in the
original complaint and also seeks money damages and injunctive relief. The
court has not yet held any hearings or made any rulings in this case. PEC
cannot predict the outcome of this matter, but vigorously defend against
the allegations.
5. The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve
substantial amounts. Where appropriate, accruals have been made in
accordance with SFAS No. 5, "Accounting for Contingencies" (SFAS No. 5), to
provide for such matters. In the opinion of management, the final
disposition of pending litigation would not have a material adverse effect
on the Company's consolidated results of operations or financial position.
127
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:
We have audited the accompanying consolidated balance sheets of Carolina Power &
Light Company d/b/a Progress Energy Carolinas, Inc. and its subsidiaries (PEC)
at December 31, 2003 and 2002, and the related consolidated statements of income
and comprehensive income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 2003. These financial statements
are the responsibility of PEC's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of PEC at December 31, 2003 and 2002,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Notes 3F and 12A to the consolidated financial statements, in
2003, the Company adopted Statement of Financial Accounting Standards No. 143
and Derivative Implementation Group Issue C20.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004
128
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of INCOME and COMPREHENSIVE INCOME
Years ended December 31
(In millions) 2003 2002 2001
- --------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 3,589 $ 3,539 $ 3,344
Diversified business 11 15 16
- --------------------------------------------------------------------------------------------------
Total Operating Revenues 3,600 3,554 3,360
- --------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 825 752 638
Purchased power 296 347 354
Operation and maintenance 782 802 711
Depreciation and amortization 562 524 522
Taxes other than on income 162 158 150
Diversified business 4 15 10
Impairment of diversified business long-lived assets - 101 -
- --------------------------------------------------------------------------------------------------
Total Operating Expenses 2,631 2,699 2,385
- --------------------------------------------------------------------------------------------------
Operating Income 969 855 975
- --------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 6 7 14
Impairment of investments (21) (25) (157)
Other, net (11) 13 (4)
- --------------------------------------------------------------------------------------------------
Total Other Expense (26) (5) (147)
- --------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 196 217 257
Allowance for borrowed funds used during construction (2) (5) (16)
- --------------------------------------------------------------------------------------------------
Total Interest Charges, Net 194 212 241
- --------------------------------------------------------------------------------------------------
Income before Income Tax and Cumulative Effect of Change in
Accounting Principles 749 638 587
Income Tax Expense 244 207 223
- --------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Change in Accounting 505 431 364
Principles
Cumulative Effect of Change in Accounting Principles, Net of Tax (23) - -
- --------------------------------------------------------------------------------------------------
Net Income 482 431 364
Preferred Stock Dividend Requirement 3 3 3
- --------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 479 $ 428 $ 361
- --------------------------------------------------------------------------------------------------
Comprehensive Income, Net of Tax:
Net Income $ 482 $ 431 $ 364
SFAS No. 133 transition adjustment (net of tax) - - (1)
Change in net unrealized losses on cash flow hedges (net of
tax of ($1), $9 and $8, respectively) 3 (14) (12)
Reclassification adjustment for amounts included in net
income (net of tax of $0, $8 and $4, respectively) 1 11 6
Minimum pension liability adjustment (net of tax of $(47)
and $47, respectively) 72 (73) -
- --------------------------------------------------------------------------------------------------
Comprehensive Income $ 558 $ 355 $ 357
- --------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
129
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED BALANCE SHEETS
(In millions) December 31
ASSETS 2003 2002
- --------------------------------------------------------------------------------------------------
Utility Plant
Utility plant in service $ 13,331 $ 12,680
Accumulated depreciation (5,280) (4,869)
- --------------------------------------------------------------------------------------------------
Utility plant in service, net 8,051 7,811
Held for future use 5 7
Construction work in progress 306 326
Nuclear fuel, net of amortization 159 177
- --------------------------------------------------------------------------------------------------
Total Utility Plant, Net 8,521 8,321
- --------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 238 18
Accounts receivable 265 301
Unbilled accounts receivable 145 151
Receivables from affiliated companies 27 37
Notes receivable from affiliated companies - 50
Taxes receivable 19 55
Inventory 348 343
Deferred fuel cost 113 146
Prepayments and other current assets 63 45
- --------------------------------------------------------------------------------------------------
Total Current Assets 1,218 1,146
- --------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 477 206
Nuclear decommissioning trust funds 505 423
Miscellaneous other property and investments 169 219
Other assets and deferred debits 118 90
- --------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,269 938
- --------------------------------------------------------------------------------------------------
Total Assets $ 11,008 $ 10,405
- --------------------------------------------------------------------------------------------------
Capitalization and Liabilities
- --------------------------------------------------------------------------------------------------
Common Stock Equity
- --------------------------------------------------------------------------------------------------
Common stock without par value, authorized 200 million shares,
160 million shares issued and outstanding at December 31 $ 1,953 $ 1,930
Unearned ESOP common stock (89) (102)
Accumulated other comprehensive loss (7) (83)
Retained earnings 1,380 1,344
- --------------------------------------------------------------------------------------------------
Total Common Stock Equity 3,237 3,089
Preferred Stock - Not Subject to Mandatory Redemption 59 59
Long-Term Debt 3,086 3,048
- --------------------------------------------------------------------------------------------------
Total Capitalization 6,382 6,196
- --------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 300 -
Accounts payable 188 258
Payables to affiliated companies 136 99
Notes payable to affiliated companies 25 -
Interest accrued 64 59
Short-term obligations 4 438
Current portion of accumulated deferred income taxes - 66
Other current liabilities 166 92
- --------------------------------------------------------------------------------------------------
Total Current Liabilities 883 1,012
- --------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 1,125 1,105
Accumulated deferred investment tax credits 148 159
Regulatory liabilities 1,175 8
Cost of removal - 1,488
Asset retirement obligations 932 -
Other liabilities and deferred credits 363 437
- --------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,743 3,197
- --------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 16)
- --------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 11,008 $ 10,405
- --------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
130
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
Years ended December 31
(In millions) 2003 2002 2001
- -------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 482 $ 431 $ 364
Adjustments to reconcile net income to net cash provided by operating
activities:
Impairment of long-lived assets and investments 21 126 157
Depreciation and amortization 660 631 616
Cumulative effect of change in accounting principles 23 - -
Deferred income taxes (68) (82) (150)
Investment tax credit (10) (12) (15)
Deferred fuel cost (credit) 33 (15) (12)
Cash provided (used) by changes in operating assets and liabilities:
Accounts receivable 41 (21) 304
Inventories 4 10 (140)
Prepayments and other current assets 21 (15) 22
Accounts payable (32) 20 (261)
Other current liabilities 56 (2) 53
Other 27 32 47
- -------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,258 1,103 985
- -------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (470) (624) (824)
Proceeds from sale of assets and investments 26 244 -
Diversified business property additions and acquisitions (1) (12) (13)
Nuclear fuel additions (66) (81) (73)
Net contributions to nuclear decommissioning trust (31) (31) (31)
Other investing activities 1 (17) (32)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (541) (521) (973)
- -------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt 588 542 296
Net increase (decrease) in short-term obligations (437) 177 (226)
Net change in intercompany notes 74 (97) 188
Retirement of long-term debt (276) (807) (135)
Equity contribution from parent - - 115
Dividends paid to parent (443) (397) (256)
Dividends paid on preferred stock (3) (3) (3)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (497) (585) (21)
- -------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 220 (3) (9)
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 18 21 30
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 238 $ 18 $ 21
- -------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 184 $ 208 $ 230
income taxes (net of refunds) $ 296 $ 319 $ 395
Noncash Investing and Financing Activities
o In January 2001, PEC transferred certain assets, through a noncash dividend
to Progress Energy in the amount of $18 million, to Progress Energy Service
Company, LLC.
See Notes to Consolidated Financial Statements.
131
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
Years ended December 31
(In millions) 2003 2002 2001
- ----------------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year $ 1,344 $ 1,313 $ 1,226
Net income 482 431 364
Preferred stock dividends at stated rates (3) (3) (3)
Common stock dividends (443) (397) (274)
- ----------------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,380 $ 1,344 $ 1,313
- ----------------------------------------------------------------------------------------------
CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
(In millions) First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 929 $ 819 $ 1,012 $840
Operating income 256 184 294 235
Income before cumulative effect of
change in accounting principles 135 89 158 123
Net income 135 89 158 100
- -----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2002
Operating revenues $ 815 $ 838 $ 1,049 $ 852
Operating income 193 210 240 212
Net income 85 131 94 121
o In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
o Fourth quarter 2003 includes impairment of investments of $21 million ($13
million after-tax) (See Note 6).
o Fourth quarter 2003 includes a cumulative effect for DIG Issue C20 of $38
million ($23 million after-tax) (See Note 12).
o Third quarter 2002 includes impairment and other charges related to Caronet
and Interpath Communications, Inc. of $133 million ($87 million, after-tax)
(See Note 6).
See Notes to Consolidated Financial Statements.
132
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina and South Carolina. Effective
January 1, 2003, CP&L began doing business under the assumed name Progress
Energy Carolinas, Inc (PEC). The legal name has not changed and there is no
restructuring of any kind related to the name change. Through its
wholly-owned subsidiaries, PEC is involved in several nonregulated business
activities, the most significant of which was its telecommunications
operation. PEC is a wholly-owned subsidiary of Progress Energy, Inc. (the
Company or Progress Energy). The Company is a registered holding company
under the Public Utility Holding Company Act of 1935 (PUHCA). Both the
Company and its subsidiaries are subject to the regulatory provisions of
PUHCA.
In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, Inc. (Caronet), both indirectly wholly-owned subsidiaries of
Progress Energy, and EPIK Communications, Inc. (EPIK), a wholly-owned
subsidiary of Odyssey Telecorp, Inc. (Odyssey), contributed substantially
all of their assets and transferred certain liabilities to Progress
Telecom, LLC (PTC LLC), a subsidiary of PTC. Subsequently, the stock of
Caronet was sold to an affiliate of Odyssey for $2 million in cash and
Caronet became an indirect wholly-owned subsidiary of Odyssey. No gain or
loss was recognized on this transaction.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of PEC and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable
and the future recovery of the sales price through the ratemaking process
is probable.
Unconsolidated investments in companies over which PEC does not have
control, but has the ability to exercise influence over operating and
financial policies (generally, 20% - 50% ownership), are accounted for
under the equity method of accounting. Certain investments in debt and
equity securities that have readily determinable market values, and for
which PEC does not have control, are accounted for at fair value in
accordance with SFAS No. 115 "Accounting for Certain Investments in Debt
and Equity Securities." Other investments are stated principally at cost.
These equity and cost investments, which total approximately $35 million
and $95 million at December 31, 2003 and 2002, respectively, are included
as miscellaneous property and investments in the Consolidated Balance
Sheets. The primary component of this balance is PEC's investments in
affordable housing of $21 million and $63 million at December 31, 2003 and
2002, respectively. This decrease is primarily due to the sale of certain
PEC investments in the third quarter of 2003. For a discussion of how new
FASB interpretations will affect these affordable housing investments see
Note 2.
Certain amounts for 2002 and 2001 have been reclassified to conform to the
2003 presentation.
C. Significant Accounting Policies
Use of Estimates and Assumptions
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
amounts of revenues and expenses reflected during the reporting period.
Actual results could differ from those estimates.
133
Revenue Recognition
PEC recognizes electric utility revenue as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Revenues related to Caronet for the design and
construction of wireless infrastructure were recognized upon completion of
services for each completed phase of design and construction.
Fuel Cost Deferrals
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by PEC's regulators. These clauses allow PEC to
recover fuel costs and portions of purchased power costs through surcharges
on customer rates.
Excise Taxes
PEC collects from customers certain excise taxes levied by the state or
local government upon the customer. PEC accounts for excise taxes on a
gross basis. For the years ended December 31, 2003, 2002 and 2001, gross
receipts tax and other excise taxes of approximately $81 million, $79
million and $77 million, respectively, are included in taxes other than on
income on the Consolidated Statements of Income and Comprehensive Income.
These approximate amounts also are included in electric operating revenues.
Income Taxes
Progress Energy and its affiliates file a consolidated federal income tax
return. The consolidated income tax of Progress Energy is allocated to PEC
in accordance with the Inter-company Income Tax Allocation Agreement (Tax
Agreement). The Tax Agreement provides an allocation that recognizes
positive and negative corporate taxable income. The Tax Agreement provides
for an equitable method of apportioning the carry over of uncompensated tax
benefits. Progress Energy tax benefits not related to acquisition interest
expense are allocated to profitable subsidiaries, beginning in 2002, in
accordance with a PUHCA order. Income taxes are provided as if PEC filed a
separate return.
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between the book and tax carrying amounts
of assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties (See Note 10).
Stock-Based Compensation
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. The exercise price at which options
are granted by the Company equals the market price at the grant date, and
accordingly no compensation expense has been recognized for stock option
grants. For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - an
Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair
value of the Company's stock options is amortized to expense over the
options' vesting period. The following table illustrates the effect on net
income if the fair value method had been applied to all outstanding and
unvested awards in each period.
(in millions) 2003 2002 2001
-------- -------- ---------
Net income, as reported $ 482 $ 431 $ 364
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 6 5 1
-------- -------- ---------
Pro forma net income $ 476 $ 426 $ 363
======== ======== =========
Utility Plant
Utility plant in service is stated at historical cost less accumulated
depreciation. PEC capitalizes all construction-related direct labor and
material costs of units of property as well as indirect construction costs.
The cost of renewals and betterments is also capitalized. Maintenance and
repairs of property, and replacements and renewals of items determined to
be less than units of property, are charged to maintenance expense as
incurred. The cost of units of property replaced or retired, less salvage,
is charged to accumulated depreciation. Removal or disposal costs were
charged to regulatory liabilities in 2003 and cost of removal in 2002. PEC
follows the guidance in SFAS No. 143, "Accounting for Asset Retirement
Obligations," to account for legal obligations associated with the
retirement of certain tangible long-lived assets.
134
Depreciation and Amortization - Utility Plant
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated salvage (See Note 3A). The North Carolina Utilities Commission
(NCUC) and the Public Service Commission of South Carolina (SCPSC) can also
grant approval to accelerate or reduce depreciation and amortization of
utility assets (See Note 5B).
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE) and costs
associated with obligations to the DOE for the decommissioning and
decontamination of enrichment facilities, is computed primarily on the
units-of-production method and charged to fuel used in electric generation
in the accompanying Consolidated Statements of Income and Comprehensive
Income. In PEC's retail jurisdictions, provisions for nuclear
decommissioning costs are approved by the NCUC and the SCPSC and are based
on site-specific estimates that include the costs for removal of all
radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by the Federal Energy Regulatory Commission (FERC).
Cash and Cash Equivalents
PEC considers cash and cash equivalents to include unrestricted cash on
hand, cash in banks and temporary investments purchased with a maturity of
three months or less.
Allowance for Doubtful Accounts
PEC maintains an allowance for doubtful accounts receivable, which totaled
approximately $13 million and $11 million at December 31, 2003 and 2002,
respectively, and is included in accounts receivable on the Consolidated
Balance Sheets.
Inventory
PEC accounts for inventory using the average-cost method.
Regulatory Assets and Liabilities
PEC's regulated operations are subject to SFAS No. 71, which allows a
regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, PEC records assets and liabilities that result from the
regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the accompanying
Consolidated Balance Sheets as regulatory assets and regulatory liabilities
(See Note 5A).
Diversified Business Property
Diversified business property is stated at cost less accumulated
depreciation. If an impairment loss is recognized on an asset, the fair
value becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis using the
estimated useful lives disclosed in Note 3B.
Unamortized Debt Premiums, Discounts and Expenses
Long-term debt premiums, discounts and issuance expenses for the utility
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utility are amortized over the remaining life of
the original debt using the straight-line method consistent with ratemaking
treatment.
Derivatives
Effective January 1, 2001, PEC adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended
by SFAS No. 138 and SFAS No. 149. SFAS No. 133, as amended, establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. SFAS No. 133 requires that an entity recognize all derivatives
as assets or liabilities in the balance sheet and measure those instruments
at fair value. During 2003, the FASB reconsidered an interpretation of SFAS
No. 133. See Note 12 for the effect of the interpretation and additional
information regarding risk management activities and derivative
transactions.
135
Environmental
The Company accrues environmental remediation liabilities when the criteria
for SFAS No. 5, "Accounting for Contingencies," has been met. Environmental
expenditures are expensed as incurred or capitalized depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are
expensed. Accruals for estimated losses from environmental remediation
obligations generally are recognized no later than completion of the
remedial feasibility study. Such accruals are adjusted as additional
information develops or circumstances change. Costs of future expenditures
for environmental remediation obligations are not discounted to their
present value. Recoveries of environmental remediation costs from other
parties are recognized when their receipt is deemed probable (See Note
16D).
Impairment of Long-lived Assets and Investments
The Company reviews the recoverability of long-lived tangible and
intangible assets whenever indicators exist. Examples of these indicators
include current period losses, combined with a history of losses or a
projection of continuing losses, or a significant decrease in the market
price of a long-lived asset group. If an indicator exists, then the asset
group is tested for recoverability by comparing the carrying value to the
sum of undiscounted expected future cash flows directly attributable to the
asset group. If the asset group is not recoverable through undiscounted
cash flows, then an impairment loss is recognized for the difference
between the carrying value and the fair value of the asset group. The
accounting for impairment of long-lived assets is based on SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," which was
adopted by the Company effective January 1, 2002. Prior to the adoption of
this standard, impairments were accounted for under SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" (SFAS No. 121), which was superceded by SFAS No.
144.
PEC reviews its investments to evaluate whether or not a decline in fair
value below the carrying value is an other-than-temporary decline. PEC
considers various factors, such as the investee's cash position, earnings
and revenue outlook, liquidity and management's ability to raise capital in
determining whether the decline is other-than-temporary. If PEC determines
that an other-than-temporary decline exists in the value of its
investments, it is PEC's policy to write-down these investments to fair
value. See Note 6 for a discussion of impairment evaluations performed and
charges taken.
Subsidiary Stock Transactions
Gains and losses realized as a result of common stock sales by PEC's
subsidiaries are recorded in the Consolidated Statements of Income and
Comprehensive Income, except for any transactions that must be credited
directly to equity in accordance with the provisions of SAB No. 51,
"Accounting for Sales of Stock by a Subsidiary."
2. New Accounting Standards
SFAS No. 150, "Accounting for Certain Financial Instruments with
Characteristics of Both Liabilities and Equity"
In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS
No. 150, "Accounting for Certain Financial Instruments with Characteristics
of Both Liabilities and Equity." The adoption of SFAS No. 150 did not have
an impact on PEC's financial position or results of operations.
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans"
In May 2003, the Emerging Issues Task Force (EITF) reached consensus in
EITF Issue No. 03-04, "Accounting for `Cash Balance' Pension Plans" (EITF
03-04), to specifically address the accounting for certain cash balance
pension plans. The consensus reached in EITF 03-04 requires certain cash
balance pension plans to be accounted for as defined benefit plans. For
cash balance plans described in EITF 03-04, the consensus also requires the
use of the traditional unit credit method for purposes of measuring the
benefit obligation and annual cost of benefits earned as opposed to the
projected unit credit method. PEC has historically accounted for its cash
balance plan as a defined benefit plan; however, PEC was required to adopt
the measurement provisions of EITF 03-04 at its cash balance plan's
measurement date of December 31, 2003. Any differences in the measurement
of the obligations as a result of applying EITF 03-04 were reported as a
component of actuarial gain or loss. The on-going effects of this standard
are dependent on other factors that also affect the determination of
actuarial gains and losses and the subsequent amortization of such gains
and losses. However, the adoption of EITF 03-04 is not expected to have a
material effect on PEC's results of operations or financial position.
136
SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities"
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." The statement amends and
clarifies SFAS No. 133 on accounting for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. The new guidance incorporates decisions made as part of the
Derivatives Implementation Group (DIG) process, as well as decisions
regarding implementation issues raised in relation to the application of
the definition of a derivative. SFAS No. 149 is generally effective for
contracts entered into or modified after June 30, 2003. Interpretations and
implementation issues with regard to SFAS No. 149 continue to evolve. The
statement had no significant impact on PEC's accounting for contracts
entered into subsequent to the statement's effective date (See Note 12).
Future effects, if any, on PEC's results of operations and financial
condition will be dependent on the specifics of future contracts entered
into with regard to guidance provided by the statement. In connection with
the January 2003 FASB EITF meeting, the FASB was requested to reconsider an
interpretation of SFAS No. 133 (See Note 12).
FIN No. 46, "Consolidation of Variable Interest Entities"
In January 2003, the FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities - an Interpretation of ARB No. 51" (FIN No. 46).
This interpretation provides guidance related to identifying variable
interest entities and determining whether such entities should be
consolidated. FIN No. 46 requires an enterprise to consolidate a variable
interest entity when the enterprise (a) absorbs a majority of the variable
interest entity's expected losses, (b) receives a majority of the entity's
expected residual returns, or both, as a result of ownership, contractual
or other financial interests in the entity. Prior to the effective date of
FIN No. 46, entities were generally consolidated by an enterprise that had
control through ownership of a majority voting interest in the entity. FIN
No. 46 originally applied immediately to variable interest entities created
or obtained after January 31, 2003. During 2003, PEC did not participate in
the creation of, or obtain a new variable interest in, any variable
interest entity. In December 2003, the FASB issued a revision to FIN No. 46
(FIN No. 46R), which modified certain requirements of FIN No. 46 and
allowed for the optional deferral of the effective date of FIN No. 46R
until March 31, 2004. However, entities subject to FIN No. 46 or FIN No.
46R that are deemed to be special-purpose entities (as defined in FIN No.
46R) must implement either FIN No. 46 or FIN No. 46R at December 31, 2003.
PEC elected to apply FIN No. 46 to special purpose entities as of December
31, 2003. Because PEC expects additional transitional guidance to be
issued, it has elected to apply FIN No. 46R to non-special-purpose entities
as of March 31, 2004.
