UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X . No .
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of each registrant's knowledge, in definitive proxy or information
statements incorporated by reference in PART III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
Indicate by check mark whether Progress Energy, Inc. is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes X . No .
Indicate by check mark whether Carolina Power & Light Company is an accelerated
filer (as defined in Rule 12b-2 of the Act). Yes . No X .
1
As of June 30, 2004, the aggregate market value of the voting and non-voting
common equity of Progress Energy, Inc. held by non-affiliates was
$10,653,481,488. As of June 30, 2004, the aggregate market value of the common
equity of Carolina Power & Light Company held by non-affiliates was $0. All of
the common stock of Carolina Power & Light Company is owned by Progress Energy,
Inc.
As of March 4, 2005, each registrant had the following shares of common stock
outstanding:
Registrant Description Shares
Progress Energy, Inc. Common Stock (Without Par Value) 248,533,367
Carolina Power & Light Company Common Stock (Without Par Value) 159,608,055
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Progress Energy and PEC definitive proxy statements dated March
31, 2005 are incorporated into PART III, ITEMS 10, 11, 12 , 13 and 14 hereof.
This combined Form 10-K is filed separately by two registrants: Progress Energy,
Inc. (Progress Energy) and Carolina Power & Light Company d/b/a Progress Energy
Carolinas, Inc. (PEC). Information contained herein relating to either
individual registrant is filed by such registrant solely on its own behalf.
2
TABLE OF CONTENTS
GLOSSARY OF TERMS
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
PART I
ITEM 1. BUSINESS
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
PROGRESS ENERGY, INC. RISK FACTORS
CAROLINA POWER & LIGHT COMPANY RISK FACTORS
3
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 Broad River LLC's Broad River Facility
Btu British thermal unit
CAIR Clean Air Interstate Rule
Caronet Caronet, Inc.
CCO Competitive Commercial Operations business segment
CERCLA or Superfund Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended
Code Internal Revenue Code
Colona Colona Synfuel Limited Partnership, LLLP
the Company Progress Energy, Inc. and subsidiaries
CP&L Carolina Power & Light Company
CP&L Energy CP&L Energy, Inc.
CR3 Crystal River Unit No. 3
CVO Contingent value obligation
DOE United States Department of Energy
DWM North Carolina Department of Environment and Natural Resources, Division of
Waste Management
ETS Engineering and Track-work
ECRC Environmental Cost Recovery Clause
EITF Emerging Issues Task Force
EMCs Electric Membership Cooperatives
ENCNG Eastern North Carolina Natural Gas Company, formerly referred to as
EasternNC
EPA of 1992 Energy Policy Act of 1992
EPIK EPIK Communications, Inc.
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
FDEP Florida Department of Environment and Protection
FERC Federal Energy Regulatory Commission
FIN No. 45 Financial Accounting Standards Board (FASB) Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
FIN No. 46R FASB Interpretation No. 46R, "Consolidation of Variable Interest Entities -
an Interpretation of ARB No. 51"
Florida Progress or FPC Florida Progress Corporation
FPSC Florida Public Service Commission
Fuels Fuels business segment
Funding Corp. Florida Progress Funding Corporation
GAAP Accounting Principles Generally Accepted in the United States of America
Genco Progress Genco Ventures LLC
Georgia Power Georgia Power Company
Global U.S. Global LLC
Harris Plant Shearon Harris Nuclear Plant
the holding company Progress Energy Corporate
Interpath Interpath Communications, Inc.
IBEW International Brotherhood of Electrical Workers
IRS Internal Revenue Service
ISO Independent System Operator
4
Jackson Jackson Electric Membership Corporation
kV Kilovolt
kVA Kilovolt-ampere
LIBOR London Inter Bank Offering Rate
LRS Locomotive and Railcar Services
LSEs Load-serving entities
MACT Maximum Achievable Control Technology
MDC Maximum Dependable Capability
Medicare Act Medicare Prescription Drug, Improvement and Modernization Act of 2003
MGP Manufactured Gas Plant
MW Megawatt
MWh Megawatt-hour
NC Clean Air North Carolina Clean Smokestacks Act enacted in June 2002
NCNG North Carolina Natural Gas Corporation
NCUC North Carolina Utilities Commission
NDE Nondestructive Examination
NEIL Nuclear Electric Insurance Limited
NOx Nitrogen Oxide
NOx SIP Call EPA rule which requires 22 states including North and South Carolina to
further reduce nitrogen oxide emissions.
NRC United States Nuclear Regulatory Commission
Nuclear Waste Act Nuclear Waste Policy Act of 1982
O&M Operations & Maintenance Expense
Odyssey Odyssey Telecorp, Inc.
OPEB Postretirement benefits other than pensions
P11 Intercession Unit P11
PCH Progress Capital Holdings, Inc.
PEC Progress Energy Carolinas, Inc.
PEC Electric PEC Electric business segment made up of the utility operations and
excludes operations of nonregulated subsidiaries
PEF Progress Energy Florida
PESC Progress Energy Service Company, LLC
PFA IRS Prefiling Agreement
the Plan Revenue Sharing Incentive Plan
PLR Private Letter Ruling
Power Agency North Carolina Eastern Municipal Power Agency
Preferred Securities FPC-obligated mandatorily redeemable preferred securities of FPC Capital I
Progress Energy Progress Energy, Inc.
Progress Fuels Progress Fuels Corporation, formerly Electric Fuels Corporation
Progress Rail Progress Rail Services Corporation
Progress Ventures Business unit of Progress Energy primarily made up of nonregulated energy
generation and marketing activities, as well as gas, coal and synthetic
fuel operations
PRP Potentially responsible party, as defined in CERCLA
PSSP Performance Share Sub-Plan
PTC Progress Telecommunications Corporation
PT LLC Progress Telecom, LLC
PUHCA Public Utility Holding Company Act of 1935, as amended
PURPA Public Utilities Regulatory Policies Act of 1978
PVI Progress Energy Ventures, Inc. (formerly referred to as CPL Energy
Ventures, Inc.)
PWR Pressurized water reactor
QF Qualifying facility
Rail Services Rail Services business segment
RCA Revolving credit agreement
Rockport Indiana Michigan Power Company's Rockport Unit No. 2
Robinson PEC's Robinson Nuclear Plant
ROE Return on Equity
RSA Restricted Stock Awards program
RTO Regional Transmission Organization
5
SCPSC Public Service Commission of South Carolina
SEC U.S. Securities and Exchange Commission
Section 29 Section 29 of the Internal Revenue Service Code
(See Note/s "#") For all Sections, except the Carolina Power & Light Company Financial
Statements in Part II, Item 8, this is a reference to the Notes in the
Progress Energy Consolidated Financial Statements in Part II, Item 8
Service Company Progress Energy Service Company, LLC
SFAS Statement of Financial Accounting Standards
SFAS No. 5 Statement of Financial Accounting Standards No. 5, "Accounting for
Contingencies"
SFAS No. 71 Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation"
SFAS No. 87 Statement of Financial Accounting Standards No. 87, "Employers' Accounting
for Pensions"
SFAS No. 109 Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes"
SFAS No. 121 Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of"
SFAS No. 123 Statement of Financial Accounting Standards No. 123, "Accounting for
Stock-Based Compensation"
SFAS No. 123R Statement of Financial Accounting Standards No. 123R, "Accounting for
Stock-Based Compensation"
SFAS No. 133 Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative and Hedging Activities"
SFAS No. 138 Statement of Financial Accounting Standards No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities - An
Amendment of FASB Statement No. 133"
SFAS No. 142 Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets"
SFAS No. 143 Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations"
SFAS No. 144 Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets"
SFAS No. 148 Statement of Financial Accounting Standards No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure - An Amendment of FASB
Statement No. 123"
SFAS No. 150 Statement of Financial Accounting Standards No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity"
SMD NOPR Notice of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission and Standard Market Design
SO2 Sulfur dioxide
SRS Strategic Resource Solutions Corp.
Tax Agreement Intercompany Income Tax Allocation Agreement
the Trust FPC Capital I
Winchester Energy Winchester Energy Company, Ltd. (formerly Westchester Gas Company)
Winchester Production Winchester Production Company, Ltd., an indirectly owned subsidiary of
Progress Fuels Corporation
6
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
Certain matters discussed throughout this Form 10-K that are not historical
facts are forward-looking and, accordingly, involve estimates, projections,
goals, forecasts, assumptions, risks and uncertainties that could cause actual
results or outcomes to differ materially from those expressed in the
forward-looking statements.
In addition, examples of forward-looking statements discussed in this Form 10-K
include 1) PART II, ITEM 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations" including, but not limited to, statements
under the following headings: a) "Results of Operations" about trends and
uncertainties; b) "Liquidity and Capital Resources" about operating cash flows,
estimated capital requirements through the year 2007 and future financing plans;
c) "Strategy" about Progress Energy, Inc.'s, strategy; and d) "Other Matters"
about the effects of new environmental regulations, nuclear decommissioning
costs and the effect of electric utility industry restructuring; and 2)
statements made in the "Risk Factors" sections.
Any forward-looking statement is based on information current as of the date of
this report and speaks only as of the date on which such statement is made, and
neither Progress Energy, Inc., (the Company) nor Progress Energy Carolinas (PEC)
undertakes any obligation to update any forward-looking statement or statements
to reflect events or circumstances after the date on which such statement is
made.