PEC has investments in 14 limited partnerships accounted for under the
equity method for which it may be the primary beneficiary. These
partnerships invest in and operate low-income housing and historical
renovation properties that qualify for federal and state tax credits. PEC
has not concluded whether it is the primary beneficiary of these
partnerships. These partnerships are partially funded with financing from
third party lenders, which is secured by the assets of the partnerships.
The creditors of the partnerships do not have recourse to PEC. At December
31, 2003, the maximum exposure to loss as a result of PEC's investments in
these limited partnerships is approximately $9 million. PEC expects to
complete its evaluation of these partnerships under FIN No. 46R during the
first quarter of 2004. If PEC had consolidated these 14 entities at
December 31, 2003, it would have recorded an increase to both total assets
and total liabilities of approximately $40 million.
PEC also has interests in several other variable interest entities created
before January 31, 2003, for which it is not the primary beneficiary. These
arrangements include equity investments in approximately 14 limited
partnerships, limited liability corporations and venture capital funds, and
two building leases with special-purpose entities. The aggregate maximum
loss exposure at December 31, 2003 under these arrangements totals
approximately $23 million. The creditors of these variable interest
entities do not have recourse to the general credit of PEC in excess of the
aggregate maximum loss exposure.
In February 2004, PEC became aware that certain long-term purchase power
and tolling contracts may be considered variable interests under FIN No.
46R. PEC has various long-term purchase power and tolling contracts with
other utilities and certain qualifying facility plants. PEC believes the
counterparties to these contracts are not special-purpose entities and,
therefore, FIN No. 46R would not apply to these contracts until March 31,
2004. PEC has not yet completed its evaluation of these contracts to
determine if the Company needs to consolidate these counterparties under
FIN No. 46R and will continue to monitor developing practice in this area.
137
3. Property, Plant and Equipment
A. Utility Plant
The balances of utility plant in service at December 31 are listed below,
with a range of depreciable lives for each:
(in millions) 2003 2002
--------------- -------------
Production plant (7-33 years) $ 8,024 $ 7,630
Transmission plant (30-75 years) 1,155 1,128
Distribution plant (12-50 years) 3,538 3,345
General plant and other (8-75 years) 614 577
--------------- -------------
Utility plant in service $ 13,331 $ 12,680
=============== =============
Generally, electric utility plant, other than nuclear fuel is pledged as
collateral for the first mortgage bonds of PEC (See Note 8).
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The
composite AFUDC rate for PEC's electric utility plant was 4.0% in 2003 and
6.2% in 2002 and 2001.
Depreciation provisions on utility plant, as a percent of average
depreciable property other than nuclear fuel, were 2.7% in 2003 and 2002
and 2.5% in 2001. The depreciation provisions related to utility plant were
$345 million, $326 million and $305 million in 2003, 2002 and 2001,
respectively. In addition to utility plant depreciation provisions,
depreciation and amortization expense also includes decommissioning cost
provisions, asset retirement obligations (ARO) accretion, cost of removal
provisions (See Note 3D) and regulatory approved expenses (See Note 5).
PEC filed a new depreciation study in 2004 that provides support for
reducing depreciation expense on an annual basis by approximately $45
million. The reduction is primarily attributable to assumption changes for
nuclear generation, offset by increases for distribution assets. The new
rates are primarily effective January 1, 2004.
The amortization of nuclear fuel costs for the years ended December 31,
2003, 2002 and 2001 were $112 million, $109 million and $101 million,
respectively.
B. Diversified Business Property
Gross diversified business property was $8 million and $10 million at
December 31, 2003 and 2002, respectively. These amounts consist primarily
of equipment which is being depreciated over periods ranging from 3 to 10
years. Accumulated depreciation was $1 million at December 31, 2003 and
2002. Diversified business depreciation expense was $1 million, $4 million
and $6 million in 2003, 2002 and 2001, respectively. Net diversified
business property is included in miscellaneous other property and
investments on the Consolidated Balance Sheets.
C. Joint Ownership of Generating Facilities
PEC holds ownership interests in certain jointly owned generating
facilities. PEC is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. PEC also
pays its ownership share of additional construction costs, fuel inventory
purchases and operating expenses. PEC's share of expenses for the jointly
owned facilities is included in the appropriate expense category. PEC's
ownership interest in the jointly-owned generating facilities is listed
below with related information at December 31 ($ in millions):
138
- ---------------------------------------------------------------------------------------------------------
Company Ownership Plant Investment Accumulated Construction
Facility Interest Depreciation Work in Progress
- ---------------------------------------------------------------------------------------------------------
2003
- ---------------------------------------------------------------------------------------------------------
Mayo Plant 83.83% $ 464 $ 242 $ 50
Harris Plant 83.83% 3,248 1,370 7
Brunswick Plant 81.67% 1,611 884 21
Roxboro Unit No. 4 87.06% 323 139 1
- ---------------------------------------------------------------------------------------------------------
2002
- ---------------------------------------------------------------------------------------------------------
Mayo Plant 83.83% $ 464 $ 232 $ 14
Harris Plant 83.83% 3,160 1,331 6
Brunswick Plant 81.67% 1,477 811 26
Roxboro Unit No. 4 87.06% 316 134 8
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Shearon Harris
Nuclear Plant (Harris Plant).
D. Decommissioning and Cost of Removal Provisions
Decommissioning cost provisions, which are included in depreciation and
amortization expense, were $31 million in 2003, 2002 and 2001. Management
believes that the decommissioning costs that have been and will be
recovered through rates will be sufficient to provide for the costs of
decommissioning.
PEC's cost of removal provisions, which are included in deprecation and
amortization expense, were $86 million, $81 million and $77 million in
2003, 2002 and 2001, respectively. These amounts represent the expense
recognized for the disposal or removal of utility assets. The FASB has
issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS
No. 143), that changed the accounting for decommissioning and cost of
removal provisions (See Note 3F).
E. Insurance
PEC is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, PEC is
insured for $500 million at each of its nuclear plants. In addition to
primary coverage, NEIL also provides decontamination, premature
decommissioning and excess property insurance with limits of $2.0 billion
on the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. PEC is insured thereunder, following a
twelve-week deductible period, for 52 weeks in the amount of $3 million per
week at the Brunswick and Harris Plants and $2.5 million per week at the
Robinson Plant. An additional 110 weeks of coverage is provided at 80% of
the above weekly amounts. For the current policy period, PEC is subject to
retrospective premium assessments of up to approximately $21 million with
respect to the primary coverage, $25 million with respect to the
decontamination, decommissioning and excess property coverage, and $14
million for the incremental replacement power costs coverage, in the event
covered losses at insured facilities exceed premiums, reserves, reinsurance
and other NEIL resources. Pursuant to regulations of the United States
Nuclear Regulatory Commission (NRC), PEC's property damage insurance
policies provide that all proceeds from such insurance be applied, first,
to place the plant in a safe and stable condition after an accident and,
second, to decontaminate, before any proceeds can be used for
decommissioning, plant repair or restoration. PEC is responsible to the
extent losses may exceed limits of the coverage described above.
139
PEC is insured against public liability for a nuclear incident up to $10.9
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear power plants, PEC, as
an owner of nuclear units, can be assessed for a portion of any third-party
liability claims arising from an accident at any commercial nuclear power
plant in the United States. In the event that public liability claims from
an insured nuclear incident exceed $300 million (currently available
through commercial insurers), PEC would be subject to pro rata assessments
of up to $101 million for each reactor owned per occurrence. Payment of
such assessments would be made over time as necessary to limit the payment
in any one year to no more than $10 million per reactor owned. Congress is
expected to approve revisions to the Price Anderson Act during 2004 that
could include increased limits and assessments per reactor owned. The final
outcome of this matter cannot be predicted at this time.
Under the NEIL policies, if there were multiple terrorism losses occurring
within one year, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant.
If terrorism losses occurred beyond the one-year period, a new set of
limits and resources would apply. For nuclear liability claims arising out
of terrorist acts, the primary level available through commercial insurers
is now subject to an industry aggregate limit of $300 million. The second
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $300 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts.
PEC self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters.
F. Asset Retirement Obligations
SFAS No. 143 provides accounting and disclosure requirements for retirement
obligations associated with long-lived assets and was adopted by the
Company effective January 1, 2003. This statement requires that the present
value of retirement costs for which PEC has a legal obligation be recorded
as a liability with an equivalent amount added to the asset cost and
depreciated over an appropriate period. The liability is then accreted over
time by applying an interest method of allocation to the liability.
Cumulative accretion and accumulated depreciation were recognized for the
time period from the date the liability would have been recognized had the
provisions of this statement been in effect to the date of adoption of this
statement.
Upon adoption of SFAS No. 143, PEC recorded AROs for nuclear
decommissioning of irradiated plant totaling $880 million. PEC used an
expected cash flow approach to measure these obligations. This amount
includes accruals recorded prior to adoption totaling $491 million, which
were previously recorded in cost of removal. The related asset retirement
costs, net of accumulated depreciation, recorded upon adoption totaled $117
million. The cumulative effect of adoption of this statement had no impact
on the net income of PEC, as the effects were offset by the establishment
of a regulatory asset in the amount of $271 million, pursuant to SFAS No.
71. The regulatory asset represents the cumulative accretion and
accumulated depreciation for the time period from the date the liability
would have been recognized had the provisions of this statement been in
effect to the date of adoption, less the amount previously recorded.
The asset retirement costs related to nuclear decommissioning of irradiated
plant, net of accumulated depreciation, totaled $113 million at December
31, 2003. The ongoing expense differences between SFAS No. 143 and
regulatory cost recovery are being deferred to the regulatory asset.
Funds set aside in PEC's nuclear decommissioning trust fund for the nuclear
decommissioning liability totaled $505 million at December 31, 2003 and
$423 million at December 31, 2002. Net unrealized gains on the nuclear
decommissioning trust fund were included in regulatory liabilities in 2003
and cost of removal in 2002.
The following table shows the changes to the asset retirement obligations
during the year ended December 31, 2003:
(in millions)
Asset retirement obligations as of January 1, 2003 $ 880
Accretion expense 52
---------
Asset retirement obligations as of December 31, 2003 $ 932
=========
140
Pro forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
PEC has identified but not recognized AROs related to electric transmission
and distribution and telecommunications assets as the result of easements
over property not owned by PEC. These easements are generally perpetual and
only require retirement action upon abandonment or cessation of use of the
property for the specified purpose. The ARO liability is not estimable for
such easements as PEC intends to utilize these properties indefinitely. In
the event PEC decides to abandon or cease the use of a particular easement,
an ARO liability would be recorded at that time.
PEC previously recognized removal and decommissioning costs as a component
of accumulated depreciation in accordance with regulatory treatment. At
December 31, 2003, such costs totaling $994 million were included in
regulatory liabilities on the Consolidated Balance Sheet and consist of
removal costs of $927 million and removal costs for non-irradiated areas at
nuclear facilities of $67 million. At December 31, 2002, such costs
totaling $1,488 million were included in cost of removal on the
Consolidated Balance Sheet and consist of removal costs of $877 million and
decommissioning costs for both the irradiated and non-irradiated areas at
nuclear facilities of $611 million. With the adoption of SFAS No. 143 in
2003, removal costs related to the irradiated areas at nuclear facilities
are reported as asset retirement obligations on the 2003 Consolidated
Balance Sheet.
PEC filed a request with the NCUC requesting deferral of the difference
between expense pursuant to SFAS No. 143 and expense as previously
determined by the NCUC. The NCUC initially granted the deferral of the
January 1, 2003 cumulative adjustment. During the third quarter of 2003,
the NCUC issued an order allowing the deferral of the ongoing effects.
In April 2003, the SCPSC approved a joint request by PEC, Duke Energy
Corporation and South Carolina Electric and Gas Company for an accounting
order to authorize the deferral of all cumulative and prospective effects
related to the adoption of SFAS No. 143.
Therefore, the actions of the NCUC and SCPSC had no impact on the income of
PEC for the year ended December 31, 2003.
4. Inventory
At December 31, inventory was comprised of:
(in millions) 2003 2002
------------ ------------
Fuel $ 118 $ 118
Materials and supplies 230 225
------------ ------------
Total inventory $ 348 $ 343
============ ============
5. Regulatory Matters
A. Regulatory Assets and Liabilities
As a regulated entity, PEC is subject to the provisions of SFAS No. 71.
Accordingly, PEC records certain assets and liabilities resulting from the
effects of the ratemaking process which would not be recorded under GAAP
for nonregulated entities. PEC's ability to continue to meet the criteria
for application of SFAS No. 71 may be affected in the future by competitive
forces and restructuring in the electric utility industry. In the event
that SFAS No. 71 no longer applied to a separable portion of PEC's
operations, related regulatory assets and liabilities would be eliminated
unless an appropriate regulatory recovery mechanism was provided.
Additionally, these factors could result in an impairment of utility plant
assets as determined pursuant to SFAS No. 144 (See Note 1C).
141
At December 31, the balances of PEC's regulatory assets (liabilities) were
as follows:
(in millions) 2003 2002
---- ----
Deferred fuel cost $ 113 $ 146
---------------- ---------------
Deferred impact of ARO (Note 3F) 291 -
Income taxes recoverable through future rates (Note 10) 94 122
Loss on reacquired debt (Note 1C) 22 13
Storm deferral (Note 5B) 21 -
Deferred DOE enrichment facilities-related costs (Note 1C) 19 25
Other 30 46
---------------- ---------------
Total long-term regulatory assets 477 206
Non-ARO cost of removal (Note 3F) (994) -
Emission allowance (8) (8)
Net nuclear decommissioning trust unrealized gains (Note 3F) (99) -
Clean air compliance (Note 5B) (74) -
---------------- ---------------
Total long-term regulatory liabilities (1,175) (8)
---------------- ---------------
Net regulatory assets/(liabilities) $ (585) $ 344
================ ===============
Except for portions of deferred fuel, all assets earn a return or the cash
has not yet been expended, in which case the assets are offset by
liabilities that do not incur a carrying cost. The utility expects to fully
recover these assets and refund the liabilities through customer rates
under current regulatory practice.
B. Retail Rate Matters
The NCUC and SCPSC approved proposals to accelerate cost recovery of PEC's
nuclear generating assets beginning January 1, 2000, and continuing through
2009. The aggregate minimum and maximum amounts of accelerated cost
recovery are $530 million and $750 million, respectively. Accelerated cost
recovery of these assets resulted in no additional expense in 2003 and
additional depreciation expense of approximately $53 million and $75
million in 2002 and 2001, respectively. Total accelerated depreciation
recorded through December 31, 2003 was $403 million.
In conjunction with the acquisition of NCNG in 1999, PEC agreed to cap base
retail electric rates in North Carolina and South Carolina through December
2004. The cap on base retail electric rates in South Carolina was extended
to December 2005 in conjunction with regulatory approval to form a holding
company.
The NC Clean Air Act of June 2002 (the Clean Air Act), requires state
utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide
(SO2) from coal-fired plants. The NCUC has allowed the utilities to
amortize and recover the costs associated with meeting the new emission
standards over a seven-year period beginning January 1, 2003. PEC
recognized $74 million of clean air amortization during 2003. This
legislation freezes PEC's base rates in North Carolina for five years,
subject to certain conditions (See Note 16D).
In conjunction with the Company's merger with Florida Progress Corporation
(Florida Progress), PEC reached a settlement with the Public Staff of the
NCUC in which it agreed to reduce rates to all of its non-real time pricing
customers by $3 million in 2002, $5 million in 2003, and $6 million in both
2004 and 2005.
PEC obtained SCPSC and NCUC approval of fuel factors in annual
fuel-adjustment proceedings. The SCPSC approved PEC's petition to leave
billing rates unchanged from the prior year by order issued March 28, 2003.
The NCUC approved an increase of $20 million by order issued September 25,
2003.
On October 16, 2003, PEC made a filing with the NCUC to seek permission to
defer expenses incurred from Hurricane Isabel and the February 2003 winter
storms. As a result of rising storm costs and the frequency of major storm
damage, PEC asked the NCUC to allow PEC to create a deferred account in
which PEC would place expenses incurred as a result of named tropical
storms, hurricanes and significant winter storms. In December 2003, the
NCUC approved PEC's request to defer the costs and amortize them over a
period of 5 years beginning in the month the storm occurs. PEC charged
approximately $24 million in 2003 from Hurricane Isabel and from current
year ice storms to the deferred account, of which $3 million was amortized
during 2003.
142
PEC retains funds internally to meet decommissioning liability. The NCUC
order issued February 2004 found that by January 1, 2008 PEC must begin
transitioning these amounts to external funds. The transition of $131
million must be completed by December 31, 2017, and at least 10% must be
transitioned each year. PEC has exclusively utilized external funding for
its decommissioning liability since 1994.
C. Regional Transmission Organizations and Standard Market Design
In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum
characteristics and eight functions for transmission entities, including
independent system operators (ISOs) and transmission companies that are
required to become FERC-approved RTOs. As a result of Order 2000, PEC,
along with Duke Energy Corporation and South Carolina Electric & Gas
Company, filed and received provisional approval from the FERC for a
GridSouth RTO. However, in July 2001, the FERC issued orders recommending
that companies in the Southeast engage in mediation to develop a plan for a
single RTO for the Southeast. PEC participated in the mediation. The FERC
has not issued an order specifically on this mediation.
In July 2002, the FERC issued its Notice of Proposed Rulemaking in Docket
No. RM01-12-000, Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market Design (SMD NOPR). If
adopted as proposed, the rules set forth in the SMD NOPR would materially
alter the manner in which transmission and generation services are provided
and paid for. PEC filed comments in November 2002 and supplement comments
in January 2003. In April 2003, the FERC released a White Paper on the
Wholesale Market Platform. The White Paper provides an overview of what the
FERC currently intends to include in a final rule in the SMD NOPR docket.
The White Paper retains the fundamental and most protested aspects of SMD
NOPR, including mandatory RTOs and the FERC's assertion of jurisdiction
over certain aspects of retail service. The FERC has not yet issued a final
rule on SMD NOPR.
PEC has $33 million invested in GridSouth at December 31, 2003. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, or an alternate combined transmission structure, PEC cannot
predict the effect on future consolidated results of operations, cash flows
or financial condition. Furthermore, the SMD NOPR presents several
uncertainties, including what percentage of the investment in GridSouth
will be recovered, how the elimination of transmission charges, as proposed
in the SMD NOPR, will impact PEC, and what amount of capital expenditures
will be necessary to create a new wholesale market.
6. Impairments of Long-Lived Assets and Investments
Effective January 1, 2002, PEC adopted SFAS No. 144, which provides
guidance for the accounting and reporting of impairment or disposal of
long-lived assets. The statement supersedes SFAS No. 121. In 2003, 2002 and
2001, PEC recorded pre-tax long-lived asset and investment impairments and
other charges of approximately $21 million, $133 million and $157 million,
respectively.
A. Long-Lived Assets
In 2002, PEC initiated an independent valuation study to assess the
recoverability of Caronet's long-lived assets. Based on this assessment,
PEC recorded asset impairments of $101 million on a pre-tax basis and other
charges of $7 million on a pre-tax basis in the third quarter of 2002. This
write-down constituted a significant reduction in the book value of these
long-lived assets. The long-lived asset impairments included an impairment
of property, plant and equipment, construction work in process and
intangible assets. The impairment charge represents the difference between
the fair value and carrying amount of these long-lived assets. The fair
value of these assets was determined using a valuation study heavily
weighted on the discounted cash flow methodology, while using market
approaches as supporting information.
143
B. Investments
PEC continually reviews its investments to determine whether a decline in
fair value below the cost basis is other than temporary. In 2003, PEC's
affordable housing investment (AHI) portfolio was reviewed and deemed to be
impaired based on various factors including continued operating losses of
the AHI portfolio and management performance issues arising at certain
properties within the AHI portfolio. As a result, PEC recorded an
impairment on the AHI portfolio of $18 million on a pre-tax basis during
the fourth quarter of 2003. PEC also recorded an impairment of $3 million
on a cost investment.
PEC obtained a valuation study to assess its investment in Interpath
Communications, Inc. (Interpath) based on current valuations in the
technology sector during 2001. Interpath was an application service
provider business in which PEC had a 35% ownership interest. As a result of
the valuation study, PEC recorded investment impairments for
other-than-temporary declines in the fair value of its investment in
Interpath. The investment write-down was $157 million on a pre-tax basis
for the year ended December 31, 2001. In May 2002, Interpath merged with a
third party and PEC's ownership was diluted to approximately 19% of
Interpath. As a result, PEC reviewed the Interpath investment for
impairment and wrote off the remaining amount of its cost-basis investment
in Interpath, recording a pre-tax impairment of $25 million in the third
quarter of 2002. In the fourth quarter of 2002, PEC sold its remaining
interest in Interpath for a nominal amount.
7. Equity
A. Capitalization
At December 31, 2003, PEC was authorized to issue up to 200 million shares
of common stock. All shares issued and outstanding are held by the Company.
Preferred stock outstanding at December 31, 2003 and 2002 consisted of the
following (in millions except per share and par value):
Authorized - 300,000 shares, cumulative, $100 par value Preferred Stock;
20,000,000 shares, cumulative, $100 par value Serial
Preferred Stock
$5.00 Preferred - 236,997 shares (redemption price $110.00) $24
$4.20 Serial Preferred - 100,000 shares outstanding
redemption price $102.00) 10
$5.44 Serial Preferred -249,850 shares (redemption price
$101.00) 25
-------
Total Preferred Stock $59
=======
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. At December 31, 2003,
there were no significant restrictions on the use of retained earnings.
PEC's Articles of Incorporation provide that cash dividends on common stock
shall be limited to 75% of net income available for dividends if common
stock equity falls below 25% of total capitalization, and to 50% if common
stock equity falls below 20%. On December 31, 2003, PEC's common stock
equity was approximately 50.7% of total capitalization.
Refer to Note 8 for additional dividend restrictions related to PEC's
mortgage.