Examples of factors that you should consider with respect to any forward-looking
statements made throughout this document include, but are not limited to, the
following: the impact of fluid and complex government laws and regulations,
including those relating to the environment; deregulation or restructuring in
the electric industry that may result in increased competition and unrecovered
(stranded) costs; the ability of the Company to implement its cost management
initiatives as planned; the uncertainty regarding the timing, creation and
structure of regional transmission organizations; weather conditions that
directly influence the demand for electricity; the Company's ability to recover
through the regulatory process, and the timing of such recovery of, the costs
associated with the four hurricanes that impacted our service territory in 2004
or other future significant weather events; recurring seasonal fluctuations in
demand for electricity; fluctuations in the price of energy commodities and
purchased power; economic fluctuations and the corresponding impact on the
Company and its subsidiaries' commercial and industrial customers; the ability
of the Company's subsidiaries to pay upstream dividends or distributions to it;
the impact on the facilities and the businesses of the Company from a terrorist
attack; the inherent risks associated with the operation of nuclear facilities,
including environmental, health, regulatory and financial risks; the ability to
successfully access capital markets on favorable terms; the impact on the
Company's financial condition and ability to meet its cash and other financial
obligations in the event its credit ratings are downgraded below investment
grade; the impact that increases in leverage may have on the Company; the
ability of the Company to maintain its current credit ratings; the impact of
derivative contracts used in the normal course of business by the Company;
investment performance of pension and benefit plans; the Company's ability to
control costs, including pension and benefit expense, and achieve its cost
management targets for 2007; the availability and use of Internal Revenue Code
Section 29 (Section 29) tax credits by synthetic fuel producers and the
Company's continued ability to use Section 29 tax credits related to its coal
and synthetic fuel businesses; the impact to the Company's financial condition
and performance in the event it is determined the Company is not entitled to
previously taken Section 29 tax credits; the impact of future accounting
pronouncements regarding uncertain tax positions; the outcome of PEF's rate
proceeding in 2005 regarding its future base rates; the Company's ability to
manage the risks involved with the operation of its nonregulated plants,
including dependence on third parties and related counter-party risks, and a
lack of operating history; the Company's ability to manage the risks associated
with its energy marketing operations; the outcome of any ongoing or future
litigation or similar disputes and the impact of any such outcome or related
settlements; and unanticipated changes in operating expenses and capital
expenditures. Many of these risks similarly impact the Company's subsidiaries.
These and other risk factors are detailed from time to time in the Company's and
PEC's filings with the United States Securities and Exchange Commission (SEC).
Many, but not all, of the factors that may impact actual results are discussed
in the "Risk Factors" sections of this report. You should carefully read the
"Risk Factors" sections of this report. All such factors are difficult to
predict, contain uncertainties that may materially affect actual results and may
be beyond the control of Progress Energy and PEC. New factors emerge from time
to time, and it is not possible for management to predict all such factors, nor
can it assess the effect of each such factor on Progress Energy and PEC.
7
PART I
ITEM 1. BUSINESS
GENERAL
COMPANY
Progress Energy, Inc. (Progress Energy or the Company, which includes
consolidated subsidiaries unless otherwise indicated) is a registered holding
company under the Public Utility Holding Company Act of 1935 (PUHCA) and is an
integrated energy company located principally in the southeast region of the
United States. The Company is subject to the regulatory provisions of PUHCA.
Progress Energy was incorporated on August 19, 1999. The Company was initially
formed as CP&L Energy, Inc. (CP&L Energy), which became the holding company for
Carolina Power & Light Company (CP&L) on June 19, 2000. All shares of common
stock of CP&L were exchanged for an equal number of shares of CP&L Energy common
stock.
Effective January 1, 2003, CP&L, Florida Power Corporation and Progress
Ventures, Inc., (PVI) began doing business under the names Progress Energy
Carolinas, Inc. (PEC), Progress Energy Florida, Inc. (PEF) and Progress Energy
Ventures, Inc. (PVI), respectively. The legal names of these entities have not
changed and there was no restructuring of any kind related to the name change.
Through its wholly owned regulated subsidiaries, PEC and PEF, Progress Energy is
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina, South Carolina and Florida. The
Progress Ventures business unit consists of the Fuels business segment (Fuels)
and Competitive Commercial Operations (CCO) operating segments. Progress
Energy's legal structure is not currently aligned with the functional management
and financial reporting of the Progress Ventures business unit. Whether, and
when, the legal and functional structures will converge depends upon legislative
and regulatory action, which cannot currently be anticipated. Through its
Competitive Commercial Operations (CCO) business segment, Progress Energy is
involved in nonregulated electricity generation operations. Through its Fuels
business segment (Fuels), Progress Energy is involved in natural gas drilling
and production, coal terminal services, coal mining, synthetic fuel production,
fuel transportation and delivery. Both CCO and Fuels are involved in limited
energy and commodity economic hedging activities. Through its Rail Services
business segment (Rail Services), Progress Energy engages in various rail and
railcar-related services. In February 2005, Progress Energy signed a definitive
agreement to sell its Progress Rail subsidiary for a sales price of $405 million
(See Note 24). The Corporate and Other Businesses segment primarily includes
Service Company activities, miscellaneous nonregulated activities and holding
company operations. For information regarding the revenues, income and assets
attributable to the Company's business segments, See Note 20 to the Progress
Energy Consolidated Financial Statements in PART II, ITEM 8.
The Company has approximately 24,000 megawatts (MW) of electric generation
capacity and serves approximately 2.9 million retail electric customers in
portions of North Carolina, South Carolina and Florida and also serves other
load-serving entities. PEC's and PEF's customer base and demand cycles are
complementary. Historically, PEC normally has a summer peaking demand, while PEF
normally has a winter peaking demand. In addition, PEC's greater proportion of
commercial and industrial customers, combined with PEF's greater proportion of
residential customers, creates a balanced customer base. The Company is
dedicated to expanding the Company's electric generation capacity and delivering
reliable, competitively priced energy.
Progress Energy revenues for the year ended December 31, 2004, were $9.8 billion
and assets at year-end were $26.0 billion. Its principal executive offices are
located at 410 South Wilmington Street, Raleigh, North Carolina 27601, telephone
number (919) 546-6111. The Progress Energy home page on the Internet is located
at http://www.progress-energy.com, the contents of which are not and shall not
be deemed a part of this document or any other U.S. Securities and Exchange
Commission (SEC) filing. The Company makes available free of charge on its Web
site its annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with or furnished to the
SEC.
8
SIGNIFICANT DEVELOPMENTS
Sale of Natural Gas Assets
In December 2004, the Company sold certain gas-producing properties and related
assets owned by Winchester Production Company, Ltd. (Winchester Production), an
indirectly owned subsidiary of Progress Fuels Corporation (Progress Fuels),
which is included in the Fuels segment. Net proceeds of approximately $251
million were used to reduce debt (See Note 4A).
2004 Hurricanes
Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the
Company's service territories during the third quarter of 2004, significantly
impacting PEF's territory. As of December 31, 2004, restoration of the Company's
systems from hurricane related damage was estimated at $398 million (See Note
3).
Divestiture of Synthetic Fuel Partnership Interests
In June 2004, the Company, through its subsidiary Progress Fuels, sold, in two
transactions, a combined 49.8% partnership interest in Colona Synfuel Limited
Partnership, LLLP, one of its synthetic fuel facilities. Substantially all
proceeds from the sales will be received over time, which is typical of such
sales in the industry (See Note 4B).
Railcar Ltd., Divestiture
In March 2003, the Company signed a letter of intent to sell the majority of
Railcar Ltd. assets to The Andersons, Inc. The asset purchase agreement was
signed in November 2003, and the transaction closed on February 12, 2004. Net
proceeds of approximately $75 million were used to reduce debt (See Note 4C).
Progress Telecommunications Corporation Business Combination
In December 2003, Progress Telecommunications Corporation (PTC) and Caronet,
Inc. (Caronet), both wholly owned subsidiaries of Progress Energy, and EPIK
Communications, Inc. (EPIK), a wholly owned subsidiary of Odyssey Telecorp, Inc.
(Odyssey), contributed substantially all of their assets and transferred certain
liabilities to Progress Telecom, LLC (PT LLC), a subsidiary of PTC.
Subsequently, the stock of Caronet was sold to an affiliate of Odyssey for $2
million in cash and Caronet became a wholly owned subsidiary of Odyssey.
Following consummation of all the transactions described above, PTC holds a 55%
ownership interest in and is the parent of PT LLC (See Note 5A).
Mesa Hydrocarbons, Inc. Divestiture
In October 2003, the Company sold certain gas-producing properties owned by Mesa
Hydrocarbons, LLC, a wholly owned subsidiary of Progress Fuels. Net proceeds of
approximately $97 million were used to reduce debt (See Note 4D).
NCNG Divestiture
In September 2003, the Company completed the sale of North Carolina Natural Gas
Corporation (NCNG) and the Company's equity investment in Eastern North Carolina
Natural Gas Company (ENCNG) to Piedmont Natural Gas Company, Inc. As a result of
this action, the operating results of NCNG were reclassified to discontinued
operations for all reportable periods. Net proceeds from the sale of NCNG and
ENCNG of approximately $443 million were used to reduce debt (See Note 4E).
Acquisition of Natural Gas Reserves
During 2003, Progress Fuels entered into several independent transactions to
acquire approximately 200 natural gas-producing wells with proven reserves of
approximately 190 billion cubic feet (Bcf) from Republic Energy, Inc. and three
other privately owned companies, all headquartered in Texas. The total cash
purchase price for the transactions was approximately $168 million (See Note
5B).
9
Wholesale Energy Contract Acquisition
In May 2003, Progress Ventures, Inc. (PVI) entered into a definitive agreement
with Williams Energy Marketing and Trading, a subsidiary of The Williams
Companies, Inc., to acquire a long-term full-requirements power supply agreement
at fixed prices with Jackson Electric Membership Corporation (Jackson), for $188
million (See Note 5C).