B. Stock-Based Compensation Plans
Employee Stock Ownership Plan
Progress Energy sponsors the Progress Energy 401(k) Savings and Stock
Ownership Plan (401(k)) for which substantially all full-time
non-bargaining unit employees and certain part-time non-bargaining
employees within participating subsidiaries are eligible. PEC is a
participating subsidiary of the 401(k), which has matching and incentive
goal features, encourages systematic savings by employees and provides a
method of acquiring Progress Energy common stock and other diverse
investments. The 401(k), as amended in 1989, is an Employee Stock Ownership
Plan (ESOP) that can enter into acquisition loans to acquire Progress
144
Energy common stock to satisfy 401(k) common stock needs. Qualification as
an ESOP did not change the level of benefits received by employees under
the 401(k). Common stock acquired with the proceeds of an ESOP loan is held
by the 401(k) Trustee in a suspense account. The common stock is released
from the suspense account and made available for allocation to participants
as the ESOP loan is repaid. Such allocations are used to partially meet
common stock needs related to Progress Energy matching and incentive
contributions and/or reinvested dividends.
There were 4.0 million and 4.6 million ESOP suspense shares at December 31,
2003 and 2002, respectively, with a fair value of $183 million and $200
million, respectively. PEC's matching and incentive goal compensation cost
under the 401(k) is determined based on matching percentages and incentive
goal attainment as defined in the plan. Such compensation cost is allocated
to participants' accounts in the form of Progress Energy common stock, with
the number of shares determined by dividing compensation cost by the common
stock market value at the time of allocation. The 401(k) common stock share
needs are met with open market purchases, with shares released from the
ESOP suspense account and with newly issued shares. Costs for incentive
goal compensation are accrued during the fiscal year and typically paid
with shares in the following year; costs for the matching component are
typically met with shares in the same year incurred. PEC's matching and
incentive cost which were and will be met with shares released from the
suspense account totaled approximately $11 million, $13 million and $13
million for the years ended December 31, 2003, 2002 and 2001, respectively.
Matching and incentive cost totaled approximately $16 million, $14 million
and $14 million for the years ended December 31, 2003, 2002 and 2001,
respectively. PEC has a long-term note receivable from the 401(k) Trustee
related to the purchase of common stock from PEC in 1989 (now Progress
Energy common stock). The balance of the note receivable from the 401(k)
Trustee is included in the determination of unearned ESOP common stock,
which reduces common stock equity. Interest income on the note receivable
is not recognized for financial statement purposes.
Stock Option Agreements
Pursuant to Progress Energy's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002, Progress
Energy may grant options to purchase shares of common stock to directors,
officers and eligible employees. For the years ended December 31, 2003,
2002 and 2001, respectively, approximately 3.0 million, 2.9 million and 2.4
million common stock options were granted. Of these amounts, approximately
1.9 million, 1.2 million and 1.0 million options were granted to officers
and eligible employees of PEC in 2003, 2002 and 2001, respectively.
Other Stock-Based Compensation Plans
Progress Energy has additional compensation plans for officers and key
employees that are stock-based in whole or in part. PEC participates in
these plans. The two primary active stock-based compensation programs are
the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards
program (RSA), both of which were established pursuant to Progress Energy's
1997 Equity Incentive Plan and were continued under the 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees are granted
performance shares on an annual basis that vest over a three-year
consecutive period. Each performance share has a value that is equal to,
and changes with, the value of a share of Progress Energy's common stock,
and dividend equivalents are accrued on, and reinvested in, the performance
shares. The PSSP has two equally weighted performance measures, both of
which are based on Progress Energy's results as compared to a peer group of
utilities. Compensation expense is recognized over the vesting period based
on the expected ultimate cash payout and is reduced by any forfeitures.
The RSA program allows the Company to grant shares of restricted common
stock to officers and key employees of the Company. The restricted shares
generally vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period and is
reduced by any forfeitures.
The total amount expensed by PEC for other stock-based compensation plans
was $15 million, $11 million and $10 million in 2003, 2002 and 2001,
respectively.
145
C. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows:
(in millions) 2003 2002
------------ -----------
Loss on cash flow hedges $ (6) $ (10)
Minimum pension liability adjustments (1) (73)
------------ -----------
Total accumulated other comprehensive loss $ (7) $ (83)
============ ===========
8. Debt and Credit Facilities
A. Debt and Credit
At December 31, PEC's long-term debt consisted of the following (maturities
and weighted-average interest rates at December 31, 2003):
(in millions) 2003 2002
------------ -----------
First mortgage bonds, maturing 2004-2033 6.42% $ 1,900 $ 1,550
Pollution control obligations, maturing 2010-2024 1.69% 708 708
Unsecured notes, maturing 2012 6.50% 500 500
Medium-term notes, maturing 2008 6.65% 300 300
Miscellaneous notes - 6
Unamortized premium and discount, net (22) (16)
Current portion of long-term debt (300) -
------------ -----------
Total Long-Term Debt, Net $ 3,086 $ 3,048
============ ===========
At December 31, 2003, PEC had committed lines of credit, which are used to
support its commercial paper borrowings and had no outstanding loans. PEC
is required to pay minimal annual commitment fees to maintain its credit
facilities. The following table summarizes PEC's credit facilities (in
millions):
Description Total
----------------------------------------------------------------------
364-Day (expiring 7/29/04) $ 165
3-Year (expiring 7/31/05) 285
-----------------
$ 450
=================
At December 31, 2003 and 2002, PEC had $4 million and $438 million,
respectively, of outstanding commercial paper and other short term debt
classified as short term obligations. The weighted-average interest rates
of such short-term obligations at December 31, 2003 and 2002 were 2.25% and
1.74%, respectively.
The combined aggregate maturities of long-term debt for 2004 through 2008
are approximately, in millions, $300, $300, $0, $200 and $300,
respectively.
B. Covenants and Default Provisions
Financial Covenants
PEC's credit line contains various terms and conditions that could affect
PEC's ability to borrow under these facilities. These include a maximum
debt to total capital ratio, a material adverse change clause and a
cross-default provision.
PEC's credit line requires a maximum total debt to total capital ratio of
65%. Indebtedness as defined by the bank agreement includes certain letters
of credit and guarantees which are not recorded on the Consolidated Balance
Sheets. At December 31, 2003, PEC's total debt to total capital ratio was
51.4%.
Material Adverse Change Clause
The credit facility of PEC includes a provision under which lenders could
refuse to advance funds in the event of a material adverse change in the
borrower's financial condition.
146
Default Provisions
PEC's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. PEC's cross-default provisions only
apply to defaults of indebtedness by PEC and its subsidiaries,
respectively, and not to other affiliates of PEC. In addition, the credit
lines of Progress Energy include a similar provision. Progress Energy's
cross-default provisions only apply to defaults of indebtedness by Progress
Energy and its significant subsidiaries, which includes PEC.
The lenders may accelerate payment of any outstanding debt if cross-default
provisions are triggered. Any such acceleration would cause a material
adverse change in the respective company's financial condition. Certain
agreements underlying PEC's indebtedness also limit PEC's ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
Other Restrictions
PEC's mortgage indenture provides that, as long as any first mortgage bonds
are outstanding, cash dividends and distributions on PEC's common stock and
purchases of PEC's common stock are restricted to aggregate net income
available for PEC, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2003, none of
PEC's retained earnings were restricted. Refer to Note 7 for additional
dividend restrictions related to PEC's Articles of Incorporation.
C. Secured Obligations
PEC's first mortgage bonds are secured by their respective mortgage
indentures. PEC's mortgage constitutes a first lien on substantially all of
its fixed properties, subject to certain permitted encumbrances and
exceptions. The PEC mortgage also constitutes a lien on subsequently
acquired property. At December 31, 2003, PEC had approximately $2,608
million in first mortgage bonds outstanding including those related to
pollution control obligations. The PEC mortgage allows the issuance of
additional mortgage bonds upon the satisfaction of certain conditions.
D. Hedging Activities
PEC uses interest rate derivatives to adjust the fixed and variable rate
components of its debt portfolio and to hedge cash flow risk of fixed rate
debt to be issued in the future. See discussion of risk management and
derivative transactions at Note 12.
9. Fair Value of Financial Instruments
At December 31, 2003 and 2002, there were miscellaneous investments
consisting primarily of investments in company-owned life insurance and
other benefit plan assets with carrying amounts totaling approximately $59
million and $54 million, respectively, included in miscellaneous other
property and investments. The carrying amount of these investments
approximates fair value due to the short maturity of certain instruments.
Other instruments are presented at fair value in accordance with GAAP. The
carrying amount of PEC's long-term debt, including current maturities, was
$3,386 million at December 31, 2003 and $3,048 million at December 31,
2002. The estimated fair value of this debt, as obtained from quoted market
prices for the same or similar issues, was $3,686 million and $3,328
million at December 31, 2003 and 2002, respectively.
External trust funds have been established to fund certain costs of nuclear
decommissioning. These nuclear decommissioning trust funds are invested in
stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are
presented at amounts that approximate fair value. Fair value is obtained
from quoted market prices for the same or similar investments.
10. Income Taxes
Deferred income taxes are provided for temporary differences between book
and tax bases of assets and liabilities. Investment tax credits related to
regulated operations are amortized over the service life of the related
property. To the extent that the establishment of deferred income taxes
under SFAS No. 109 is different from the recovery of taxes by PEC through
the ratemaking process, the differences are deferred pursuant to SFAS No.
71. A regulatory asset or liability has been recognized for the impact of
tax expenses or benefits that are recovered or refunded in different
periods by the utilities pursuant to rate orders.
147
Net accumulated deferred income tax liabilities/(assets) at December 31
are:
(in millions) 2003 2002
-------------- -------------
Accumulated depreciation and property
cost differences $ 1,207 $ 1,280
Minimum pension liability (1) (47)
Deferred costs, net (26) (50)
Income tax credit carry forward (22) (10)
Valuation allowance 1 8
Miscellaneous other temporary differences, net (50) (10)
-------------- -------------
Net accumulated deferred income tax liability $ 1,109 $ 1,171
============== =============
Total deferred income tax liabilities were $1,880 million and $1,882
million at December 31, 2003 and 2002, respectively. Total deferred income
tax assets were $771 million and $711 million at December 31, 2003 and
2002, respectively. At December 31, 2003 and 2002, PEC had net non-current
deferred tax liabilities of $1,125 million and $1,105 million. At December
31, 2003 PEC had a net current deferred tax asset of $16 million which is
included on the Consolidated Balance Sheets under the caption prepayments
and other current assets. At December 31, 2002 PEC had a net current
deferred tax liability of $66 million which is included on the Consolidated
Balance Sheets under the caption other current liabilities.
PEC established additional valuation allowances of $1 million, $4 million
and $4 million during 2003, 2002 and 2001, respectively, due to the
uncertainty of realizing certain future state tax benefits. PEC had a
valuation allowance of $8 million at December 31, 2002, which decreased by
$7 million in 2003. The overall decrease in the 2003 valuation allowance is
largely due to PEC's sale of its wholly-owned subsidiary Caronet. Caronet's
valuation allowance balance at December 31, 2002 and 2001 was $8 million
and $4 million, respectively. PEC believes that it is more likely than not
that the results of future operations will generate sufficient taxable
income to allow for the utilization of the remaining deferred tax assets.
Reconciliations of PEC's effective income tax rate to the statutory federal
income tax rate are:
2003 2002 2001
------------- ------------- -------------
Effective income tax rate 32.6% 32.5% 38.0%
State income taxes, net of federal benefit (1.9) (3.1) (3.2)
Investment tax credit amortization 1.4 1.9 2.5
Progress Energy tax benefit allocation 3.0 5.0 -
Other differences, net (0.1) (1.3) (2.3)
------------- ------------- -------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
============= ============= =============
The provisions for income tax expense are comprised of:
(in millions) 2003 2002 2001
------------- ------------- ---------------
Income tax expense (credit):
Current - federal $ 285 $ 265 $ 349
state 37 36 39
Deferred - federal (55) (76) (140)
state (13) (6) (10)
Investment tax credit (10) (12) (15)
------------- ------------- ---------------
Total income tax expense $ 244 $ 207 $ 223
============= ============= ===============
PEC and each of its wholly-owned subsidiaries have entered into a Tax
Agreement with Progress Energy (See Note 1C). PEC's intercompany tax
receivable was $16 million and $13 million at December 31, 2003 and 2002,
respectively.
148
11. Benefit Plans
PEC and some of its subsidiaries have a non-contributory defined benefit
retirement (pension) plan for substantially all full-time employees. PEC
also has supplementary defined benefit pension plans that provide benefits
to higher-level employees. In addition to pension benefits, PEC and some of
its subsidiaries provide contributory other postretirement benefits (OPEB),
including certain health care and life insurance benefits, for retired
employees who meet specified criteria. PEC uses a measurement date of
December 31 for its pension and OPEB plans.
The components of net periodic benefit cost for the years ended December 31
are:
Pension Benefits Other Postretirement Benefits
--------------------------------- -----------------------------
(in millions) 2003 2002 2001 2003 2002 2001
--------------------------------- ---------------------------
Service cost $ 23 $ 19 $ 17 $ 7 $ 6 $ 7
Interest cost 51 51 47 15 14 14
Expected return on plan assets (70) (73) (72) (3) (3) (4)
Amortization, net - 1 (6) 5 2 5
--------------------------------- ---------------------------
Net periodic cost / (benefit) $ 4 $ (2) $ (14) $ 24 $ 19 $ 22
================================= ===========================
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants. PEC uses a five-year averaging
method to determine its market-related value of assets.
Reconciliations of the changes in the plans' benefit obligations and the
plans' funded status are:
Pension Benefits Other Postretirement Benefits
------------------------ ------------------------------
(in millions) 2003 2002 2003 2002
------------------------ ------------------------------
Obligation at January 1 $ 802 $ 682 $ 234 $ 192
Service cost 23 19 7 6
Interest cost 51 51 15 14
Benefit payments (46) (46) (8) (9)
Actuarial loss (gain) (82) 96 12 31
------------------------ ------------------------------
Obligation at December 31 748 802 260 234
Fair value of plan assets at December 31 694 574 43 33
------------------------ ------------------------------
Funded status (54) (228) (217) (201)
Unrecognized transition obligation - - 23 26
Unrecognized prior service cost 4 4 - -
Unrecognized net actuarial (gain) loss 61 238 41 38
Minimum pension liability adjustment (2) (125) - -
------------------------ ------------------------------
Prepaid (accrued) cost at December 31, net $ 9 $ (111) $ (153) $ (137)
======================== ==============================
The net prepaid pension cost of $9 million at December 31, 2003 is
recognized in the accompanying Consolidated Balance Sheets as prepaid
pension cost of $28 million, which is included in other assets and deferred
debits, and accrued benefit cost of $19 million, which is included in other
liabilities and deferred credits. The accrued pension cost at December 31,
2002 is included in other liabilities and deferred credits in the
accompanying Consolidated Balance Sheets. The defined benefit pension plans
with accumulated benefit obligations in excess of plan assets had projected
benefit obligations totaling $22 million and $802 million at December 31,
2003 and 2002, respectively. Those plans had accumulated benefit
obligations totaling $19 million and $685 million, respectively, no plan
assets at December 31, 2003, and plan assets totaling $574 million at
December 31, 2002. The total accumulated benefit obligation for pension
plans was $745 million and $685 million at December 31, 2003 and 2002,
respectively. The accrued OPEB cost is included in other liabilities and
deferred credits in the accompanying Consolidated Balance Sheets.
149
A minimum pension liability adjustment of $2 million, related to the
supplementary defined benefit pension plan, was recorded at December 31,
2003. This adjustment is offset by a corresponding pre-tax amount in
accumulated other comprehensive loss, a component of common stock equity.
Due to a combination of decreases in the fair value of plan assets and a
decrease in the discount rate used to measure the pension obligation, a
minimum pension liability adjustment of $125 million was recorded at
December 31, 2002. This adjustment resulted in a charge of $4 million to
intangible assets, included in other assets and deferred debits in the
accompanying Consolidated Balance Sheets, and a pre-tax charge of $121
million to accumulated other comprehensive loss, a component of common
stock equity.
Reconciliations of the fair value of plan assets are:
Pension Benefits Other Postretirement Benefits
---------------------------- -----------------------------
(in millions) 2003 2002 2003 2002
---------------------------- ------------------------
Fair value of plan assets January 1 $ 574 $ 717 $ 33 $ 38
Actual return on plan assets 164 (97) 10 (5)
Benefit payments (46) (46) (8) (9)
Employer contributions 1 1 8 9
Transfers - (1) - -
------------ ------------ ----------- -----------
Fair value of plan assets at December 31 $ 693 $ 574 $ 43 $ 33
============ ============ =========== ===========
In the table above, substantially all employer contributions represent
benefit payments made directly from Company assets. The remaining benefits
payments were made directly from plan assets. The OPEB benefit payments
represent the net PEC cost after participant contributions. Participant
contributions represent approximately 35% of gross benefit payments.
The asset allocation for PEC's plans at the end of 2003 and 2002 and the
target allocation for the plans, by asset category, are as follows:
Pension Benefits Other Postretirement Benefits
------------------------------------------ ---------------------------------------------
Target Percentage of Plan Assets Target Percentage of Plan Assets
Allocations at Year End Allocations at Year End
------------- ------------------------ ----------------- ------------------------
Asset Category 2004 2003 2002 2004 2003 2002
------------- ---------------------- ----------------- ----------------------
Equity - domestic 50% 49% 47% 50% 49% 47%
Equity - international 15% 22% 20% 15% 22% 20%
Debt - domestic 15% 11% 15% 15% 11% 15%
Debt - international 10% 11% 10% 10% 11% 10%
Other 10% 7% 8% 10% 7% 8%
------------- ---------------------- ----------------- ----------------------
Total 100% 100% 100% 100% 100% 100%
============= ====================== ================= ======================
PEC sets target allocations among asset classes to provide broad
diversification to protect against large investment losses and excessive
volatility, while recognizing the importance of offsetting the impacts of
benefit cost escalation. In addition, PEC employs external investment
managers who have complementary investment philosophies and approaches.
Tactical shifts (plus or minus five percent) in asset allocation from the
target allocations are made based on the near-term view of the risk and
return tradeoffs of the asset classes.
In 2004, PEC expects to make required contributions of $17 million directly
to pension plan assets. The expected benefit payments for the pension
benefit plan for 2004 through 2008 and in total for 2009-2013, in millions,
are approximately $48, $49, $50, $53, $55 and $301, respectively. The
expected benefit payments for the OPEB plan for 2004 through 2008 and in
total for 2009-2013, in millions, are approximately $7, $8, $9, $10, $10
and $62, respectively. The expected benefit payments include benefit
payments directly from plan assets and benefit payments directly from
Company assets. The benefit payment amounts reflect the net cost to PEC
after any participant contributions.
150
The following weighted-average actuarial assumptions were used in the
calculation of the year-end obligation:
Pension Benefits Other Postretirement Benefits
------------------------- -----------------------------
2003 2002 2003 2002
------------------------- ----------------------------
Discount rate 6.30% 6.60% 6.30% 6.60%
Rate of increase in future compensation - non-bargaining - 4.00% - -
Rate of increase in future compensation - supplementary plan 5.00% 4.00% - -
Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.50%
Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.50%
Ultimate medical cost trend rate - - 5.25% 5.25%
Year ultimate medical cost trend rate is achieved - - 2009 2009
PEC's primary defined benefit retirement plan for non-bargaining employees
is a "cash balance" pension plan as defined in EITF Issue No. 03-4.
Therefore, effective December 31, 2003, PEC began to use the traditional
unit credit method for purposes of measuring the benefit obligation of this
plan and will use that method to measure future benefit costs. Under the
traditional unit credit method, no assumptions are included about future
changes in compensation and the accumulated benefit obligation and
projected benefit obligation are the same.
The following weighted-average actuarial assumptions were used in the
calculation of the net periodic cost:
Pension Benefits Other Postretirement Benefits
---------------------------- -------------------------------
2003 2002 2001 2003 2002 2001
---------------------------- -------------------------------
Discount rate 6.60% 7.50% 7.50% 6.60% 7.50% 7.50%
Rate of increase in future compensation 4.00% 4.00% 4.00% - - -
Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 9.25% 9.25% 9.25%
Initial medical cost trend rate for pre-Medicare
benefits - - - 7.50% 7.50% 7.50%
Initial medical cost trend rate for post-Medicare
benefits - - - 7.50% 7.50% 7.50%
Ultimate medical cost trend rate - - - 5.25% 5.00% 5.00%
Year ultimate medical cost trend rate is achieved - - - 2009 2008 2007
The expected long-term rates of return on plan assets were determined by
considering long-term historical returns for the plans and long-term
projected returns based on the plans' target asset allocations. Those
benchmarks support an expected long-term rate of return between 9.5% and
10.0%. PEC has chosen to use an expected long-term rate of 9.25% due to the
uncertainties of future returns.
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2003 would increase by $1 million, and
the OPEB obligation at December 31, 2003, would increase by $18 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for
2003 would decrease by $1 million and the OPEB obligation at December 31,
2003, would decrease by $15 million.
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the Act) was signed into law. In accordance with
guidance issued by the FASB in FASB Staff Position FAS 106-1, PEC has
elected to defer accounting for the effects of the Act due to uncertainties
regarding the effects of the implementation of the Act and the accounting
for certain provisions of the Act. Therefore, OPEB information presented
above and in the financial statements does not reflect the effects of the
Act. When specific authoritative accounting guidance is issued, it could
require plan sponsors to change previously reported information. PEC is in
the early stages of reviewing the Act and determining its potential effects
on PEC.
151
12. Risk Management Activities and Derivatives Transactions
Under its risk management policy, PEC may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments
contain credit risk if the counterparty fails to perform under the
contract. PEC minimizes such risk by performing credit reviews using, among
other things, publicly available credit ratings of such counterparties.
Potential non-performance by counterparties is not expected to have a
material effect on the consolidated financial position or consolidated
results of operations of PEC.