Westchester Acquisition
In April 2002, Progress Fuels acquired 100% of Westchester Gas Company
(Westchester). During 2004, the name of the company was changed to Winchester
Energy Co. Ltd., (Winchester Energy). The acquisition included approximately 215
natural gas-producing wells, 52 miles of intrastate gas pipeline and 170 miles
of gas-gathering systems. The aggregate purchase price was approximately $153
million (See Note 5D).
Generation Acquisition
In February 2002, PVI acquired 100% of two electric generating projects in
Georgia from LG&E Energy Corp., a subsidiary of Powergen plc. for a total cash
purchase price of approximately $348 million. The transaction included tolling
agreements and two power purchase agreements with LG&E Energy Marketing, Inc.
(See Note 5E).
Florida Progress Acquisition
On November 30, 2000, the Company completed its acquisition of Florida Progress
Corporation (FPC), a diversified, exempt electric utility holding company, for
an aggregate purchase price of approximately $5.4 billion. The Company paid cash
consideration of approximately $3.5 billion and issued 46.5 million shares of
common stock valued at approximately $1.9 billion. In addition, the Company
issued 98.6 million contingent value obligations (CVOs) valued at approximately
$49 million.
The FPC acquisition was accounted for using the purchase method of accounting
and, accordingly, the results of operations for FPC have been included in the
Company's Consolidated Financial Statements since the date of acquisition.
COMPETITION
GENERAL
In recent years, the electric utility industry has experienced a substantial
increase in competition at the wholesale level, caused by changes in federal law
and regulatory policy. Several states have also decided to restructure aspects
of retail electric service. The issue of retail restructuring and competition is
being reviewed by a number of states, and bills have been introduced in past
sessions of Congress that sought to introduce such restructuring in all states.
The 108th Congress spent much of 2004 working on a comprehensive energy bill.
While that legislation passed the House, the Senate failed to pass the
legislation in 2004. The Company expects that there will be an effort to
resurrect the legislation in 2005. The legislation would have further clarified
the Federal Energy Regulatory Commission's (FERC) role with respect to Standard
Market Design and mandatory Regional Transmission Organizations (RTOs) and would
have repealed PUHCA. The Company cannot predict the outcome of this matter.
As a result of the Public Utilities Regulatory Policies Act of 1978 (PURPA) and
the Energy Policy Act of 1992 (EPA of 1992), competition in the wholesale
electricity market has greatly increased, especially from nonutility generators
of electricity. In 1996, the FERC issued new rules on transmission service to
facilitate competition in the wholesale market on a nationwide basis. The rules
give greater flexibility and more choices to wholesale power customers.
To date, many states have adopted legislation that would give retail customers
the right to choose their electricity provider (retail choice), and most other
states have, in some form, considered the issue. There is currently no proposed
legislation in North Carolina, South Carolina or Florida that would introduce
retail choice.
Since passage of the EPA of 1992, competition in the wholesale electric utility
industry has significantly increased due to a greater participation by
traditional electricity suppliers, wholesale power marketers and brokers and due
to the trading of energy futures contracts on various commodities exchanges.
10
This increased competition could affect PEC and PEF's load forecasts, plans for
power supply and wholesale energy sales and related revenues. The impact could
vary depending on the extent to which additional generation is built to compete
in the wholesale market, new opportunities are created for PEC and PEF to expand
their wholesale load, or current wholesale customers elect to purchase from
other suppliers after existing contracts expire.
An issue encompassed by industry restructuring is the recovery of "stranded
costs." Stranded costs primarily include the generation assets of utilities
whose value in a competitive marketplace would be less than their current book
value, as well as above-market purchased power commitments to qualifying
facilities (QFs). Thus far, all states that have passed restructuring
legislation have provided for the opportunity to recover a substantial portion
of stranded costs. Assessing the amount of stranded costs for a utility requires
various assumptions about future market conditions, including the future price
of electricity.
In November 2003, the FERC adopted new standards of conduct that apply uniformly
to interstate natural gas pipelines and public utilities. These standards have
been clarified and supplemented by subsequent FERC orders. The new standards of
conduct govern the relationship between transmission providers and their energy
affiliates in a manner that prevents excessive market power and preferential
treatment. Each utility was required to submit a plan and schedule for
compliance with the new rules by February 2004. PEC and PEF have complied in all
material respects with all of the requirements associated with these standards
and FERC orders.
In April 2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market power
of applicants for wholesale market-based rates, and described additional
analyses and mitigation measures that could be presented if an applicant does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider whether the FERC's current methodology
for determining whether a public utility should be allowed to sell wholesale
electricity at market-based rates should be modified in any way. Management is
unable to predict the outcome of these actions by the FERC or their effect on
future results of operations and cash flows. PEF does not have market-based rate
authority for wholesale sales in peninsular Florida. Given the difficulty PEC
believes it would experience in passing one of the interim screens, on August
12, 2004, PEC notified the FERC that it would revise its Market-based Rate
tariff to restrict it to sales outside PEC's control area and file a new
cost-based tariff for sales within PEC's control area that incorporates the
FERC's default cost-based rate methodologies for sales of one year or less. PEC
anticipates making this filing the first quarter of 2005.