A. Commodity Contracts - General
Most of PEC's commodity contracts either are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
In connection with the January 2003 EITF meeting, the FASB was requested to
reconsider an interpretation of SFAS No. 133. The interpretation, which was
contained in the Derivative Implementation Group's C11 guidance, related to
the pricing of contracts that include broad market indices (e.g., CPI). In
particular, that guidance discussed whether the pricing in a contract that
contains broad market indices could qualify as a normal purchase or sale
(the normal purchase or sale term is a defined accounting term, and may
not, in all cases, indicate whether the contract would be "normal" from an
operating entity viewpoint). In June 2003, the FASB issued final
superseding guidance (DIG Issue C20) on this issue. The new guidance was
effective October 1, 2003 for the Company. DIG Issue C20 specifies new
pricing-related criteria for qualifying as a normal purchase or sale, and
it required a special transition adjustment as of October 1, 2003.
PEC determined that it had one existing "normal" contract that was affected
by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
a pre-tax fair value loss transition adjustment of $38 million ($23 million
after-tax) in the fourth quarter of 2003, which was recorded as a
cumulative effect of a change in accounting principle. The subject contract
meets the DIG Issue C20 criteria for normal purchase or sale and,
therefore, was designated as a normal purchase as of October 1, 2003. The
liability associated with the fair value loss will be amortized to earnings
over the term of the related contract.
B. Commodity Derivatives - Economic Hedges and Trading
Nonhedging derivatives, primarily electricity forward contracts, are
entered into for trading purposes and for economic hedging purposes. While
management believes the economic hedges mitigate exposures to fluctuations
in commodity prices, these instruments are not designated as hedges for
accounting purposes and are monitored consistent with trading positions.
PEC manages open positions with strict policies that limit its exposure to
market risk and require daily reporting to management of potential
financial exposures. Gains and losses from such contracts were not material
during 2003, 2002 or 2001, and PEC did not have material outstanding
positions in such contracts at December 31, 2003 or 2002.
C. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
PEC manages its interest rate exposure in part by maintaining its
variable-rate and fixed-rate exposures within defined limits. In addition,
PEC also enters into financial derivative instruments including, but not
limited to, interest rate swaps and lock agreements to manage and mitigate
interest rate risk exposure.
PEC uses cash flow hedging strategies to hedge variable interest rates on
long-term debt and to hedge interest rates with regard to future fixed-rate
debt issuances. PEC held no interest rate cash flow hedges at December 31,
2003 or 2002. At December 31, 2003, $1 million of net after-tax deferred
losses in accumulated other comprehensive income, related to terminated
hedges, will be reclassified to earnings during the next 12 months as the
hedged interest payments occur.
PEC uses fair value hedging strategies to manage its exposure to fixed
interest rates on long-term debt. At December 31, 2003 and 2002, PEC had no
open interest rate fair value hedges.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
152
13. Related Party Transactions
PEC participates in an internal money pool, operated by Progress Energy, to
more effectively utilize cash resources and to reduce outside short-term
borrowings. The money pool also is used to settle intercompany balances.
The weighted-average interest rate for the money pool was 1.47%, 2.18% and
4.47% at December 31, 2003, 2002 and 2001, respectively. At December 31,
2003, PEC had $25 million of amounts payable to the money pool that are
included in notes payable to affiliated companies on the Consolidated
Balance Sheets. At December 31, 2002, PEC had $50 million of amounts
receivable from the money pool that are included in notes receivable from
affiliated companies on the Consolidated Balance Sheets. PEC recorded net
interest expense of approximately $1 million related to the money pool for
2003 and 2002. Net interest expense for 2001 was not significant.
The Company formed Progress Energy Service Company, LLC (PESC) to provide
specialized services, at cost, to the Company and its subsidiaries, as
approved by the U.S. Securities and Exchange Commission (SEC). PEC has an
agreement with PESC under which services, including purchasing, information
technology, telecommunications, marketing, treasury, human resources,
accounting, real estate, legal and tax are rendered at cost. Amounts billed
to PEC by PESC for these services during 2003, 2002 and 2001 amounted to
$184 million, $198 million and $156 million, respectively. At December 31,
2003 and 2002, PEC had net payables of $118 million and $63 million,
respectively, to PESC. During 2002, the Office of Public Utility Regulation
within the SEC completed an audit examination of the Company's books and
records. This examination is a standard process for all PUHCA registrants.
Based on the review, the method for allocating PESC costs to the Company
and its affiliates changed for 2003 and retroactive reallocations of 2002
and 2001 charges were made during the first quarter. The net after-tax
impact of the reallocation of costs was a reduction of expenses at PEC by
$10 million.
The Company sold North Carolina Natural Gas Corporation (NCNG) to Piedmont
Natural Gas Company, Inc. on September 30, 2003. During the years ended
December 31, 2003, 2002 and 2001, gas sales from NCNG to PEC amounted to
$11 million, $18 million and $15 million, respectively. The gas sales for
2003 indicated above exclude any sales subsequent to September 2003.
PEC entered into a Tax Agreement with Progress Energy (See Note 10).
In February 2002, PEC transferred the Rowan Plant to Progress Ventures,
Inc. The property and inventory transferred totaled approximately $244
million.
In August 2002, PEC transferred reservation payments for the manufacture of
two combustion turbines to PEF at PEC's original cost of $20 million.
14. Financial Information by Business Segment
PEC's operations consist primarily of the PEC Electric segment which is
engaged in the generation, transmission, distribution and sale of electric
energy primarily in portions of North Carolina and South Carolina. These
electric operations are subject to the rules and regulations of the FERC,
the NCUC, the SCPSC and the NRC.
The Other segment, whose operations are primarily in the United States, is
made up of other nonregulated business areas including telecommunications
and other nonregulated subsidiaries that do not separately meet the
disclosure requirements of SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information" and consolidation entities and
eliminations. Included are the operations of Caronet, which recognized an
$87 million after-tax asset and investment impairment in 2002 and an
after-tax investment impairment of $107 million in 2001.
153
(In millions) PEC Electric Other Total
- ------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Revenues $ 3,589 $ 11 $ 3,600
Depreciation and amortization 562 1 563
Total interest charges, net 194 - 194
Impairment of long-lived assets &
investments 11 10 21
Income taxes 240 4 244
Income before cumulative effect 515 (13) 502
Total segment assets 10,854 154 11,008
Capital and investment
expenditures 470 1 471
- ------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Revenues $ 3,539 $ 15 $ 3,554
Depreciation and amortization 524 4 528
Total interest charges, net 212 - 212
Impairment of long-lived assets &
investments - 126 126
Income taxes 237 (30) 207
Income before cumulative effect 513 (85) 428
Total segment assets 10,139 266 10,405
Capital and investment
expenditures 624 12 636
- ------------------------------------------------------------------------------------------------
Year Ended December 31, 2001
Revenues $ 3,344 $ 16 $ 3,360
Depreciation and amortization 522 7 529
Total interest charges, net 241 - 241
Impairment of long-lived assets &
investments - 157 157
Income taxes 264 (41) 223
Income before cumulative effect 468 (107) 361
Capital and investment
expenditures 824 13 837
- ------------------------------------------------------------------------------------------------
15. Other Income and Other Expense
Other income and expense includes interest income, gain on the sale of
investments, impairment of investments and other income and expense items
as discussed below. The components of other, net as shown on the
Consolidated Statements of Income and Comprehensive Income for years ended
December 31, are as follows:
154
(in millions) 2003 2002 2001
---- ---- ----
Other income
Net financial trading gain (loss) $ (1) $ (2) $ 3
Net energy brokered for resale gain 2 1 3
Nonregulated energy and delivery services income 8 12 12
Investment gains 9 22 2
AFUDC equity 2 6 9
Other 12 21 13
---------------------------------------
Total other income $ 32 $ 60 $ 42
---------------------------------------
Other expense
Nonregulated energy and delivery services expenses $ 9 $ 14 $ 21
Donations 6 8 11
Investment losses 12 14 4
Other 16 11 10
---------------------------------------
Total other expense $ 43 $ 47 $ 46
---------------------------------------
Other, net $ (11) $ 13 $ (4)
=======================================
Net financial trading gain (loss) represents non-asset-backed trades of
electricity and gas. Nonregulated energy and delivery services include
power protection services and mass market programs (surge protection,
appliance services and area light sales) and delivery, transmission and
substation work for other utilities.
16. Commitments and Contingencies
A. Purchase Obligations
The following table reflects PEC's contractual cash obligations and other
commercial commitments in the respective periods in which they are due.
(in millions)
Contractual Cash Obligations 2004 2005 2006 2007 2008 Thereafter
- -------------------------------------------------------------------------------------------------------
Fuel $ 433 $ 244 $ 195 $ 96 $ 33 $ 73
Purchased power 110 110 110 110 74 474
Construction Obligations 5 - - - - -
Other Purchase Obligations - - - - - 13
- -------------------------------------------------------------------------------------------------------
Total $ 548 $ 354 $ 305 $ 206 $ 107 $ 560
Fuel and Purchased Power
PEC has entered into various long-term contracts for coal, gas and oil
requirements of its generating plants. Total payments under these
commitments were $498 million, $529 million and $496 million in 2003, 2002
and 2001, respectively. Estimated annual payments for firm commitments of
fuel purchases and transportation costs under these contracts are
approximately $433 million, $244 million, $195 million, $96 million and $33
million for 2004 through 2008, respectively, with $73 million payable
thereafter.
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between PEC and the North Carolina Eastern Municipal Power Agency (Power
Agency), PEC is obligated to purchase a percentage of Power Agency's
ownership capacity of, and energy from, the Harris Plant. In 1993, PEC and
Power Agency entered into an agreement to restructure portions of their
contracts covering power supplies and interests in jointly owned units.
Under the terms of the 1993 agreement, PEC increased the amount of capacity
and energy purchased from Power Agency's ownership interest in the Harris
Plant, and the buyback period was extended six years through 2007. The
estimated minimum annual payments for these purchases, which reflect
capacity costs, total approximately $36 million. These contractual
purchases totaled $36 million, $36 million and $33 million for 2003, 2002
and 2001, respectively. In 1987, the NCUC ordered PEC to reflect the
recovery of the capacity portion of these costs on a levelized basis over
the original 15-year buyback period, thereby deferring for future recovery
the difference between such costs and amounts collected through rates. In
1988, the SCPSC ordered similar treatment, but with a 10-year levelization
period. At December 31, 2002, PEC had deferred purchased capacity costs,
including carrying costs accrued on the deferred balances of $17 million.
At December 31, 2003 all previously deferred costs have been expensed.
155
PEC has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 MW of
capacity through 2009 with estimated minimum annual payments of
approximately $42 million, representing capital-related capacity costs.
Estimated annual payments for energy and capacity costs are approximately
$70 million through 2009. Total purchases (including energy and
transmission use charges) under the Rockport agreement amounted to $66
million, $59 million and $63 million for 2003, 2002 and 2001, respectively.
Effective June 1, 2001, PEC executed a long-term agreement for the purchase
of power from Skygen Energy LLC's Broad River facility (Broad River). The
agreement provides for the purchase of approximately 500 MW of capacity
through 2021 with an original minimum annual payment of approximately $16
million, primarily representing capital-related capacity costs. A separate
long-term agreement for additional power from Broad River commenced June 1,
2002. This agreement provided for the additional purchase of approximately
300 MW of capacity through 2022 with an original minimum annual payment of
approximately $16 million representing capital-related capacity costs.
Total purchases under the Broad River agreements amounted to $37 million,
$38 million, and $21 million in 2003, 2002 and 2001 respectively.
PEC has various pay-for-performance purchased power contracts with certain
cogenerators (qualifying facilities) for approximately 400 MW of capacity
expiring at various times through 2009. These purchased power contracts
generally provide for capacity and energy payments. Payments for both
capacity and energy are contingent upon the QFs' ability to generate.
Payments made under these contracts were $118 million in 2003 and $145
million in 2002 and 2001.
Construction Obligations
PEC has purchase obligations for various combustion turbines. Total
purchases under these obligations were $21 million for 2003 and $13 million
for 2002. Future purchase obligations are $5 million for 2004.
Other Contractual Obligations
On December 31, 2002, PEC entered into a contractual commitment to purchase
at least $13 million of capital parts by December 31, 2010. At December 31,
2003 no capital parts have been purchased under this contract.
B. Leases
PEC leases office buildings, computer equipment, vehicles, and other
property and equipment with various terms and expiration dates. Rent
expense under operating leases totaled $11 million, $10 million and $22
million for 2003, 2002 and 2001, respectively. Assets recorded under
capital leases consist of:
(in millions) 2003 2002
---- ----
Buildings $ 30 $ 28
Less: Accumulated amortization (10) (10)
----------- ----------
$ 20 $ 18
=========== ==========
156
Minimum annual rental payments, excluding executory costs such as property
taxes, insurance and maintenance, under long-term noncancelable leases at
December 31, 2003 are:
(in millions) Capital Leases Operating Leases
-------------- ----------------
2004 $ 2 $ 6
2005 2 9
2006 2 6
2007 2 6
2008 2 6
Thereafter 25 102
-------------- ----------------
$ 35 $ 135
================
Less amount representing imputed interest (15)
--------------
Present value of net minimum lease payments $ 20
==============
PEC is the lessor of electric poles, streetlights and other facilities.
Rents received are contingent upon usage and totaled $31 million, $28
million and $31 million for 2003, 2002 and 2001, respectively.
C. Guarantees
As a part of normal business, PEC enters into various agreements providing
financial or performance assessments to third parties. Such agreements
include, for example, guarantees, standby letters of credit and surety
bonds. These agreements are entered into primarily to support or enhance
the creditworthiness otherwise attributed to subsidiaries on a stand-alone
basis, thereby facilitating the extension of sufficient credit to
accomplish the subsidiaries' intended commercial purposes. At December 31,
2003, management does not believe conditions are likely for performance
under these agreements.
At December 31, 2003, outstanding guarantees consisted of the following:
(in millions)
Standby letters of credit $ 3
Surety bonds 19
------------
Total $ 22
============
Standby Letters of Credit
PEC has issued standby letters of credit to financial institutions for the
benefit of third parties that have extended credit to PEC and certain
subsidiaries. These letters of credit have been issued primarily for the
purpose of supporting payments of trade payables, securing performance
under contracts and on interest payments on outstanding debt obligations.
If a subsidiary does not pay amounts when due under a covered contract, the
counterparty may present its claim for payment to the financial
institution, which will in turn request payment from PEC. Any amounts owed
by its subsidiaries are reflected in the Consolidated Balance Sheets.
Surety Bonds
At December 31, 2003, PEC had $19 million in surety bonds purchased
primarily for purposes such as providing workers' compensation coverage and
obtaining licenses, permits and rights-of-way. To the extent liabilities
are incurred as a result of the activities covered by the surety bonds,
such liabilities are included in the Consolidated Balance Sheets.
Guarantees Issued by the Parent
In 2003, PEC determined that its external funding levels did not fully meet
the nuclear decommissioning financial assurance levels required by the NRC.
Therefore, PEC obtained parent company guarantees of $276 million to meet
the required levels.
D. Claims and Uncertainties
1. PEC is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
157
Hazardous and Solid Waste Management
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
PEC has some connection. In this regard, PEC and other potentially
responsible parties (PRPs) are participating in, investigating and, if
necessary, remediating former MGP sites with several regulatory agencies,
including, but not limited to, the U.S. Environmental Protection Agency
(EPA) and the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM). In addition, PEC is
periodically notified by regulators such as the EPA and various state
agencies of its involvement or potential involvement in sites, other than
MGP sites, that may require investigation and/or remediation.
There are nine former MGP sites and other sites associated with PEC that
have required or are anticipated to require investigation and/or
remediation costs. PEC received insurance proceeds to address costs
associated with PEC environmental liabilities related to its involvement
with some MGP sites. All eligible expenses related to these are charged
against a specific fund containing these proceeds. At December 31, 2003,
approximately $9 million remains in this centralized fund with a related
accrual of $9 million recorded for the associated expenses of environmental
issues. PEC does not believe that it can provide an estimate of the
reasonably possible total remediation costs beyond what is currently
accrued due to the fact that investigations have not been completed at all
sites. PEC measures its liability for these sites based on available
evidence including its experience in investigating and remediating
environmentally impaired sites. The process often involves assessing and
developing cost-sharing arrangements with other PRPs. PEC will accrue costs
for the sites to the extent its liability is probable and the costs can be
reasonably estimated. Presently, PEC cannot determine the total costs that
may be incurred in connection with the remediation of any of these MGP
sites.
In September 2003, the Company sold NCNG to Piedmont Natural Gas Company,
Inc. As part of the sales agreement, the Company retained responsibility to
remediate five former NCNG MGP sites, all of which also are associated with
PEC, to state standards pursuant to an Administrative Order by consent.
These sites are anticipated to have investigation or remediation costs
associated with them. NCNG had previously accrued approximately $2 million
for probable and reasonably estimable remediation costs at these sites.
These accruals have been recorded on an undiscounted basis. At the time of
the sale, the liability for these costs and the related accrual was
transferred to PEC. PEC does not believe it can provide an estimate of the
reasonably possible total remediation costs beyond the accrual because
investigations have not been completed at all sites. Therefore, PEC cannot
currently determine the total costs that may be incurred in connection with
the investigation and/or remediation of all sites.
PEC has filed claims with its general liability insurance carriers to
recover costs arising out of actual or potential environmental liabilities.
All claims have settled other than with insolvent carriers. These
settlements have not had a material effect on the consolidated financial
position or results of operations.
PEC is also currently in the process of assessing potential costs and
exposures at other environmentally impaired sites. As the assessments are
developed and analyzed, PEC will accrue costs for the sites to the extent
the costs are probable and can be reasonably estimated.
Air Quality
There has been and may be further proposed federal legislation requiring
reductions in air emissions for NOx, SO2, carbon dioxide and mercury. Some
of these proposals establish nation-wide caps and emission rates over an
extended period of time. This national multi-pollutant approach to air
pollution control could involve significant capital costs which could be
material to PEC's consolidated financial position or results of operations.
Some companies may seek recovery of the related cost through rate
adjustments or similar mechanisms. Control equipment that will be installed
on North Carolina fossil generating facilities as part of the North
Carolina legislation discussed below may address some of the issues
outlined above. However, PEC cannot predict the outcome of this matter.
158
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether
modifications at those facilities were subject to New Source Review
requirements or New Source Performance Standards under the Clean Air Act.
PEC was asked to provide information to the EPA as part of this initiative
and cooperated in providing the requested information. The EPA initiated
civil enforcement actions against other unaffiliated utilities as part of
this initiative. Some of these actions resulted in settlement agreements
calling for expenditures by these unaffiliated utilities, ranging from $1.0
billion to $1.4 billion. A utility that was not subject to a civil
enforcement action settled its New Source Review issues with the EPA for
$300 million. These settlement agreements have generally called for
expenditures to be made over extended time periods, and some of the
companies may seek recovery of the related cost through rate adjustments or
similar mechanisms. PEC cannot predict the outcome of this matter.
In 1998, the EPA published a final rule at Section 110 of the Clean Air Act
addressing the regional transport of ozone (NOx SIP Call). The EPA's rule
requires 23 jurisdictions, including North Carolina, South Carolina and
Georgia, to further reduce NOx emissions in order to attain a pre-set state
NOx (NOx) emission level by May 31, 2004. PEC is currently installing
controls necessary to comply with the rule. Capital expenditures to meet
these measures in North and South Carolina could reach approximately $370
million, which has not been adjusted for inflation. PEC has spent
approximately $258 million to date related to these expenditures. Increased
operation and maintenance costs relating to the NOx SIP Call are not
expected to be material to PEC's results of operations. Further controls
are anticipated as electricity demand increases. PEC cannot predict the
outcome of this matter.
In July 1997, the EPA issued final regulations establishing a new 8-hour
ozone standard. In October 1999, the District of Columbia Circuit Court of
Appeals ruled against the EPA with regard to the federal 8-hour ozone
standard. The U.S. Supreme Court has upheld, in part, the District of
Columbia Circuit Court of Appeals decision. Designation of areas that do
not attain the standard is proceeding, and further litigation and
rulemaking on this and other aspects of the standard are anticipated. North
Carolina adopted the federal 8-hour ozone standard and is proceeding with
the implementation process. North Carolina has promulgated final
regulations, which will require PEC to install NOx controls under the
State's 8-hour standard. The costs of those controls are included in the
$370 million cost estimate above. However, further technical analysis and
rulemaking may result in a requirement for additional controls at some
units. PEC cannot predict the outcome of this matter.
The EPA published a final rule approving petitions under Section 126 of the
Clean Air Act. This rule as originally promulgated required certain sources
to make reductions in NOx emissions by May 1, 2003. The final rule also
includes a set of regulations that affect NOx emissions from sources
included in the petitions. The North Carolina coal-fired electric
generating plants are included in these petitions. Acceptable state plans
under the NOx SIP Call can be approved in lieu of the final rules the EPA
approved as part of the 126 petitions. PEC, other utilities, trade
organizations and other states participated in litigation challenging the
EPA's action. On May 15, 2001, the District of Columbia Circuit Court of
Appeals ruled in favor of the EPA, which will require North Carolina to
make reductions in NOx emissions by May 1, 2003. However, the Court in its
May 15th decision rejected the EPA's methodology for estimating the future
growth factors the EPA used in calculating the emissions limits for
utilities. In August 2001, the Court granted a request by PEC and other
utilities to delay the implementation of the 126 Rule for electric
generating units pending resolution by the EPA of the growth factor issue.
The Court's order tolls the three-year compliance period (originally set to
end on May 1, 2003) for electric generating units as of May 15, 2001. On
April 30, 2002, the EPA published a final rule harmonizing the dates for
the Section 126 Rule and the NOx SIP Call. In addition, the EPA determined
in this rule that the future growth factor estimation methodology was
appropriate. The new compliance date for all affected sources is now May
31, 2004, rather than May 1, 2003. The EPA has approved North Carolina's
NOx SIP Call rule and has indicated it will rescind the Section 126 rule in
a future rulemaking. PEC expects a favorable outcome of this matter.
In June 2002, legislation was enacted in North Carolina requiring the
state's electric utilities to reduce the emissions of NOx and SO2 from
coal-fired power plants. PEC expects its capital costs to meet these
emission targets will be approximately $813 million by 2013. PEC has
expended approximately $30 million of these capital costs through December
31, 2003. PEC currently has approximately 5,100 MW of coal-fired generation
in North Carolina that is affected by this legislation. The legislation
requires the emissions reductions to be completed in phases by 2013, and
applies to each utility's total system rather than setting requirements for
individual power plants. The legislation also freezes the utilities' base
rates for five years unless there are extraordinary events beyond the
control of the utilities or unless the utilities persistently earn a return
substantially in excess of the rate of return established and found
reasonable by the NCUC in the utilities' last general rate case. Further,
the legislation allows the utilities to recover from their retail customers
the projected capital costs during the first seven years of the 10-year
compliance period beginning on January 1, 2003. The utilities must recover
159
at least 70% of their projected capital costs during the five-year rate
freeze period. Pursuant to the law, PEC entered into an agreement with the
state of North Carolina to transfer to the state all future emissions
allowances it generates from over-complying with the federal emission
limits when these units are completed. The law also requires the state to
undertake a study of mercury and carbon dioxide emissions in North
Carolina. Operation and maintenance costs will increase due to the
additional personnel, materials and general maintenance associated with the
equipment. Operation and maintenance expenses are recoverable through base
rates, rather than as part of this program. PEC cannot predict the future
regulatory interpretation, implementation or impact of this law.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
conveyed that mercury is not a risk to the average American and expressed
uncertainty about whether reductions in mercury emissions from coal-fired
power plants would reduce human exposure. Nevertheless, EPA determined in
2000 that regulation of mercury emissions from coal-fired power plants was
appropriate. In 2003, the EPA proposed two alternative control plans that
would limit mercury emissions from coal-fired power plants. The first, a
Maximum Available Control Technology (MACT) standard applicable to every
coal-fired plant, would require compliance in 2008. The second, a national
mercury cap and trade program, would require limits to be met in two
phases, 2010 and 2018. The mercury rule is expected to become final in
December 2004. Achieving compliance with either proposal could involve
significant capital costs which could be material to PEC's consolidated
financial position or results of operations. PEC cannot predict the outcome
of this matter.
In conjunction with the proposed mercury rule, the EPA proposed to regulate
nickel emissions from residual oil-fired units. The agency estimates the
proposal will reduce national nickel emissions to approximately 103 tons.
The rule is expected to become final in December 2004.
In December 2003, the EPA released its proposed Interstate Air Quality Rule
(commonly known as the Fine Particulate Transport Rule and/or the Regional
Transport Rule). The EPA's proposal requires 28 jurisdictions, including
North Carolina, South Carolina, Georgia and Florida, to further reduce NOx
and SO2 emissions in order to attain pre-set NOx and SO2 emissions levels
(which have not yet been determined). The rule is expected to become final
in 2004. The installation of controls necessary to comply with the rule
could involve significant capital costs.
Water Quality
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams will be
generated at the applicable facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and treatment challenges to PEC in the immediate
and extended future.
After many years of litigation and settlement negotiations the EPA
published regulations in February 2004 for the implementation of Section
316(b) of the Clean Water Act. The purpose of these regulations is to
minimize adverse environmental impacts caused by cooling water intake
structures and intake systems. Over the next several years these
regulations will impact the larger base load generation facilities and may
require the facilities to mitigate the effects to aquatic organisms by
constructing intake modifications or undertaking other restorative
activities. Substantial costs could be incurred by the facilities in order
to comply with the new regulation. The Company cannot predict the outcome
and impacts to the facilities at this time.
Other Environmental Matters
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. The United States has not adopted the Kyoto Protocol,
however, a number of carbon dioxide emissions control proposals have been
advanced in Congress and by the Bush administration. The Bush
administration favors voluntary programs. Reductions in carbon dioxide
emissions to the levels specified by the Kyoto Protocol and some
legislative proposals could be materially adverse to PEC's consolidated
financial position or results of operations if associated costs cannot be
recovered from customers. PEC favors the voluntary program approach
recommended by the administration and is evaluating options for the
reduction, avoidance, and sequestration of greenhouse gases. However, PEC
cannot predict the outcome of this matter.
2. As required under the Nuclear Waste Policy Act of 1982, PEC entered into
a contract with the DOE under which the DOE agreed to begin taking spent
nuclear fuel by no later than January 31, 1998. All similarly situated
utilities were required to sign the same standard contract.
160
In April 1995, the DOE issued a final interpretation that it did not have
an unconditional obligation to take spent nuclear fuel by January 31, 1998.
In Indiana Michigan Power v. DOE, the Court of Appeals vacated the DOE's
final interpretation and ruled that the DOE had an unconditional obligation
to begin taking spent nuclear fuel. The Court did not specify a remedy
because the DOE was not yet in default.
After the DOE failed to comply with the decision in Indiana Michigan Power
v. DOE, a group of utilities petitioned the Court of Appeals in Northern
States Power (NSP) v. DOE, seeking an order requiring the DOE to begin
taking spent nuclear fuel by January 31, 1998. The DOE took the position
that its delay was unavoidable, and the DOE was excused from performance
under the terms and conditions of the contract. The Court of Appeals did
not order the DOE to begin taking spent nuclear fuel, stating that the
utilities had a potentially adequate remedy by filing a claim for damages
under the contract.
After the DOE failed to begin taking spent nuclear fuel by January 31,
1998, a group of utilities filed a motion with the Court of Appeals to
enforce the mandate in NSP v. DOE. Specifically, this group of utilities
asked the Court to permit the utilities to escrow their waste fee payments,
to order the DOE not to use the waste fund to pay damages to the utilities,
and to order the DOE to establish a schedule for disposal of spent nuclear
fuel. The Court denied this motion based primarily on the grounds that a
review of the matter was premature, and that some of the requested remedies
fell outside of the mandate in NSP v. DOE.
Subsequently, a number of utilities each filed an action for damages in the
Federal Court of Claims. The U.S. Circuit Court of Appeals (Federal
Circuit) ruled that utilities may sue the DOE for damages in the Federal
Court of Claims instead of having to file an administrative claim with DOE.
On January 14, 2004, PEC filed a complaint with the United States Court of
Federal Claims against the United States of America (Department of Energy)
claiming that the DOE breached the Standard Contract for Disposal of Spent
Nuclear Fuel by failing to accept spent nuclear fuel from various Progress
Energy facilities on or before January 31, 1998. Damages due to DOE's
breach will likely exceed $100 million. Similar suits have been initiated
by over two dozen other utilities.
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. DOE plans to submit a license
application for the Yucca Mountain facility by the end of 2004. On November
5, 2003, Congressional negotiators approved $580 million for fiscal year
2004 for the Yucca Mountain project, $123 million more than the previous
year. PEC cannot predict the outcome of this matter.
With certain modifications and additional approval by the NRC, PEC's spent
nuclear fuel storage facilities will be sufficient to provide storage space
for spent fuel generated on its system through the expiration of the
current operating licenses for all of its nuclear generating units.
Subsequent to the expiration of these licenses, dry storage may be
necessary. PEC obtained NRC approval in December 2000 to use additional
storage space at the Harris Plant.
3. In August 2003, PEC was served as a co-defendant in a purported class
action lawsuit styled as Collins v. Duke Energy Corporation et al, Civil
action No. 03CP404050, in South Carolina's Circuit Court of Common Pleas
for the Fifth Judicial Circuit. PEC is one of three electric utilities
operating in South Carolina named in the suit. The plaintiffs are seeking
damages for the alleged improper use of electric easements but have not
asserted a dollar amount for their damage claims. The complaint alleges
that the licensing of attachments on electric utility poles, towers and
other structures to non-utility third parties or telecommunication
companies for other than the electric utilities' internal use along the
electric right-of-way constitutes a trespass.
In September 2003, PEC filed a motion to dismiss all counts of the
complaint on substantive and procedural grounds. In October 2003, the
plaintiffs filed a motion to amend their complaint. PEC believes the
amended complaint asserts the same factual allegations as are in the
original complaint and also seeks money damages and injunctive relief.
The court has not yet held any hearings or made any rulings in this case.
In November 2003, PEC filed a motion to dismiss the plaintiffs' first
amended complaint. PEC cannot predict the outcome of the outcome of this
matter, but will vigorously defend against the allegations.
161
4. PEC is involved in various litigation matters in the ordinary course of
business, some of which involve substantial amounts. Where appropriate,
accruals have been made in accordance with SFAS No. 5, "Accounting for
Contingencies," to provide for such matters. In the opinion of management,
the final disposition of pending litigation would not have a material
adverse effect on PEC's consolidated results of operations or financial
position.
162
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:
We have audited the consolidated balance sheets of Progress Energy, Inc. and its
subsidiaries at December 31, 2003 and 2002, and the related consolidated
statements of income, changes in common stock equity and cash flows for each of
the three years in the period ended December 31, 2003 and have issued our report
thereon dated February 20, 2004 (which expresses an unqualified opinion and
includes an explanatory paragraph concerning the adoption of new accounting
principles in 2003 and 2002); such consolidated financial statements and report
are included herein. Our audits also included the consolidated financial
statement schedule of the Company, listed in Item 8. This consolidated financial
statement schedule is the responsibility of the Company's management. Our
responsibility is to express an opinion based on our audits. In our opinion,
such consolidated financial statement schedule, when considered in relation to
the basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004
163
INDEPENDENT AUDITORS' REPORT
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:
We have audited the consolidated balance sheets of Carolina Power & Light
Company d/b/a Progress Energy Carolinas, Inc. and its subsidiaries (PEC) at
December 31, 2003 and 2002, and the related consolidated statements of income
and comprehensive income, retained earnings, and cash flows for each of the
three years in the period ended December 31, 2003 and have issued our report
thereon dated February 20, 2004 (which express an unqualified opinion and
includes an explanatory paragraph concerning the adoption of new accounting
principles in 2003); such consolidated financial statements and report are
included herein. Our audits also included the consolidated financial statement
schedule of PEC listed in Item 8. This consolidated financial statement schedule
is the responsibility of PEC's management. Our responsibility is to express an
opinion based on our audits. In our opinion, such consolidated financial
statement schedule, when considered in relation to the basic financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
/s/ DELOITTE & TOUCHE LLP
Raleigh, North Carolina
February 20, 2004
164
PROGRESS ENERGY, INC.
Schedule II - Valuation and Qualifying
Accounts For the Years Ended December 31,
2003, 2002 and 2001
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expenses Additions Deductions Period
- -------------------------------------------------------------------------------------------------------------------------
Year Ended
December 31, 2003
Uncollectible accounts $ 40 $ 26 $ - $ (38) (a) $ 28
Fossil dismantlement
reserve 142 1 - - 143
Nuclear refueling
outage reserve 10 8 - (16) (b) 2
Year Ended
December 31, 2002
Uncollectible accounts $ 39 $ 15 $ - $ (14) (a) $ 40
Fossil dismantlement
reserve 141 1 - - 142
Nuclear refueling
outage reserve - 10 - - 10
Year Ended
December 31, 2001
Uncollectible accounts $ 26 $ 12 $ 20 (c) $ (19) (a) $ 39
Fossil dismantlement
reserve 135 6 - - 141
Nuclear refueling
outage reserve 11 17 - (28) (b) -
(a) Represents write-off of uncollectible accounts, net of recoveries.
(b) Represents payments of actual expenditures related to the outages.
(c) Represents the reclassification of Rail Services' uncollectible accounts
from Net Assets Held for Sale.
- --------------------------------------------------------------------------------------------------------------------------
165
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS
Schedule II - Valuation and Qualifying
Accounts For the Years Ended December 31,
2003, 2002 and 2001
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expense Additions Deductions Period
- ----------------------------------------------------------------------------------------------------------------------
Year Ended
December 31, 2003
Uncollectible accounts $ 11 $ 12 $ - $ (10) (a) $ 13
Year Ended
December 31, 2002
Uncollectible accounts $ 12 $ 8 $ - $ (9) (a) $ 11
Year Ended
December 31, 2001
Uncollectible accounts $ 17 $ 4 $ - $ (9) (a) $ 12
(a) Represents write-off of uncollectible accounts, net of recoveries.
- --------------------------------------------------------------------------------------------------------------------------
166
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Progress Energy, Inc.
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, Progress
Energy carried out an evaluation, with the participation of its management,
including Progress Energy's Chairman and Chief Executive Officer and Chief
Financial Officer, of the effectiveness of Progress Energy's disclosure controls
and procedures (as defined under Rule 13a-15(e) under the Securities Exchange
Act of 1934) as of the end of the period covered by this report. Based upon that
evaluation, Progress Energy's Chief Executive Officer and Chief Financial
Officer concluded that its disclosure controls and procedures are effective in
timely alerting them to material information relating to Progress Energy
(including its consolidated subsidiaries) required to be included in its
periodic SEC filings.
There has been no change in Progress Energy's internal control over financial
reporting during the quarter ended December 31, 2003 that has materially
affected, or is reasonably likely to materially affect its internal control over
financial reporting.
Progress Energy Carolinas, Inc.
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, PEC
carried out an evaluation, with the participation of its management, including
PEC's Chairman and Chief Executive Officer and Chief Financial Officer, of the
effectiveness of PEC's disclosure controls and procedures (as defined under Rule
13a-15(e) under the Securities Exchange Act of 1934) as of the end of the period
covered by this report. Based upon that evaluation, PEC's Chief Executive
Officer and Chief Financial Officer concluded that its disclosure controls and
procedures are effective in timely alerting them to material information
relating to PEC (including its consolidated subsidiaries) required to be
included in its periodic SEC filings.
There has been no change in PEC's internal control over financial reporting
during the quarter ended December 31, 2003 that has materially affected, or is
reasonably likely to materially affect its internal control over financial
reporting.
167
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
a) Information on Progress Energy, Inc.'s directors is set forth in the
Progress Energy 2003 definitive proxy statement dated March 31, 2004, and
incorporated by reference herein. Information on PEC's directors is set
forth in the PEC 2003 definitive proxy statement dated March 31, 2004, and
incorporated by reference herein.
b) Information on both Progress Energy's and PEC's executive officers is set
forth in PART I and incorporated by reference herein.
c) The Company has adopted a Code of Ethics that applies to all of its
employees, including its Chief Executive Officer, Chief Financial Officer,
Chief Accounting Officer and Controller (or persons performing similar
functions). The Company's Board of Directors has adopted the Company's Code
of Ethics as its own standard. Board members, Company officers and Company
employees certify their compliance with the Code of Ethics on an annual
basis. The Company's Code of Ethics is posted on its Internet website and
can be accessed at www.progress-energy.com and is available in print to any
shareholder upon request by writing to Progress Energy, Inc.
The Company intends to satisfy the disclosure requirement under Item 10 of
Form 8-K relating to amendments to or waivers from any provision of the
Code of Ethics applicable to the Company's CEO, CFO, CAO and Controller by
posting such information on its Internet website, www.progress-energy.com.
d) The Board of Directors has determined that David L. Burner and Carlos A.
Saladrigas are the "Audit Committee Financial Experts" as that term is
defined in the rules promulgated by the Securities and Exchange Commission
pursuant to the Sarbanes-Oxley Act of 2002, and have designated them as
such. Both Mr. Burner and Mr. Saladrigas are "independent" as that term is
defined in the general independence standards of the New York Stock
Exchange listing standards.
e) The following are available on the Company's website and in print:
o Audit Committee Charter
o Corporate Governance Committee Charter
o Organization and Compensation Committee Charter
o Corporate Governance Guidelines
ITEM 11. EXECUTIVE COMPENSATION
Information on Progress Energy's executive compensation is set forth in the
Progress Energy 2003 definitive proxy statement dated March 31, 2004, and
incorporated by reference herein. Information on PEC's executive compensation is
set forth in the PEC 2003 definitive proxy statement dated March 31, 2004, and
incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
a) Information regarding any person Progress Energy knows to be the beneficial
owner of more than five (5%) percent of any class of its voting securities
is set forth in its 2003 definitive proxy statement, dated March 31, 2004,
and incorporated herein by reference.
Information regarding any person PEC knows to be the beneficial owner of
more than five (5%) percent of any class of its voting securities is set
forth in its 2003 definitive proxy statement, dated March 31, 2004, and
incorporated herein by reference.
b) Information on security ownership of the Progress Energy's and PEC's
management is set forth in the Progress Energy and PEC 2003 definitive
proxy statements dated March 31, 2004, and incorporated by reference
herein.
168
c) Information on the equity compensation plans of Progress Energy is set
forth under the heading "Equity Compensation Plan Information" in the
Progress Energy 2003 definitive proxy statement dated March 31, 2004 and
incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on certain relationships and related transactions is set forth in
the Progress Energy and PEC 2003 definitive proxy statements dated March 31,
2004, and incorporated by reference herein.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services is set forth in the
Progress Energy and PEC 2003 definitive proxy statements dated March 31, 2004,
and incorporated by reference herein.
169
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and
Supplementary Data
3. Exhibits Filed:
See EXHIBIT INDEX
b) Reports on Form 8-K or Form 8-K/A filed or furnished during or with
respect to the last quarter of 2003 and the portion of the first
quarter of 2004 prior to the filing of this Form 10-K:
Progress Energy, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed
-------- -------- ------------- ----------
12 Yes February 26, 2004 February 26, 2004
5 No February 24, 2004 February 24, 2004
5 No January 23, 2004 January 23, 2004
9, 12 Yes January 21, 2004 January 21, 2004
7, 9 Yes December 1, 2003 December 1, 2003
9, 12 Yes October 22, 2003 October 22, 2003
Progress Energy Carolinas, Inc.
Financial
Item Statements
Reported Included Date of Event Date Filed
-------- -------- ------------- ----------
12 Yes February 26, 2004 February 26, 2004
5 No January 23, 2004 January 23, 2004
9, 12 Yes January 21, 2004 January 21, 2004
9, 12 Yes October 22, 2003 October 22, 2003
170
PROGRESS ENERGY, INC. RISK FACTORS
In this section, unless the context indicates otherwise, references to "our,"
"we," "us" or similar terms refer to Progress Energy, Inc. and its consolidated
subsidiaries. Investing in our securities involves risks, including the risks
described below, that could affect the energy industry, as well as us and our
business. Although we have tried to discuss key factors, please be aware that
other risks may prove to be important in the future. New risks may emerge at any
time and we cannot predict such risks or estimate the extent to which they may
affect our financial performance. Before purchasing our securities, you should
carefully consider the following risks and the other information in this Annual
Report, as well as the documents we file with the SEC from time to time. Each of
the risks described below could result in a decrease in the value of our
securities and your investment therein.
Risks Related to the Energy Industry
We are subject to fluid and complex government regulations that may have a
negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal, state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are required
to have numerous permits, approvals and certificates from the agencies that
regulate our business. We believe the necessary permits, approvals and
certificates have been obtained for our existing operations and that our
business is conducted in accordance with applicable laws; however, we are unable
to predict the impact on our operating results from the future regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional regulations could have an adverse impact on our results of
operations.
The 108th Congress spent much of 2003 working on a comprehensive energy bill.
While that legislation passed the House, the Senate failed to pass the
legislation in 2003. There will probably be an effort to resurrect the
legislation in 2004. The legislation would have further clarified the Federal
Energy Regulatory Commission's (FERC) role with respect to Standard Market
Design and mandatory Regional Transmission Organizations (RTOs) and would have
repealed PUHCA. The Company cannot predict the outcome of this matter.
The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North
Carolina Utilities Commission ("NCUC"), the Florida Public Service Commission
("FPSC"), and the Public Service Commission of South Carolina ("SCPSC") regulate
many aspects of our utility operations, including siting and construction of
facilities, customer service and the rates that we can charge customers. Our
system is also subject to the jurisdiction of the SEC under the Public Utility
Holding Company Act of 1935 ("PUHCA"). The rules and regulations promulgated
under PUHCA impose a number of restrictions on the operations of registered
utility holding companies and their subsidiaries. These restrictions include a
requirement that, subject to a number of exceptions, the SEC approve in advance
securities issuances, acquisitions and dispositions of utility assets or of
securities of utility companies, and acquisitions of other businesses. PUHCA
also generally limits the operations of a registered holding company like ours
to a single integrated public utility system, plus additional energy-related
businesses. Furthermore, PUHCA rules require that transactions between
affiliated companies in a registered holding company system be performed at
cost, with limited exceptions.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.
We are subject to numerous environmental laws and regulations that may increase
our cost of operations, impact or limit our business plans, or expose us to
environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.
171
In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount or
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all PRPs.
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
Congress, FERC, and the state utility regulators have paid significant attention
in recent years to transmission issues, including the possibility of regional
transmission organizations. While these deliberations have not yet resulted in
significant changes to our utilities' transmission operations, they cast
uncertainty over those operations, which constitute a material portion of our
assets.
For the last several years, the FERC has supported independent RTOs and has
indicated a belief that it has the authority to order transmission-owning
utilities to transfer operational control of their transmission assets to such
RTOs. Many state regulators, including most regulators in the Southeast, have
expressed skepticism over the potential benefits of RTOs and generally disagree
with the FERC's interpretation of its authority to mandate RTOs.
In addition, in July 2002, the FERC issued its Notice of Proposed Rulemaking in
Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market Design ("SMD NOPR"). The
proposed rules set forth in the SMD NOPR would require, among other things, that
1) all transmission owning utilities transfer control of their transmission
facilities to an independent third party; 2) transmission service to bundled
retail customers be provided under the FERC-regulated transmission tariff,
rather than state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) load-serving
entities (LSEs) be required to meet minimum criteria for generating reserves. If
adopted as proposed, the rules set forth in the SMD NOPR would materially alter
the manner in which transmission and generation services are provided and paid
for. We filed comments in November 2002 and supplemental comments in January
2003. The FERC has not yet issued a final rule on SMD. Furthermore, the SMD NOPR
presents several uncertainties, including what percentage of our investments in
GridSouth and GridFlorida will be recovered, how the elimination of transmission
charges, as proposed in the SMD NOPR, will impact us, and what amount of capital
expenditures will be necessary to create a new wholesale market.