On December 23, 2004, PEF advised the FERC that PEF only has market-based rate
authority in Southern Company's control area in Georgia. PEF also advised the
FERC that PEF filed market power studies in 2003 demonstrating that it does not
have market power in that market and that because nothing has changed since that
study was performed, PEF should not have to perform the new tests.
Although the Company cannot predict the ultimate outcome of these changes, the
Company does not anticipate that the current operations of PEC or PEF would be
impacted materially if they were unable to sell power at market-based rates in
their respective control areas.
See PART I, ITEM 1, "Competition" of Electric-PEC and Electric-PEF for
discussions of franchises as they relate to PEC and PEF.
See PART I, ITEM 1, "Competition," under Electric-PEC, Electric-PEF and Other
for further discussion of competitive developments within these segments.
PUHCA
As a result of the acquisition of FPC, Progress Energy is now a registered
holding company subject to regulation by the SEC under PUHCA. Therefore,
Progress Energy and its subsidiaries are subject to the regulatory provisions of
PUHCA, including provisions relating to the issuance of securities, sales,
acquisitions of securities and utility assets, and services performed by
Progress Energy Service Company, LLC.
While various proposals, including the 2004 energy bill, have been introduced in
Congress regarding PUHCA, the prospects for legislative reform or repeal are
uncertain at this time.
11
REGULATORY MATTERS
GENERAL
PEC is subject to regulation in North Carolina by the North Carolina Utilities
Commission (NCUC), and in South Carolina by the Public Service Commission of
South Carolina (SCPSC) and PEF is subject to regulation in Florida by the
Florida Public Service Commission (FPSC) with respect to, among other things,
rates and service for electric energy sold at retail, retail service territory
cost recovery of unusual or unexpected expense, such as severe storm costs, and
issuances of securities. PEC and PEF are also subject to regulation by the
United States Nuclear Regulatory Commission (NRC). In addition, PEC and PEF are
subject to regulation by the FERC with respect to transmission and sales of
wholesale power, accounting and certain other matters. The underlying concept of
utility ratemaking is to set rates at a level that allows the utility to collect
revenues equal to its cost of providing service, including a reasonable rate of
return on its equity. Increased competition as a result of industry
restructuring may affect the ratemaking process.
NUCLEAR MATTERS
GENERAL
PEC owns and operates four nuclear generating units and PEF owns and operates
one nuclear generating unit regulated by the NRC under the Atomic Energy Act of
1954 and the Energy Reorganization Act of 1974. In the event of noncompliance,
the NRC has the authority to impose fines, set license conditions, shut down a
nuclear unit, or some combination of these, depending upon its assessment of the
severity of the situation, until compliance is achieved. Nuclear units are
periodically removed from service to accommodate normal refueling and
maintenance outages, repairs and certain other modifications.
The nuclear power industry faces uncertainties with respect to the cost and
long-term availability of sites for disposal of spent nuclear fuel and other
radioactive waste, compliance with changing regulatory requirements, nuclear
plant operations, increased capital outlays for modifications, the technological
and financial aspects of decommissioning plants at the end of their licensed
lives and requirements relating to nuclear insurance.
On April 19, 2004, the NRC announced that it has renewed the operating license
for PEC's Robinson Nuclear Plant (Robinson) for an additional 20 years through
July 2030. The original operating license of 40 years was set to expire in 2010.
NRC operating licenses held by PEC currently expire in December 2014 and
September 2016 for Brunswick Units 2 and 1, respectively. An application to
extend these licenses 20 years was submitted in October 2004. The NRC operating
license held by PEC for the Shearon Harris Nuclear Plant (Harris Plant)
currently expires in October 2026. An application to extend this license 20
years is expected to be submitted in the fourth quarter of 2006.
The NRC operating license held by PEF for Crystal River Unit No. 3 (CR3)
currently expires in December 2016. An application to extend this license 20
years is expected to be submitted in the first quarter of 2009.
A condition of the operating license for each unit requires an approved plan for
decontamination and decommissioning.
On February 27, 2004, PEC requested to have its license for the Independent
Spent Fuel Storage Installation at the Robinson Plant extended by 20 years with
an exemption request for an additional 20-year extension. Its current license is
due to expire in August 2006. PEC expects to receive this extension including
the exemption.
PRESSURIZED WATER REACTORS
In 2002, the NRC sent a bulletin to companies that hold licenses for pressurized
water reactors (PWRs) requiring information on the structural integrity of the
reactor vessel head and a basis for concluding that the vessel head will
continue to perform its function as a coolant pressure boundary. Inspections of
the vessel heads at the Company's PWR plants had been performed during previous
outages. At the Robinson and Harris Plants, inspections were completed in 2001,
and there was no degradation of the reactor vessel heads. The Company's
Brunswick Plant has a different design and is not affected by the issue.