To date, our electric utilities have responded as follows:
o PEC and other investor-owned utilities filed applications with the FERC,
the NCUC and the SCPSC for approval of an RTO, currently named GridSouth.
However, PEC and the other GridSouth participants withdrew their RTO
application before the NCUC and the SCPSC pending the review of the FERC's
SMD NOPR. A determination about refiling will be made at a later date.
o PEF and other investor-owned utilities filed applications with the FERC and
the FPSC for approval of an RTO, currently named GridFlorida. The FERC
provisionally approved the structure and governance of GridFlorida. The
FPSC's most recent order in December 2003 ordered further state
proceedings.
The actual structure of GridSouth, GridFlorida or any alternative combined
transmission structure, as well as the date it may become operational, depends
upon the resolution of all regulatory approvals and technical issues. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, GridFlorida or an alternate combined transmission structure, we
cannot predict whether their creation will have any material adverse effect on
our future consolidated results of operations, cash flows or financial
condition.
Since weather conditions directly influence the demand for and cost of providing
electricity, our results of operations, financial condition, cash flows and
ability to pay dividends on our common stock can fluctuate on a seasonal or
quarterly basis and can be negatively affected by changes in weather conditions
and severe weather.
172
Our results of operations, financial condition, cash flows and ability to pay
dividends on our common stock may be affected by changing weather conditions.
Weather conditions in our service territories, primarily North Carolina, South
Carolina, and Florida, directly influence the demand for electricity affect the
price of energy commodities necessary to provide electricity to our customers
and energy commodities that our nonregulated businesses sell.
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
As a result, our overall operating results in the future may fluctuate
substantially on a seasonal basis. The pattern of this fluctuation may change
depending on the nature and location of facilities we acquire and the terms of
power sale contracts into which we enter. In addition, we have historically sold
less power, and consequently earned less income, when weather conditions are
milder. While we believe that our North Carolina, South Carolina, and Florida
markets complement each other during normal seasonal fluctuations, unusually
mild weather could diminish our results of operations and harm our financial
condition.
Furthermore, severe weather in these states, such as hurricanes, tornadoes,
severe thunderstorms and snow and ice storms, can be destructive, causing
outages, downed power lines and property damage, requiring us to incur
additional and unexpected expenses and causing us to lose generating revenues.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2003, commercial and industrial customers represented approximately
37% of our electric revenues. As a result, changes in the macroeconomy can have
negative impacts on our revenues. As our commercial and industrial customers
experience economic hardships, our revenues can be negatively impacted. In North
and South Carolina, sales to industrial customers have been affected by
downturns in the textile and chemical industries.
Deregulation or restructuring in the electric industry may result in increased
competition and unrecovered costs that could adversely affect the financial
condition, results of operations or cash flows of us and our utilities'
businesses.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on us and our utility subsidiaries
and consequently on our results of operations and cash flows. Increased
competition could also result in increased pressure to lower costs, including
the cost of electricity. Retail competition and the unbundling of regulated
energy and gas service could have a significant adverse financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower profit margins or increased costs of capital. Because we have not
previously operated in a competitive retail environment, we cannot predict the
extent and timing of entry by additional competitors into the electric markets.
Due to several factors, however, there currently is little discussion of any
movement toward deregulation in North Carolina, South Carolina and Florida. We
cannot predict when we will be subject to changes in legislation or regulation,
nor can we predict the impact of these changes on our financial condition,
results of operations or cash flows.
Risks Related to Us and Our Business
As a holding company, we are dependent on upstream cash flows from our
subsidiaries. As a result, our ability to meet our ongoing and future financial
obligations and to pay dividends on our common stock is primarily dependent on
the earnings and cash flows of our operating subsidiaries and their ability to
pay upstream dividends or to repay funds to us.
We are a holding company. As such, we have no operations of our own. Our ability
to meet our financial obligations and to pay dividends on our common stock at
the current rate is primarily dependent on the earnings and cash flows of our
operating subsidiaries and their ability to pay upstream dividends or to repay
funds to us. Prior to funding us, our subsidiaries have financial obligations
that must be satisfied, including among others, debt service, dividends and
obligations to trade creditors.
The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators. Accordingly, our profit
margins could be adversely affected if we or our utility subsidiaries do not
control operating costs.
173
The NCUC, the SCPSC and the FPSC each exercises regulatory authority for review
and approval of the retail electric power rates charged within its respective
state. State regulators may not allow our utility subsidiaries to increase
retail rates in the manner or to the extent requested by those subsidiaries.
State regulators may also seek to reduce retail rates. For example, in March
2002, PEF entered into a Stipulation and Settlement Agreement that required PEF,
among other things, to reduce its retail rates and to operate under a revenue
sharing plan through 2005 which provides for possible rate refunds to its retail
customers. The Agreement will also require increased capital expenditures for
PEF's Commitment to Excellence program. However, if PEF's base rate earnings
fall below a 10% return on equity, PEF may petition the FPSC to amend its base
rates. Additionally, a North Carolina law passed in 2002 froze PEC's base retail
rates for five years unless there are significant cost changes due to
governmental action, significant expenditures due to force majeure or other
extraordinary events beyond the control of PEC. The same legislation required a
significant increase in capital expenditures over the next several years for
clean air improvements. The cash costs incurred by our utility subsidiaries are
generally not subject to being fixed or reduced by state regulators. Our utility
subsidiaries will also require dedicated capital expenditures. Thus, our ability
to maintain our profit margins depends upon stable demand for electricity and
our efforts to manage our costs.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
We own and operate five nuclear units through our subsidiaries, PEC (four units)
and PEF (one unit), that represent approximately 4,220 megawatts, or 18%, of our
generation capacity. Our nuclear facilities are subject to environmental, health
and financial risks such as the ability to dispose of spent nuclear fuel, the
ability to maintain adequate capital reserves for decommissioning, potential
liabilities arising out of the operation of these facilities, and the costs of
securing the facilities against possible terrorist attacks. We maintain
decommissioning trusts and external insurance coverage to minimize the financial
exposure to these risks; however, it is possible that damages could exceed the
amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could require us to make substantial capital expenditures at our
nuclear plants. In addition, although we have no reason to anticipate a serious
nuclear incident at our plants, if an incident did occur, it could materially
and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.
Our facilities require licenses that need to be renewed or extended in order to
continue operating. We do not anticipate any problems renewing these licenses.
However, as a result of potential terrorist threats and increased public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.
Our financial performance depends on the successful operation of electric
generating facilities by our subsidiaries and our ability to deliver electricity
to our customers.
Operating electric generating facilities and delivery systems involves many
risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as fires, earthquakes, explosions, floods,
terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated from our subsidiaries' electric
generating facilities and electricity delivery systems or an increase in the
cost of operating the facilities could have an adverse effect on our business
and results of operations.
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
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We rely on access to both short-term money markets and long-term capital markets
as a significant source of liquidity for capital requirements not satisfied by
the cash flow from our operations. If we are not able to access capital at
competitive rates, our ability to implement our strategy will be adversely
affected. We believe that we will maintain sufficient access to these financial
markets based upon current credit ratings. However, certain market disruptions
or a downgrade of our credit rating may increase our cost of borrowing or
adversely affect our ability to access one or more financial markets. Such
disruptions could include:
o an economic downturn;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o market prices for electricity and gas;
o terrorist attacks or threatened attacks on our facilities or unrelated
energy companies; or
o the overall health of the utility industry.
Restrictions on our ability to access financial markets may affect our ability
to execute our business plan as scheduled. An inability to access capital may
limit our ability to pursue improvements or acquisitions that we may otherwise
rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
electric utilities. In addition to operating cash flows, we rely heavily on our
commercial paper and long-term debt. At December 31, 2003, commercial paper and
bank borrowings and long-term debt balances for Progress Energy and its
subsidiaries were as follows (in millions):
Outstanding Commercial Paper Total Long-Term
Company and Bank Borrowings Debt, Net
- ------------------ ----------------------------- -------------------
Progress Energy, unconsolidated (a) $ - $ 4,292
PEC 4 3,086
PEF - 1,879 (b)
Other Subsidiaries - 677 (c)
----------------------------- -------------------
Progress Energy, consolidated $ 4 $ 9,934 (b)(d)
(a) Represents solely the outstanding indebtedness of the holding company.
(b) On February 21, 2003, PEF issued $650.0 million aggregate principal amount
of its first mortgage bonds, the proceeds from which were or will be used
to reduce, redeem, or retire our outstanding long-term and short-term,
secured and unsecured, indebtedness.
(c) Includes the following subsidiaries: Progress Genco Ventures, LLC ($241
million), Florida Progress Funding Corporation ($270 million) and Progress
Capital Holdings, Inc. ($166 million).
(d) Net of current portion, which at December 31, 2003, was $868 million on a
consolidated basis.
Progress Energy and its subsidiaries have an aggregate of six committed credit
lines that support our commercial paper programs totaling $1.6 billion. While
our financial policy precludes us from issuing commercial paper in excess of our
credit lines, at December 31, 2003, we did not have any commercial paper
outstanding, leaving $1.6 billion available for future borrowing under our
credit lines.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios and minimum coverage ratios. Under the credit facilities, indebtedness
includes certain letters of credit and guarantees which are not recorded on our
consolidated Balance Sheets. At December 31, 2003, the maximum and actual ratios
were as follows:
Leverage Ratios Coverage Ratios
Company Maximum Ratio Actual Ratio Maximum Ratio Actual Ratio
------- ------------- ------------ ------------- ------------
Progress Energy 68% 61.5% 2.5:1 3.74:1
PEC 65% 51.4% n/a n/a
PEF 65% 51.5% 3.0:1 9.22:1
Genco 40% 24.6% 1.25:1 6.35:1
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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.
Furthermore, the credit lines of Progress Energy, PEC, PEF and Genco each
include provisions under which lenders could refuse to advance funds to each
company under their respective credit lines in the event of a material adverse
change in the respective company's financial condition. A limitation in our
liquidity could have a material adverse impact on our business strategy and our
ongoing financing needs.
Our indebtedness also includes several cross-default provisions which could
significantly impact our financial condition. Progress Energy's, PEC's, PEF's
and Genco's credit lines each include cross-default provisions for defaults of
indebtedness in excess of $10 million. Under these provisions, if the applicable
borrower or certain subsidiaries fail to pay various debt obligations in excess
of $10 million, the lenders could accelerate payment of any outstanding
borrowings and terminate their commitments to the credit facility. Progress
Energy's cross default provisions only apply to defaults of indebtedness by
Progress Energy and its significant subsidiaries (i.e., PEC, Florida Progress,
PEF, PCH, PVI and Progress Fuels). PEC's and PEF's cross-default provisions only
apply to defaults of indebtedness by PEC and PEF and their subsidiaries,
respectively, not other affiliates of PEC and PEF.
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, not its
subsidiaries. In the event that either of these cross-default provisions are
triggered, the debt holders could accelerate payment of approximately $4.8
billion in long-term debt. Any such acceleration would cause a material adverse
change in the respective company's financial condition. Certain agreements
underlying our indebtedness also limit our ability to incur additional liens or
engage in certain types of sale and leaseback transactions.
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o impacting our ability to pay dividends on our common stock at the current
rate;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it, for
working capital, acquisitions, debt service requirements or other purposes;
o increasing our vulnerability to adverse economic and industry conditions;
o requiring us to dedicate a substantial portion of our cash flow from
operations to payments on our debt, which would reduce funds available to
us for operations, future business opportunities or other purposes;
o limiting our flexibility in planning for, or reacting to, changes in our
business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors who
have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings could increase our borrowing costs, limit
our access to additional capital and require posting of collateral, all of which
could materially and adversely affect our business, results of operations and
financial condition.
In February 2003, Moody's announced that it was lowering Progress Energy's
senior unsecured debt rating from "Baa1" to "Baa2," and changing the outlook of
the rating from negative to stable. Moody's cited the slower than planned pace
of the Company's efforts to pay down debt from its acquisition of Florida
Progress as the primary reason for the ratings change. Moody's also changed the
outlook of PEF's senior secured debt from stable to negative. PEC's senior
unsecured debt has been assigned a rating by S&P of "BBB+" (negative outlook)
and by Moody's of "Baa1" (stable outlook). PEF's senior unsecured debt has been
assigned a rating by S&P of "BBB+" (negative outlook) and by Moody's of "A-2"
(stable outlook). In August 2003, Standard & Poor's Ratings Group (S&P), a
division of The McGraw-Hill Companies, Inc., announced that it had lowered its
corporate credit rating on Progress Energy Inc., PEC, PEF, and Florida Progress
to BBB from BBB+. The outlook of the ratings was changed from negative to
stable. While our nonregulated operations, including those conducted through our
Progress Ventures business unit, have a higher level of risk than our regulated
utility operations, we will seek to maintain a solid investment grade rating
through prudent capital management and financing structures. We cannot, however,
assure you that any of Progress Energy's current ratings, or those of PEC and
PEF, will remain in effect for any given period of time or that a rating will
not be lowered or withdrawn entirely by a rating agency if, in its judgment,
circumstances in the future so warrant. Any downgrade could increase our
borrowing costs and adversely affect our access to capital, which could
negatively impact our financial results. Further, we may be required to pay a
higher interest rate in future financings, and our potential pool of investors
and funding sources could decrease. Although we would have access to liquidity
176
under our committed and uncommitted credit lines, if our short-term rating were
to fall below A-2 or P-2, the current ratings assigned by S&P and Moody's,
respectively, it could significantly limit our access to the commercial paper
market. We note that the ratings from credit agencies are not recommendations to
buy, sell or hold our securities or those of PEC or PEF and that each rating
should be evaluated independently of any other rating.
Our energy marketing business relies on Progress Energy's investment grade
ratings to stand behind transactions in that business. At December 31, 2003,
Progress Energy has issued guarantees with a notional amount of approximately
$332 million to support CCO's energy marketing businesses. Based upon the amount
of trading positions outstanding at December 31, 2003, if Progress Energy's
ratings were to decline below investment grade, we would have to deposit cash or
provide letters of credit or other cash collateral for approximately $56 million
for the benefit of our counterparties. Additionally, the power supply agreement
with Jackson Electric Membership Corporation that PVI acquires from Williams
Energy Marketing and Trading Company includes a performance guarantee that
Progress Energy assumed. In the event that Progress Energy's credit ratings fall
below investment grade, Progress Energy will be required to provide additional
security for its guarantee in form and amount acceptable to Jackson, but not to
exceed the coverage amount. The coverage amount at the inception of PVI's power
sale to Jackson is $285 million and will decline over the life of the
transaction. At December 31, 2003, the coverage amount is $280 million. These
collateral requirements could adversely affect our profitability on energy
trading and marketing transactions and limit our overall liquidity.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
We could incur a significant tax liability, and our results of operations and
cash flows may be materially and adversely affected if the Internal Revenue
Service denies or otherwise makes unusable the Section 29 tax credits related to
our coal and synthetic fuels businesses.
Through our Fuels segment, we produce coal-based solid synthetic fuel. The
production and sale of the synthetic fuel from these facilities qualifies for
tax credits under Section 29 if certain requirements are satisfied, including a
requirement that the synthetic fuel differs significantly in chemical
composition from the coal used to produce such synthetic fuel and that the fuel
was produced from a facility that was placed in service before July 1, 1998. All
of our synthetic fuel facilities have received favorable private letter rulings
(PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic
fuel operations. These tax credits are subject to review by the IRS. In
September 2002, all of our majority-owned synthetic fuel entities were accepted
into the IRS' Pre-Filing Agreement (PFA) program. The PFA program allows
taxpayers to voluntarily accelerate the IRS examination process in order to seek
resolution of specific issues. Either we or the IRS can withdraw from the
program at any time, and issues not resolved through the program may proceed to
the next level of the IRS examination process. We believe that we operate in
conformity with all the necessary requirements to be allowed such credits under
Section 29. The current Section 29 tax credit program will expire at the end of
2007. With respect to any IRS review or audit of our synthetic fuel operations,
if we fail to prevail through the administrative or legal process, there could
be a significant tax liability owed for previously taken Section 29 credits or
we could lose our ability to claim future tax credits that we might otherwise be
able to benefit from both of which would significantly impact earnings and cash
flows.
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29 of the Internal Revenue Code. The investigation
generally relates to the utilization of the tax credits, the nature of the
technologies and fuels created, the use of the synthetic fuel, and other aspects
of Section 29 and is not specific to our synthetic fuel operations. We are
providing information in connection with this investigation as requested.
There are risks involved with the operation of our nonregulated plants,
including dependence on third parties and related counter-party risks, and a
lack of operating history, all of which may make our wholesale generation and
overall operations less profitable and more unstable.
177
At December 31, 2003, we had approximately 3,100 megawatts of nonregulated
generation in commercial operation.
The operation of wholesale generation facilities is subject to many risks,
including those listed below. During the execution of our wholesale generation
strategy, these risks will intensify. These risks include:
o We may enter into or otherwise acquire long-term contracts that take effect
at a future date based upon our current expectations of our future
wholesale generation capacity. If our expected future capacity does not
meet our expectations, we may not be able to meet our obligations under any
such long-term contracts and may have to purchase power in the spot market
at then prevailing prices. Accordingly, we may lose current and future
customers, impair our ability to implement our wholesale strategy, and
suffer reputational harm. Additionally, if we are unable to secure
favorable pricing in the spot market, our results of operations may be
diminished. We may also become liable under any related performance
guarantees then in existence.
o Our wholesale facilities depend on third parties through power purchase
agreements, fuel supply and transportation agreements, and transmission
grid connection agreements. If such third parties breach their obligations
to us, our revenues, financial condition, cash flow and ability to make
payments of interest and principal on our outstanding debts may be
impaired. Any material breach by any of these parties of their obligations
under the project contracts could adversely affect our cash flows and could
impair our ability to make payments of principal of and interest on our
indebtedness.
o We depend on transmission and distribution facilities owned and operated by
utilities and other energy companies to deliver the electricity and natural
gas that we sell to the wholesale market. If transmission is disrupted, or
if capacity is inadequate, our ability to sell and deliver products and
satisfy our contractual obligations may be hindered. Although the FERC has
issued regulations designed to encourage competition in wholesale market
transactions for electricity, there is the potential that fair and equal
access to transmission systems will not be available or that sufficient
transmission capacity will not be available to transmit electric power as
we desire. We cannot predict the timing of industry changes as a result of
these initiatives or the adequacy of transmission facilities in specific
markets.
o Agreements with our counter-parties frequently will include the right to
terminate and/or withhold payments or performance under the contracts if
specific events occur. If a project contract were to be terminated due to
nonperformance by us or by the other party to the contract, our ability to
enter into a substitute agreement having substantially equivalent terms and
conditions is uncertain.
o Because many of our facilities are newly constructed and have no
significant operating history, various unexpected events may increase our
expenses or reduce our revenues and impair our ability to service the
related project debt. As with any new business venture of this size and
nature, operation of our facility could be affected by many factors,
including start-up problems, the breakdown or failure of equipment or
processes, the performance of our facility below expected levels of output
or efficiency, failure to operate at design specifications, labor disputes,
changes in law, failure to obtain necessary permits or to meet permit
conditions, government exercise of eminent domain power or similar events
and catastrophic events including fires, explosions, earthquakes and
droughts.
o Our facilities seek to enter into long-term power purchase agreements to
sell all or a portion of their generating capacity. Currently, the
percentage of our anticipated nonregulated capacity that will be under
contract is as follows: 2004--85%, 2005--50% and 2006--50%. Following the
expiration or early termination of our power purchase agreements, or to the
extent we cannot otherwise secure contracts for our current and future
generation capacity, our facilities will generally become merchant
facilities. Our merchant facilities may not be able to find adequate
purchasers, attain favorable pricing, or otherwise compete effectively in
the wholesale market. Additionally, numerous legal and regulatory
limitations restrict our ability to operate a facility on a wholesale
basis.
Our energy marketing and trading operations are subject to risks that may reduce
our revenues and adversely impact our results of operations and financial
condition, many of which are beyond our control.
Our fleet of nonregulated plants may sell energy into the spot market or other
competitive power markets or on a contractual basis. We may also enter into
contracts to purchase and sell electricity, natural gas and coal as part of our
power marketing and energy trading operations. Our business may also include
entering into long-term contracts that supply customers' full electric
requirements. These contracts do not guarantee us any rate of return on our
178
capital investments through mandated rates, and our revenues and results of
operations from these contracts are likely to depend, in large part, upon
prevailing market prices for power in our regional markets and other competitive
markets. These market prices can fluctuate substantially over relatively short
periods of time. Trading margins may erode as markets mature, and should
volatility decline, we may have diminished opportunities for gain.
In particular, we believe that over the past few years, the Southeastern
wholesale energy market has been overbuilt and accordingly believe that supply
exceeds demand. Due to this overbuilding, we believe that spot prices as well as
contractual pricing will provide us with a reduced rate of return on our capital
investment and our revenues and results of operations from this market will be
lower than originally expected unless and until demand catches up with supply.
In addition, the Enron Corporation bankruptcy and enhanced regulatory scrutiny
have contributed to more rigorous credit rating review of participants in the
energy marketing and trading business. Credit downgrades of certain other market
participants have significantly reduced such participants' participation in the
wholesale power markets. These events are causing a decrease in the number of
significant participants in the wholesale power markets, which could result in a
decrease in the volume and liquidity in the wholesale power markets. We are
unable to predict the impact of such developments on our power marketing and
trading business.
Furthermore, the FERC, which has jurisdiction over wholesale power rates, as
well as ISOs that oversee some of these markets, may impose price limitations,
bidding rules and other mechanisms to address some of the volatility in these
markets. Fuel prices also may be volatile, and the price we can obtain for power
sales may not change at the same rate as fuel costs changes. These factors could
reduce our margins and therefore diminish our revenues and results of
operations.
Volatility in market prices for fuel and power may result from:
o weather conditions;
o seasonality;
o power usage;
o illiquid markets;
o transmission or transportation constraints or inefficiencies;
o availability of competitively priced alternative energy sources;
o demand for energy commodities;
o natural gas, crude oil and refined products, and coal production
levels;
o natural disasters, wars, embargoes and other catastrophic events; and
o federal, state and foreign energy and environmental regulation and
legislation.
We actively manage the market risk inherent in our energy marketing operations.
Nonetheless, adverse changes in energy and fuel prices may result in losses in
our earnings or cash flows and adversely affect our balance sheet. Our marketing
and risk management procedures may not work as planned. As a result, we cannot
predict with precision the impact that our marketing, trading and risk
management decisions may have on our business, operating results or financial
position. In addition, to the extent that we do not cover the entire exposure of
our assets or our positions to market price volatility, or our hedging
procedures do not work as planned, fluctuating commodity prices could cause our
sales and net income to be volatile.
179
PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS
In this section, references to "we," "our," "us" or similar terms are to
Progress Energy Carolinas, Inc. and its consolidated subsidiaries. Investing in
our securities involves risks, including the risks described below, that could
affect the energy industry, as well as us and our business. Although we have
tried to discuss key factors, please be aware that other risks may prove to be
important in the future. New risks may emerge at any time and we cannot predict
such risks or estimate the extent to which they may affect our financial
performance. Before purchasing our securities, you should carefully consider the
following risks and the other information in this Annual Report, as well as
documents we file with the SEC from time to time. Each of the risks described
below could result in a decrease in the value of our securities and your
investment therein.
Risks Related to the Energy Industry
We are subject to fluid and complex government regulations that may have a
negative impact on our business and our results of operations.
We are subject to comprehensive regulation by several federal and state
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are required
to have numerous permits, approvals and certificates from the agencies that
regulate our business. We believe the necessary permits, approvals and
certificates have been obtained for our existing operations and that our
business is conducted in accordance with applicable laws; however, we are unable
to predict the impact on our operating results from the future regulatory
activities of any of these agencies. Changes in regulations or the imposition of
additional regulations could have an adverse impact on our results of
operations.
The Federal Energy Regulatory Commission ("FERC"), the U.S. Nuclear Regulatory
Commission ("NRC"), the U.S. Environmental Protection Agency ("EPA"), the North
Carolina Utilities Commission ("NCUC") and the Public Service Commission of
South Carolina ("SCPSC") regulate many aspects of our utility operations,
including siting and construction of facilities, customer service and the rates
that we can charge customers. Although we are not a registered holding company
under the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), we
are subject to many of the regulatory provisions of PUHCA.
We are a wholly-owned subsidiary of Progress Energy, Inc., a registered public
utility holding company under PUHCA. Repeal of PUHCA has been proposed, but it
is unclear whether or when such a repeal would occur. It is also unclear to what
extent repeal of PUHCA would result in additional or new regulatory oversight or
action at the federal or state levels, or what the impact of those developments
might be on our business.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal and state agencies. Changes in
regulations or the imposition of additional regulations could have a negative
impact on our business and results of operations.
We are subject to numerous environmental laws and regulations that may increase
our cost of operations, impact or limit our business plans, or expose us to
environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste, and hazardous waste. These laws and
regulations can result in increased capital, operating and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
financial or operational outcome of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount and
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all PRPs.
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
180
Deregulation or restructuring in the electric utility industry may result in
increased competition and unrecovered costs that could adversely affect our
financial condition, results of operations and cash flows.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on our results of operations and
cash flows. Increased competition could also result in increased pressure to
lower rates. Retail competition and the unbundling of regulated energy and gas
service could have a significant adverse financial impact on us due to an
impairment of assets, a loss of retail customers, lower profit margins or
increased costs of capital. Because we have not previously operated in a
competitive retail environment, we cannot predict the extent and timing of entry
by additional competitors into the electric markets. Due to several factors,
however, there currently is little discussion of any movement toward
deregulation in North Carolina and South Carolina. We cannot predict when we
will be subject to changes in legislation or regulation, nor can we predict the
impact of these changes on our financial condition, results of operations or
cash flows.
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
For the last several years, the FERC has supported independent RTOs and has
indicated a belief that it has the authority to order transmission-owning
utilities to transfer operational control of their transmission assets to
participate in such RTOs. Many state regulators, including most regulators in
the Southeast, have expressed skepticism over the potential benefits of RTOs and
generally disagree with the FERC's interpretation of its authority to mandate
RTOs.
In addition, in July 2002, the FERC issued its Notice of Proposed Rulemaking in
Docket No. RM01-12-000, Remedying Undue Discrimination through Open Access
Transmission Service and Standard Electricity Market Design ("SMD NOPR"). The
proposed rules set forth in the SMD NOPR would require, among other things, that
1) all transmission owning utilities transfer control of their transmission
facilities to an independent third party; 2) transmission service to bundled
retail customers be provided under the FERC- regulated transmission tariff,
rather than state-mandated terms and conditions; 3) new terms and conditions for
transmission service be adopted nationwide, including new provisions for pricing
transmission in the event of transmission congestion; 4) new energy markets be
established for the buying and selling of electric energy; and 5) LSEs be
required to meet minimum criteria for generating reserves. If adopted as
proposed, the rules set forth in the SMD NOPR would materially alter the manner
in which transmission and generation services are provided and paid for.
Progress Energy, Inc. filed comments on the SMD NOPR in November 2002 and
supplemental comments in January 2003. The FERC has not yet issued a final rule
on SMD. Furthermore, the SMD NOPR presents several uncertainties, including what
percentage of our investments in GridSouth will be recovered, how the
elimination of transmission charges, as proposed in the SMD NOPR, will impact
us, and what amount of capital expenditures will be necessary to create a new
wholesale market.
In response, PEC and other investor-owned utilities filed applications with the
FERC, the NCUC and the SCPSC for approval of an RTO, currently named GridSouth.
However, PEC and the other GridSouth participants withdrew their RTO application
before the NCUC and the SCPSC pending the review of the FERC's SMD NOPR. A
determination about refilling will be made at a later date.
The actual structure of GridSouth or any alternative combined transmission
structure, as well as the date it may become operational, depends upon the
resolution of all regulatory approvals and technical issues. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, or an alternate combined transmission structure, we cannot predict
whether their creation will have any material adverse effect on our future
consolidated results of operations, cash flows or financial condition.
Since weather conditions directly influence the demand for and cost of providing
electricity, our results of operations, financial condition and cash flows can
fluctuate on a seasonal or quarterly basis and can be negatively affected by
changes in weather conditions and severe weather.
Our results of operations, financial condition and cash flows may be affected by
changing weather conditions. Weather conditions in our service territories
directly influence the demand for electricity and affect the price of energy
commodities necessary to provide electricity to our customers.
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change depending on the nature and location
181
of facilities we acquire and the terms of power sale contracts into which we
enter. In addition, we have historically sold less power, and consequently
earned less income, when weather conditions are milder. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.
Furthermore, severe weather in North Carolina and South Carolina, such as
hurricanes, tornadoes, severe thunderstorms and snow and ice storms, can be
destructive, causing outages, downed power lines and property damage, requiring
us to incur additional and unexpected expenses and causing us to lose generating
revenues.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2003, commercial and industrial customers represented approximately
24% and 18% of our electric revenues, respectively. As a result, changes in the
macroeconomy can have negative impacts on our revenues. As our commercial and
industrial customers experience economic hardships, our revenues can be
negatively impacted.
Risks Related to Us and Our Business
Under a North Carolina law passed in 2002, our base rates are frozen for five
years and we are required to increase capital expenditures for clean air
improvements. Accordingly, our profit margin could be adversely affected if we
do not control operating costs.
The NCUC and the SCPSC each exercises regulatory authority for review and
approval of the retail electric power rates charged within its respective state.
State regulators may not allow us to increase retail rates in the manner or to
the extent we request. State regulators may also seek to reduce retail rates. A
North Carolina law passed in 2002 froze our base retail rates for five years
unless there are significant cost changes due to governmental action,
significant expenditures due to force majeure or other extraordinary events
beyond our control. That same legislation required a significant increase in
capital expenditures over the next several years for clean air improvements. The
cash costs incurred by us are generally not subject to being fixed or reduced by
state regulators. We will also require dedicated capital expenditures. Thus, our
ability to maintain our profit margins depends upon stable demand for
electricity and our efforts to manage our costs.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
We own and operate four nuclear units that represent approximately 3,382
megawatts, or approximately 27%, of our generation capacity. Our nuclear
facilities are subject to environmental, health and financial risks such as the
ability to dispose of spent nuclear fuel, the ability to maintain adequate
capital reserves for decommissioning, potential liabilities arising out of the
operation of these facilities, and the costs of securing the facilities against
possible terrorist attacks. We maintain a decommissioning trust and external
insurance coverage to minimize the financial exposure to these risks; however,
it is possible that damages could exceed the amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down any of our units, or both, depending upon its assessment of the
severity of the situation, until compliance is achieved. Revised safety
requirements promulgated by the NRC could require us to make substantial capital
expenditures at our nuclear plants. In addition, although we have no reason to
anticipate a serious nuclear incident at any of our plants, if an incident did
occur, it could materially and adversely affect our results of operations or
financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.
Our facilities require licenses that need to be renewed or extended in order to
continue operating. We do not anticipate any problems renewing these licenses.
However, as a result of potential terrorist threats and increased public
scrutiny of utilities, the licensing process could result in increased licensing
or compliance costs that are difficult or impossible to predict.
Our financial performance depends on the successful operation of our electric
generating facilities and our ability to deliver electricity to our customers.
182
Operating electric generating facilities and delivery systems involves many
risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as fires, earthquakes, explosions, floods,
terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated from our electric generating
facilities and electricity delivery systems or an increase in the cost of
operating the facilities could have an adverse effect on our business and
results of operations.
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
We rely on access to both short-term money markets and long-term capital markets
as a significant source of liquidity for capital requirements not satisfied by
the cash flow from our operations. If we are not able to access capital at
competitive rates, our ability to implement our business operations will be
adversely affected. We believe that we will maintain sufficient access to these
financial markets based upon current credit ratings. However, certain market
disruptions or a downgrade of our credit rating may increase our cost of
borrowing or adversely affect our ability to access one or more financial
markets. Such disruptions could include:
o an economic downturn;
o a ratings downgrade of Progress Energy, Inc.;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o market prices for electricity;
o terrorist attacks or threatened attacks on our facilities or those of
unrelated energy companies; or
o the overall health of the utility industry.
Restrictions on our ability to access financial markets may affect our ability
to execute our business plan as scheduled. An inability to access capital may
limit our ability to pursue improvements or acquisitions that we may otherwise
rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and ability to access capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
business. In addition to operating cash flows, we rely heavily on our commercial
paper and long-term debt. At December 31, 2003, our commercial paper balance was
zero, we had $25 million notes payable to affiliated companies and our long-term
debt balances were approximately $3.1 billion (with current portion of long-term
debt of $300 million at December 31, 2003).
We have a committed credit line that supports our commercial paper programs and
matures in July 2005. At December 31, 2003, we had no outstanding borrowings
under this line.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios. At December 31, 2003, the maximum and actual ratios, pursuant to the
terms of the credit facilities, were 65% and 51.4%, respectively. Indebtedness,
as defined under the credit facility agreements, includes certain letters of
credit and guarantees that are not recorded on our balance sheets.
In the event our capital structure changes such that we approach the permitted
ratios, our access to capital and additional liquidity could decrease.
Furthermore, our credit lines include provisions under which lenders could
refuse to advance funds to us in the event of a material adverse change in our
financial condition. A limitation in our liquidity could have a material adverse
impact on our business strategy and our ongoing financing needs.
183
Our indebtedness also includes cross-default provisions which could
significantly impact our financial condition. Our credit lines include
cross-default provisions for defaults of indebtedness in excess of $10 million.
Under these provisions, if the applicable borrower fails to pay various debt
obligations in excess of $10 million, the lenders could accelerate payment of
any outstanding borrowings and terminate their commitments to the credit
facility. Our cross-default provisions only apply to defaults on our
indebtedness, but not defaults by our affiliates. In the event that a
cross-default provision was triggered, our lenders could accelerate payment of
any outstanding debt. Any such acceleration would cause a material adverse
change in our financial condition.
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it,
for working capital, acquisitions, debt service requirements or other
purposes;
o increasing our vulnerability to adverse economic and industry
conditions; o requiring us to dedicate a substantial portion of our
cash flow from operations to payments on our debt, which would reduce
funds available to us for operations, future business opportunities or
other purposes;
o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors
who have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings could increase our borrowing costs and limit
our access to additional capital, which could materially and adversely affect
our business, results of operations and financial condition.
Our senior secured debt has been assigned a rating by Standard & Poor's Ratings
Group, a division of The McGraw Hill Companies, Inc., of "BBB+" (negative
outlook) and by Moody's Investors Service, Inc. of "A3" (stable outlook). Our
senior unsecured debt rating has been assigned a rating by S&P of "BBB+"
(negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's
rating philosophy links the ratings of a utility subsidiary to the credit rating
of its parent corporation. Accordingly, if S&P were to downgrade Progress
Energy, Inc.'s credit ratings, our credit rating would also likely be
downgraded, regardless of whether or not we had experienced any change in our
business operations or financial conditions. We will seek to maintain a solid
investment grade rating through prudent capital management and financing
structures. We cannot, however, assure you that our current ratings will remain
in effect for any given period of time or that our ratings will not be lowered
or withdrawn entirely by a rating agency if, in its judgment, circumstances in
the future so warrant. Any downgrade could increase our borrowing costs and
adversely affect our access to capital, which could negatively impact our
financial results. Further, we may be required to pay a higher interest rate in
future financings, and our potential pool of investors and funding sources could
decrease. Although we would have access to liquidity under our committed and
uncommitted credit lines, if our short-term rating were to fall below "A-2" or
"P-2," the current ratings assigned by S&P and Moody's, respectively, it could
significantly limit our access to the commercial paper market. We note that the
ratings from credit agencies are not recommendations to buy, sell or hold our
securities and that each rating should be evaluated independently of any other
rating.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
184
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrants have duly caused this report to be signed on their
behalf by the undersigned, thereunto duly authorized.
PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY
Date: March 12, 2004 (Registrants)
By: /s/Robert B. McGehee
------------------------------------
Robert B. McGehee
Chief Executive Officer
Progress Energy, Inc.
By: /s/Fred N. Day IV
------------------------------------
Fred N. Day IV
President and Chief Executive Officer
Carolina Power & Light Company
By: /s/Geoffrey S. Chatas
------------------------------------
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer
Progress Energy, Inc.
Carolina Power & Light Company
By: /s/Robert H. Bazemore, Jr.
------------------------------------
Robert H. Bazemore, Jr.
Vice President and Controller
(Chief Accounting Officer)
Progress Energy, Inc.
Carolina Power & Light Company
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
/s/ William Cavanaugh III Director March 12, 2004
- -------------------------
(William Cavanaugh III,
Chairman)
/s/ Edwin B. Borden Director March 12, 2004
- --------------------
(Edwin B. Borden)
/s/ James E. Bostic, Jr. Director March 12, 2004
- ------------------------
(James E. Bostic, Jr.)
/s/ David L. Burner Director March 12, 2004
- --------------------
(David L. Burner)
185
/s/ Charles W. Coker Director March 12, 2004
- ---------------------
(Charles W. Coker)
/s/ Richard L. Daugherty Director March 12, 2004
- -------------------------
(Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 12, 2004
- ------------------------
(W.D. Frederick, Jr.)
/s/ William O. McCoy Director March 12, 2004
- ---------------------
(William O. McCoy)
/s/ E. Marie McKee Director March 12, 2004
- -------------------
(E. Marie McKee)
/s/ John H. Mullin, III Director March 12, 2004
- ------------------------
(John H. Mullin, III)
/s/ Richard A. Nunis Director March 12, 2004
- ---------------------
(Richard A. Nunis)
/s/Peter S. Rummell Director March 12,2004
- -------------------
(Peter S. Rummell)
/s/ Carlos A. Saladrigas Director March 12, 2004
- -------------------------
(Carlos A. Saladrigas)
/s/ J. Tylee Wilson Director March 12, 2004
- --------------------
(J. Tylee Wilson)
/s/ Jean Giles Wittner Director March 12, 2004
- -----------------------
(Jean Giles Wittner)
EXHIBIT INDEX
Progress
Number Exhibit Energy, Inc. PEC
*2(a) Agreement and Plan of Merger By and Among Carolina Power X
& Light Company, North Carolina Natural Gas Corporation
and Carolina Acquisition Corporation, dated as of
November 10, 1998 (filed as Exhibit No. 2(b) to Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 1998, File No. 1-3382.)
*2(b) Agreement and Plan of Merger by and among Carolina Power X
& Light Company, North Carolina Natural Gas Corporation
and Carolina Acquisition Corporation, Dated as of
November 10, 1998, as Amended and Restated as of April
22, 1999 (filed as Exhibit 2 to Quarterly Report on Form
10-Q for the quarterly period ended March 31, 1999, File
No. 1-3382).
*2(c) Agreement and Plan of Exchange, dated as of August 22, X X
1999, by and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Holdings, Inc.
(filed as Exhibit 2.1 to Current Report on Form 8-K dated
August 22, 1999, File No. 1-3382).
*2(d) Amended and Restated Agreement and Plan of Exchange, by X X
and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Energy, Inc., dated as of
August 22, 1999, amended and restated as of March 3, 2000
(filed as Annex A to Joint Preliminary Proxy Statement of
Carolina Power & Light Company and Florida Progress
Corporation dated March 6, 2000, File No. 1-3382).
*3a(1) Restated Charter of Carolina Power & Light Company, as X
amended May 10, 1995 (filed as Exhibit No. 3(i) to Quarterly
Report on Form 10-Q for the quarterly period ended June 30,
1995, File No. 1-3382).
*3a(2) Restated Charter of Carolina Power & Light Company as X
amended on May 10, 1996 (filed as Exhibit No. 3(i) to
Quarterly Report on Form 10-Q for the quarterly period ended
June 30, 1997, File No. 1-3382).
*3a(3) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on June 15, 2000
(filed as Exhibit No. 3a(1) to Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000, File
No. 1-15929 and No. 1-3382).
187
*3b(1) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on December 4, 2000
(filed as Exhibit 3b(1) to Annual Report on Form 10-K dated
March 28, 2002, File No. 1-3392 and 1-15929).
*3b(2) By-Laws of Carolina Power & Light Company, as amended on X
December 12, 2001 (filed as Exhibit 3b(2) to Annual Report on
Form 10-K dated March 28, 2002, File No. 1-3382 and 1-15929).
*3b(3) By-Laws of Progress Energy, Inc., as amended and restated X
December 12, 2001 (filed as Exhibit No. 3 to Current Report on
Form 8-K dated January 17, 2002, File No. 1-15929).
*4a(1) Resolution of Board of Directors, dated December 8, 1954, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
Carolina Power & Light Company's Serial Preferred Stock,
$4.20 Series (filed as Exhibit 3(c), File No. 33-25560).
*4a(2) Resolution of Board of Directors, dated January 17, 1967, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
Carolina Power & Light Company's Serial Preferred Stock,
$5.44 Series (filed as Exhibit 3(d), File No. 33-25560).
*4a(3) Statement of Classification of Shares dated January 13, X
1971, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for Carolina Power & Light Company's Serial Preferred
Stock, $7.95 Series (filed as Exhibit 3(f), File No. 33-25560).
*4a(4) Statement of Classification of Shares dated September 7, X
1972, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for Carolina Power & Light Company's Serial Preferred
Stock, $7.72 Series (filed as Exhibit 3(g), File No. 33-25560).
*4b(1) Mortgage and Deed of Trust dated as of May 1, 1940 between X
Carolina Power & Light Company and The Bank of New York formerly,
Irving Trust Company) and Frederick G. Herbst (Douglas J.
MacInnes, Successor), Trustees and the First through
Fifth Supplemental Indentures thereto (Exhibit 2(b), File
No. 2-64189); the Sixth through Sixty-sixth Supplemental
Indentures (Exhibit 2(b)-5, File No. 2-16210; Exhibit
2(b)-6, File No. 2-16210; Exhibit 4(b)-8, File No.
2-19118; Exhibit 4(b)-2, File No. 2-22439; Exhibit
4(b)-2, File No. 2-24624; Exhibit 2(c), File No. 2-27297;
Exhibit 2(c), File No. 2-30172; Exhibit 2(c), File No.
2-35694; Exhibit 2(c), File No. 2-37505; Exhibit 2(c),
File No. 2-39002; Exhibit 2(c), File No. 2-41738; Exhibit
2(c), File No. 2-43439; Exhibit 2(c), File No. 2-47751;
Exhibit 2(c), File No. 2-49347; Exhibit 2(c), File
No. 2-53113; Exhibit 2(d), File No. 2-53113; Exhibit
2(c), File No. 2-59511; Exhibit 2(c), File No. 2-61611;
Exhibit 2(d), File No. 2-64189; Exhibit 2(c), File
No. 2-65514; Exhibits 2(c) and 2(d), File No. 2-66851;
Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File No. 2-81299;
Exhibits 4(c)-1 through 4(c)-8, File No. 2-95505;
Exhibits 4(b) through 4(h), File No. 33-25560; Exhibits
188
4(b) and 4(c), File No. 33-33431; Exhibits 4(b) and 4(c),
File No. 33-38298; Exhibits 4(h) and 4(i), File No.