Inspection of the vessel head at CR3 was performed during a previous outage, and
no degradation of the reactor vessel head was identified.
12
In 2002, the NRC issued an additional bulletin dealing with head leakage due to
cracks near the control rod nozzles, asking licensees to commit to high
inspection standards to ensure the more susceptible plants have no cracks. The
Robinson Plant is in this category and had a refueling outage in 2002. The
Company completed a series of examinations in 2002 of the entire reactor
pressure vessel head and found no indications of control rod drive mechanism
cracking and no corrosion of the head itself. During the outage, a walkdown of
the reactor coolant pressure boundary was also completed, and no corrosion was
found. The Robinson reactor head was re-inspected during its 2004 outage, and no
indication of control rod drive mechanism cracking or corrosion of the head was
observed. The head is scheduled for replacement in 2005. The Harris Plant is
ranked in the lowest susceptibility classification. PEF replaced the vessel head
at CR3 during its regularly scheduled refueling outage in 2003.
In 2003, the NRC issued an order requiring specific inspections of the reactor
pressure vessel head and associated penetration nozzles at PWRs. The Company
responded, stating that it intended to comply with the provisions of the order.
The NRC also issued a bulletin requesting PWR licensees to address inspection
plans for reactor pressure vessel lower head penetrations. The Company completed
a bare metal visual inspection of the vessel bottom at Robinson during its 2004
outage and at Harris and CR3 during their 2003 outages and found no signs of
corrosion or leakage at any unit. The Company plans to do additional, more
detailed inspections as part of the next scheduled 10-year in-service
inspections.
In February 2004, the NRC issued a revised order for inspection requirements for
reactor pressure vessel heads at PWRs. The Company has reviewed the required
inspection frequencies and has incorporated them into long-range plans. The
Harris Plant will complete the required nonvisual nondestructive examination
(NDE) inspection prior to February 2008. Both CR3 and Robinson will be required
to inspect their new heads within seven years or four refueling outages after
replacement. CR3 plans to inspect its new head prior to the end of 2009, and
Robinson will need to inspect its new head prior to the end of 2012.
SECURITY
The NRC has issued various orders since September 2001 with regard to security
at nuclear plants. These orders include additional restrictions on access,
increased security measures at nuclear facilities and closer coordination with
the Company's partners in intelligence, military, law enforcement and emergency
response at the federal, state and local levels. The Company completed the
requirements as outlined in the orders by the committed dates. As the NRC, other
governmental entities and the industry continue to consider security issues, it
is possible that more extensive security plans could be required.
SPENT FUEL AND OTHER HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (Nuclear Waste Act) provides the framework
for development by the federal government of interim storage and permanent
disposal facilities for high-level radioactive waste materials. The Nuclear
Waste Act promotes increased usage of interim storage of spent nuclear fuel at
existing nuclear plants. The Company will continue to maximize the use of spent
fuel storage capability within its own facilities for as long as feasible.
With certain modifications and additional approval by the NRC, including the
installation of onsite dry storage facilities at Robinson (2005) and Brunswick
(2010), PEC's spent nuclear fuel storage facilities will be sufficient to
provide storage space for spent fuel generated on PEC's system through the
expiration of the current operating licenses for all of PEC's nuclear generating
units.
With certain modifications and additional approval by the NRC, including the
installation of onsite dry storage facilities at PEF's nuclear unit, Crystal
River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities will be
sufficient to provide storage space for spent fuel generated on PEF's system
through the expiration of the operating license for CR3.
See Note 23E and Note 18D to the PGN and PEC Consolidated Financial Statements,
respectively, for a discussion of the Company's contract with the U.S.
Department of Energy (DOE) for spent nuclear waste.
DECOMMISSIONING
In PEC's and PEF's retail jurisdictions, provisions for nuclear decommissioning
costs are approved by the NCUC, the SCPSC and the FPSC and are based on
site-specific estimates that include the costs for removal of all radioactive
and other structures at the site. In the wholesale jurisdiction, the provisions
for nuclear decommissioning costs are approved by the FERC. See Note 6D for a
discussion of PEC and PEF's nuclear decommissioning costs.
13
ENVIRONMENTAL
In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, the Company is
subject to regulation by various federal, state and local authorities. The
Company considers itself to be in substantial compliance with those
environmental regulations currently applicable to its business and operations
and believes it has all necessary permits to conduct such operations.
Environmental laws and regulations constantly evolve and the ultimate costs of
compliance cannot always be accurately estimated. The estimated capital costs
associated with compliance with pollution control laws and regulations at the
Company's existing fossil facilities that the Company expects to incur from 2005
through 2007 are included in the "Capital Expenditures" discussion for Progress
Energy under PART II, ITEM 7, "Liquidity and Capital Resources."