33-42869; Exhibits 4(e)-(g), File No. 33-48607; Exhibits
4(e) and 4(f), File No. 33-55060; Exhibits 4(e) and 4(f),
File No. 33-60014; Exhibits 4(a) and 4(b) to
Post-Effective Amendment No. 1, File No. 33-38349;
Exhibit 4(e), File No. 33-50597; Exhibit 4(e) and 4(f),
File No. 33-57835; Exhibit to Current Report on Form 8-K
dated August 28, 1997, File No. 1-3382; Form of Carolina
Power & Light Company First Mortgage Bond, 6.80% Series
Due August 15, 2007 filed as Exhibit 4 to Form 10-Q for
the period ended September 30, 1998, File No. 1-3382;
Exhibit 4(b), File No. 333-69237; and Exhibit 4(c) to
Current Report on Form 8-K dated March 19, 1999, File No.
1-3382.); and the Sixty-eighth Supplemental Indenture
(Exhibit No. 4(b) to Current Report on Form 8-K dated
April 20, 2000, File No. 1-3382; and the Sixty-ninth
Supplemental Indenture (Exhibit No. 4b(2) to Annual
Report on Form 10-K dated March 29, 2001, File No.
1-3382); and the Seventieth Supplemental Indenture,
(Exhibit 4b(3) to Annual Report on Form 10-K dated March
29, 2001, File No. 1-3382); and the Seventy-first
Supplemental Indenture (Exhibit 4b(2) to Annual Report on
Form 10-K dated March 28, 2002).
*4b(2) Seventy-second Supplemental Indenture, dated as of X
September 1, 2003, to PEC Mortgage and Deed of Trust
dated May 1, 1940, between PEC and The Bank of New York
and Douglas J. MacInnes, as Trustees (filed as Exhibit 4
to PEC Report on Form 8-K dated September 12, 2003, File
No.1-03382).
*4c(1) Indenture, dated as of February 15, 2001, between X
Progress Energy, Inc. and Bank One Trust Company, N.A.,
as Trustee, with respect to Senior Notes (filed as
Exhibit 4(a) to Form 8-K dated February 27, 2001, File
No. 1-15929).
*4c(2) Indenture, dated as of March 1, 1995, between Carolina X
Power & Light Company Bankers Trust Company, as Trustee,
with respect to Unsecured Subordinated Debt Securities
(filed as Exhibit No. 4(c) to Current Report on Form 8-K
dated April 13, 1995, File No. 1-3382).
*4c(3) Resolutions adopted by the Executive Committee of the X
Board of Directors at a meeting held on April 13, 1995,
establishing the terms of the 8.55% Quarterly Income
189
Capital Securities (Series A Subordinated Deferrable
Interest Debentures) (filed as Exhibit 4(b) to Current
Report on Form 8-K dated April 13, 1995, File No. 1-3382).
*4d Indenture (for Senior Notes), dated as of March 1, 1999 X
between Carolina Power & Light Company and The Bank of New
York, as Trustee, (filed as Exhibit No. 4(a) to Current
Report on Form 8-K dated March 19, 1999, File No.
1-3382), and the First and Second Supplemental Senior
Note Indentures thereto (Exhibit No. 4(b) to Current
Report on Form 8-K dated March 19, 1999, File No.
1-3382); Exhibit No. 4(a) to Current Report on Form 8-K
dated April 20, 2000, File No. 1-3382).
*4e Indenture (For Debt Securities), dated as of October 28, X
1999 between Carolina Power & Light Company and The Chase
Manhattan Bank, as Trustee (filed as Exhibit 4(a) to
Current Report on Form 8-K dated November 5, 1999, File
No. 1-3382), and an Officer's Certificate issued pursuant
thereto, dated as of October 28, 1999, authorizing the
issuance and sale of Extendible Notes due October 28,
2009 (Exhibit 4(b) to Current Report on Form 8-K dated
November 5, 1999, File No. 1-3382).
*4f Contingent Value Obligation Agreement, dated as of X
November 30, 2000, between CP&L Energy, Inc. and The Chase
Manhattan Bank, as Trustee (Exhibit 4.1 to Current Report
on Form 8-K dated December 12, 2000, File No. 1-3382).
*10a(1) Purchase, Construction and Ownership Agreement dated July X
30, 1981 between Carolina Power & Light Company and North
Carolina Municipal Power Agency Number 3 and Exhibits,
together with resolution dated December 16, 1981 changing
name to North Carolina Eastern Municipal Power Agency,
amending letter dated February 18, 1982, and amendment
dated February 24, 1982 (filed as Exhibit 10(a),
File No. 33-25560).
*10a(2) Operating and Fuel Agreement dated July 30, 1981 between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981 changing name to
North Carolina Eastern Municipal Power Agency, amending
letters dated August 21, 1981 and December 15, 1981, and
amendment dated February 24, 1982 (filed as
Exhibit 10(b), File No. 33-25560).
*10a(3) Power Coordination Agreement dated July 30, 1981 between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981 changing name to
North Carolina Eastern Municipal Power Agency and
amending letter dated January 29, 1982 (filed as
Exhibit 10(c), File No. 33-25560).
190
*10a(4) Amendment dated December 16, 1982 to Purchase, X
Construction and Ownership Agreement dated July 30, 1981
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency (filed as Exhibit 10(d),
File No. 33-25560).
*10a(5) Agreement Regarding New Resources and Interim Capacity X
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency dated October 13, 1987 (filed
as Exhibit 10(e), File No. 33-25560).
*10a(6) Power Coordination Agreement - 1987A between North X
Carolina Eastern Municipal Power Agency and Carolina
Power & Light Company for Contract Power From New
Resources Period 1987-1993 dated October 13, 1987 (filed
as Exhibit 10(f), File No. 33-25560).
*10b(1) Progress Energy, Inc. $250,000,000 364-Day Amended and X
Restated Credit Agreement dated as of November 10, 2003
(filed as Exhibit 10(i) to Quarterly Report on Form 10-Q
for the period ended September 30, 2003, File No. 1-03382
and 1-15929).
*10b(2) Amendment and Restatement, dated as of July 30, 2003, to the X
364-Day Revolving Credit Agreement among PEC and certain
Lenders (filed as Exhibit 10(v) to Quarterly Report on Form 10-Q
for the period ended June 30, 2003, File No. 1-3382 and 1-15929).
*10b(3) Notice, dated March 25, 2003 to the Agent for the Lenders named X
in the PEC 364-Day Revolving Credit Agreement dated July 31,
2002, of a commitment reduction in the amount of $120,000,000
(filed as Exhibit 10(ii) to Quarterly Report on Form 10-Q
for the period ended March 31, 2003, File No. 1-03382 and
1-15929).
*10b(4) Assumption Agreement from The Bank of New York dated August 5, X
2002 for a total commitment of $25 million, increasing the
amount of the PEC 364-Day and 3-Year Revolving Credit
Agreements, dated July 31, 2002, to $285,000,000 each
(filed as Exhibit 10(v) to Quarterly Report on Form 10-Q
for the period ended September 30, 2002, File No. 1-03382
and 1-15929).
*10b(5) Carolina Power & Light Company $272,500,000 364-Day X
Revolving Credit Agreement dated as of July 31, 2002
(filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q
for the period ended September 30, 2002, File No. 1-3382).
*10b(6) Assumption Agreement from The Bank of New York dated X
August 5, 2002 for a total commitment of $25 million,
increasing the amount of the PEC 364-Day and 3-Year
Revolving Credit Agreements dated as of July 31, 2002, to
191
$285,000,000 each (filed as exhibit 10(v) to Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 2002, File No. 1-3382 and 1-15929).
*10b(7) Amendment and Restatement dated July 26, 2002 to Progress X
Energy, Inc.'s $450,000,000 3-Year Revolving Credit
Agreement dated November 13, 2001 as amended February 13,
2002 (filed as Exhibit 10(i) to Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2002,
File No. 1-3382 and 1-15929).
*10b(8) Amendment, dated February 13, 2002, to Progress Energy, X
Inc. $450,000,000 3-Year Revolving Credit Agreement dated
November 13, 2001 (filed as Exhibit 10b(8) to Annual
Report on Form 10-K dated March 28, 2002, File No. 1-3392
and 1-15929).
*10b(9) Progress Energy, Inc. $450,000,000 3-Year Revolving Credit X
Agreement dated as of November 13, 2001 (filed as Exhibit
10b(6) to Annual Report on Form 10-K dated March 28, 2002,
File No. 1-3392 and 1-15929).
*10b(10) PEF 364-Day $200,000,000 Credit Agreement dated as of April X
1, 2003 (filed as Exhibit 10(ii) to Florida Power Corporation
Form 10-Q for the quarter ended March 31, 2003).
*10b(11) PEF 3-Year $200,000,000 Credit Agreement, dated as of April X
1, 2003 (filed as Exhibit 10(iii) to the Florida Power
Corporation Form 10-Q for the quarter ended March 31, 2003).
- -+*10c(1) Directors Deferred Compensation Plan effective January 1, X
1982 as amended (filed as Exhibit 10(g), File No. 33-25560).
- -+*10c(2) Retirement Plan for Outside Directors (filed as Exhibit X
10(i), File No. 33-25560).
- -+*10c(3) Key Management Deferred Compensation Plan (filed as Exhibit X
10(k), File No. 33-25560).
+*10c(4) Resolutions of the Board of Directors, dated March 15, X
1989, amending the Key Management Deferred Compensation Plan
(filed as Exhibit 10(a), File No. 33-48607).
- -+*10c(5) Resolutions of the Board of Directors dated May 8, 1991, X X
amending the PEC Directors Deferred Compensation Plan (filed
as Exhibit 10(b), File No. 33-48607).
+*10c(6) Resolutions of Board of Directors dated July 9, 1997, X
amending the Deferred Compensation Plan for Key Management
Employees of Carolina Power & Light Company.
192
+*10c(7) Progress Energy, Inc. Non-Employee Director Stock Unit X X
Plan, amended and restated effective July 10, 2002 (filed
as Exhibit 10(ii) to Quarterly Report on Form 10-Q for
the period ended June 30, 2003, File No. 1-03382 and
1-15929).
- -+*10c(8) Carolina Power & Light Company Restricted Stock X X
Agreement, as approved January 7, 1998, pursuant to the
Company's 1997 Equity Incentive Plan (filed as Exhibit
No. 10 to Quarterly Report on Form 10-Q for the quarterly
period ended March 31, 1998, File No. 1-3382.)
- -+*10c(9) Progress Energy, Inc. Restoration Retirement Plan, as X X
amended and restated July 10, 2002 (filed as Exhibit
10(i) to Quarterly Report on Form 10-Q for the period
ended June 30, 2003, File No. 1-3382 and 1-15929).
- -+*10c(10) Amended and Restated Supplemental Senior Executive X X
Retirement Plan of Progress Energy, Inc., as last amended
July 10, 2002 (filed as Exhibit 10b(iii) to Quarterly
Report on Form 10-Q for the period ended June 30, 2003,
File No. 1-3382 and 1-15929).
- -+*10c(11) Performance Share Sub-Plan of the 2002 Progress Energy, X X
Inc. Equity Incentive Plan, dated July 9, 2002 (filed as
Exhibit 10(vii) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2002, File No.
1-3382 and 1-15929).
- -+*10c(12) Performance Share Sub-Plan of the 1997 Equity Incentive X X
Plan, as amended January 1, 2001 (filed as Exhibit
10c(11) to Annual Report on Form 10-K dated March 28,
2002, File No. 1-3382 and 1-15929).
+*10c(13) 2002 Progress Energy, Inc. Equity Incentive Plan, amended X X
and restated July 10, 2002 (filed as Exhibit 10(vi) to
Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2002, File No. 1-3382 and 1-15929).
+*10c(14) 1997 Equity Incentive Plan, Amended and Restated as of X X
September 26, 2001 (filed as Exhibit 4.3 to Progress Energy
Form S-8 dated September 27, 2001, File No.
1-3382).
+*10c(15) Progress Energy, Inc. Form of Stock Option Agreement X X
(filed as Exhibit 4.4 to Form S-8 dated September 27, 2001,
File No. 333-70332).
+*10c(16) Progress Energy, Inc. Form of Stock Option Award (filed as X X
Exhibit 4.5 to Form S-8 dated September 27, 2001, File No.
333-70332).
193
- -+*10c(17) Amended Management Incentive Compensation Plan of X X
Progress Energy, Inc., as amended January 1, 2003 (filed
as Exhibit 10(iv) to Quarterly Report on Form 10-Q for
the period ended June 30, 2003, File No. 1-3382 and
1-15929).
- -+*10c(18) Progress Energy, Inc. Management Deferred X X
Compensation Plan, revised and restated as of January 1,
2003 (filed as Exhibit 4.3 to Progress Energy Form S-8 on
May 2, 2003, File No. 333-104952).
+*10c(19) Agreement dated April 27, 1999 between Carolina Power & X
Light Company and Sherwood H. Smith, Jr. (filed as Exhibit
10b, File No. 1-3382).
+*10c(20) Employment Agreement dated August 1, 2000 between CP&L X
Service Company LLC and William Cavanaugh III (filed as
Exhibit 10(i) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(21) Employment Agreement dated August 1, 2000 between X
Carolina Power & Light Company and William S. "Skip"
Orser (filed as Exhibit 10(ii) to Quarterly Report on
Form 10-Q for the quarterly period ended September 30,
2000, File No. 1-15929 and No. 1-3382).
+*10c(22) Employment Agreement dated August 1, 2000 between Carolina X
Power & Light Company and Tom Kilgore (filed as Exhibit
10(iii) to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(23) Employment Agreement dated August 1, 2000 between CP&L X
Service Company LLC and Robert McGehee (filed as Exhibit
10(iv) to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(24) Form of Employment Agreement dated August 1, 2000 (i) X X
between Carolina Power & Light Company and Don K. Davis; and
(ii) between CP&L Service Company LLC and Peter M.
Scott III and William D. Johnson (filed as Exhibit 10(v)
to Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(25) Form of Employment Agreement dated August 1, 2000 (i) X X
between Carolina Power & Light Company and Fred Day IV,
C.S. "Scotty" Hinnant and E. Michael Williams; and (ii)
between CP&L Service Company LLC and Bonnie V. Hancock
(filed as Exhibit 10(vi) to Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 2000, File
No. 1-15929 and No. 1-3382).
194
+*10c(26) Employment Agreement dated November 30, 2000 between X
Carolina Power & Light Company, Florida Power Corporation
and H. William Habermeyer, Jr. (filed as Exhibit
10.(b)(32) to Florida Progress Corporation and Florida
Power Corporation Annual Report on Form 10-K for the
year ended December 31, 2000).
+10c(27) Form of Employment Agreement between (i) Progress Energy X
Service Company, LLC and Brenda F. Castonguay, effective
September 2002; and (ii) Progress Energy Service Company and
John R. McArthur, effective January 2003; dated December 15,
2003 (filed as Exhibit 10c(27) to Annual Report on Form 10-K
for the year ended December 31, 2002, File No. 1-33382 and
1-5929).
+10c(28) Employment Agreement dated October 1, 2003 between Progress X
Energy Service Company, LLC and Geoffrey S. Chatas
12 Computation of Ratio of Earnings to Fixed Charges and X X
Ratio of Earnings to Fixed Charges Preferred Dividends
Combined.
21 Subsidiaries of Progress Energy, Inc. X
23(a) Consent of Deloitte & Touche LLP. X X
31(a) 302 Certification of Chief Executive Officer X X
31(b) 302 Certification of Chief Financial Officer X X
32(a) 906 Certification of Chief Executive Officer X X
32(b) 906 Certification of Chief Financial Officer X X
*Incorporated herein by reference as indicated.
+Management contract or compensation plan or arrangement required to be filed as
an exhibit to this report pursuant to Item 14 (c) of Form 10-K.
- -Sponsorship of this management contract or compensation plan or arrangement was
transferred from Carolina Power & Light Company to Progress Energy, Inc.,
effective August 1, 2000.
195
PROGRESS ENERGY, INC.
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
(Millions of Dollars)
Earnings, as defined:
Income from continuing operations before cumulative
effect of changes in accounting principles $ 811 $ 552 $ 541 $ 478 $ 383
Fixed charges, as below 657 667 719 275 193
Capitalized interest (20) (38) - - -
Income taxes, as below (117) (166) (162) 188 250
- -----------------------------------------------------------------------------------------------------------------------------------
Total earnings, as defined $ 1,331 $ 1,015 $ 1,098 $ 941 $ 826
===================================================================================================================================
Fixed Charges, as defined:
Interest on long-term debt $ 595 $ 600 $ 578 $ 224 $ 174
Other interest 37 41 112 37 7
Imputed interest factor in rentals-charged
principally to operating expenses 18 19 21 9 7
Preferred dividend requirements of subsidiaries (a) 7 7 8 5 5
- -----------------------------------------------------------------------------------------------------------------------------------
Total fixed charges, as defined $ 657 $ 667 $ 719 $ 275 $ 193
===================================================================================================================================
Income Taxes:
Income tax expense (benefit) $ (109) $ (158) $ (154) $ 196 $ 258
Included in AFUDC - deferred taxes in
book depreciation (8) (8) (8) (8) (8)
- -----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $ (117) $ (166) $ (162) $ 188 $ 250
===================================================================================================================================
Ratio of Earnings to Fixed Charges 2.03 1.52 1.53 3.42 4.28
(a) Preferred dividends of subsidiaries not deductible times ratio of earnings
before income taxes to net income
196
PROGRESS ENERGY CAROLINAS, INC.
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND
PREFERRED DIVIDENDS COMBINED AND RATIO OF EARNINGS TO FIXED CHARGES
Years Ended December 31,
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
(Millions of Dollars)
Earnings, as defined:
Income before cumulative effect of change in accounting
principles $ 505 $ 431 $ 364 $ 461 $ 382
Fixed charges, as below 200 220 264 246 196
Income taxes, as below 236 199 215 282 250
- -----------------------------------------------------------------------------------------------------------------------------------
Total earnings, as defined $ 941 $ 850 $ 843 $ 989 $ 828
===================================================================================================================================
Fixed Charges, as defined:
Interest on long-term debt $ 185 $ 205 $ 246 $ 224 $ 181
Other interest 11 12 11 17 10
Imputed interest factor in rentals-charged
principally to operating expenses 4 3 7 5 5
- -----------------------------------------------------------------------------------------------------------------------------------
Total fixed charges, as defined $ 200 $ 220 $ 264 $ 246 $ 196
===================================================================================================================================
Earnings Before Income Taxes $ 741 $ 630 $ 579 $ 743 $ 632
Ratio of Earnings Before Income Taxes to Income before 1.47 1.46 1.59 1.61 1.65
cumulative effect of change in accounting principles
Income Taxes:
Income tax expense $ 244 $ 207 $ 223 $ 290 $ 258
Included in AFUDC - deferred taxes in
book depreciation (8) (8) (8) (8) (8)
- -----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $ 236 $ 199 $ 215 $ 282 $ 250
===================================================================================================================================
Fixed Charges and Preferred Dividends Combined:
Preferred dividend requirements $ 3 $ 3 $ 3 $ 3 $ 3
Portion deductible for income tax purposes - - - - -
Preferred dividend requirements not deductible $ 3 $ 3 $ 3 $ 3 $ 3
Preferred dividend factor:
Preferred dividends not deductible times ratio of
earnings before income taxes to net income $ 4 $ 4 $ 5 $ 5 $ 5
Preferred dividends deductible for income taxes - - - - -
Fixed charges, as above 200 220 264 246 196
- -----------------------------------------------------------------------------------------------------------------------------------
Total fixed charges and preferred dividends combined $ 204 $ 224 $ 269 $ 251 $ 201
===================================================================================================================================
Ratio of Earnings to Fixed Charges 4.71 3.86 3.19 4.02 4.22
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined 4.61 3.79 3.13 3.94 4.12
197
Exhibit 21
SUBSIDIARIES OF PROGRESS ENERGY, INC.
AT DECEMBER 31, 2003
The following is a list of certain direct and indirect subsidiaries of Progress
Energy, Inc. and their respective states of incorporation:
Carolina Power & Light Company d/b/a PEC North Carolina
Florida Progress Corporation Florida
Florida Power Corporation d/b/a/ PEF Florida
Progress Telecommunications Corporation Florida
Progress Telecom, LLC Delaware
Progress Capital Holdings, Inc. Florida
Progress Fuels Corporation Florida
Progress Rail Services Corporation Alabama
Progress Ventures, Inc. North Carolina
Strategic Resource Solutions Corp. North Carolina
Progress Energy Service Company, LLC North Carolina
198
Exhibit 23(a)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
33-33520 on Form S-8, Post-Effective Amendment 1 to Registration Statement No.
33-38349 on Form S-3, Registration Statement No. 333-81278 on Form S-3,
Registration Statement No. 333-81278-01 on Form S-3, Registration Statement No.
333-81278-02 on Form S-3, Registration Statement No. 333-81278-03 on Form S-3,
Post-Effective Amendment 1 to Registration Statement No. 333-69738 on Form S-3,
Registration Statement No. 333-70332 on Form S-8, Registration Statement No.
333-87274 on Form S-3, Post-Effective Amendment 1 to Registration Statement No.
333-47910 on Form S-3, Registration Statement No. 333-52328 on Form S-8,
Post-Effective Amendment 1 to Registration Statement No. 333-89685 on Form S-8,
and Registration Statement No. 333-48164 on Form S-8 of Progress Energy, Inc. of
our reports dated February 20, 2004 (which express an unqualified opinion and
include an explanatory paragraph concerning the adoption of new accounting
principles in 2003 and 2002); appearing in this Annual Report on Form 10-K of
Progress Energy, Inc. for the year ended December 31, 2003.
We also consent to the incorporation by reference in Registration Statement No.
333-58800 on Form S-3 of Carolina Power & Light Company d/b/a Progress Energy
Carolinas, Inc. (PEC) of our reports dated February 20, 2004 (which express an
unqualified opinion and includes an explanatory paragraph concerning the
adoption of new accounting principles in 2003), appearing in this Annual Report
on Form 10-K of (PEC) for the year ended December 31, 2003.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 12, 2004
199