The provisions of the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the
cleanup of hazardous waste sites. This statute imposes retroactive joint and
several liabilities. Some states, including North and South Carolina, have
similar types of legislation. Both electric utilities, Progress Fuels and
Progress Rail Services Corporation (Progress Rail) are periodically notified by
regulators such as the EPA and various state agencies of their involvement or
potential involvement in sites that may require investigation and/or
remediation.
There are presently several sites, including manufactured gas plant (MGP) sites,
with respect to which the Company has been notified by the EPA, the State of
North Carolina or the State of Florida of its potential liability, as a
potentially responsible party (PRP). Although the Company's subsidiaries may
incur costs at the sites about which they have been notified, based upon the
current status of these sites, the Company cannot determine the total costs that
may be incurred in connection with all sites at this time. See Note 22 for a
discussion of the Company's environmental matters.
EMPLOYEES
As of February 28, 2005, Progress Energy and its subsidiaries employed
approximately 15,700 full-time employees. Of this total, approximately 2,400
employees at PEF are represented by the International Brotherhood of Electrical
Workers (IBEW). The three-year labor contract with IBEW expires in December
2005.
The Company and some of its subsidiaries have a noncontributory defined benefit
retirement (pension) plan for substantially all full-time employees and an
employee stock purchase plan among other employee benefits. The Company and some
of its subsidiaries also provide contributory postretirement benefits, including
certain health care and life insurance benefits, for substantially all retired
employees.
On February 28, 2005, as part of a previously announced cost management
initiative, the executive officers of the Company approved a workforce
restructuring. The restructuring will result in a reduction of approximately 450
positions and is expected to be completed in September of 2005. In addition to
the workforce restructuring, the cost management initiative includes a voluntary
enhanced retirement program. See Note 24 for more information.
As of February 28, 2005, PEC employed approximately 5,100 full-time employees.
ELECTRIC - PEC
GENERAL
PEC is a public service corporation formed under the laws of North Carolina in
1926 and is primarily engaged in the generation, transmission, distribution and
sale of electricity in portions of North and South Carolina. At December 31,
2004, PEC had a total summer generating capacity (including jointly owned
capacity) of approximately 12,482 MW.
PEC distributes and sells electricity in 56 of the 100 counties in North
Carolina and 14 counties in northeastern South Carolina. The service territory
covers approximately 34,000 square miles, including a substantial portion of the
coastal plain of North Carolina extending to the Atlantic coast between the
Pamlico River and the South Carolina border, the lower Piedmont section of North
Carolina, an area in northeastern South Carolina and an area in western North
Carolina in and around the city of Asheville. At December 31, 2004, PEC was
14
providing electric services, retail and wholesale, to approximately 1.4 million
customers. Major wholesale power sales customers include North Carolina Eastern
Municipal Power Agency (Power Agency) and North Carolina Electric Membership
Corporation. PEC is subject to the rules and regulations of the FERC, the NCUC,
the SCPSC and the NRC. No single customer accounts for more than 10% of PEC's
revenues.
BILLED ELECTRIC REVENUES
PEC's electric revenues billed by customer class, for the last three years, are
shown as a percentage of total PEC electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2004 2003 2002
Residential 38% 36% 36%
Commercial 25% 24% 24%
Industrial 19% 18% 19%
Wholesale 16% 20% 19%
Other retail 2% 2% 2%
Major industries in PEC's service area include textiles, chemicals, metals,
paper, food, rubber and plastics, wood products and electronic machinery and
equipment.
FUEL AND PURCHASED POWER
Sources of Generation
PEC's consumption of various types of fuel depends on several factors, the most
important of which are the demand for electricity by PEC's customers, the
availability of various generating units, the availability and cost of fuel and
the requirements of federal and state regulatory agencies. PEC's total system
generation (including jointly owned capacity) by primary energy source, along
with purchased power for the last three years is presented in the following
table:
ENERGY MIX PERCENTAGES
2004 2003 2002
Coal 47% 46% 46%
Nuclear 43% 44% 42%
Purchased power 6% 7% 8%
Oil/Gas 3% 2% 3%
Hydro 1% 1% 1%
PEC is generally permitted to pass the cost of fuel and purchased power to its
customers through fuel adjustment clauses. The future prices for and
availability of various fuels discussed in this report cannot be predicted with
complete certainty. See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK and "Risk Factors." However, PEC
believes that its fuel supply contracts, as described below, will be adequate to
meet its fuel supply needs.
PEC's average fuel costs per million British thermal units (Btu) for the last
three years were as follows:
AVERAGE FUEL COST
(per million Btu)
2004 2003 2002
Coal $ 2.17 $ 2.00 $ 1.93
Nuclear 0.42 0.43 0.43
Oil 6.78 6.69 5.48
Gas 8.29 8.32 5.31
Hydro - - -
Weighted-average 1.57 1.43 1.38
15
Changes in the unit price for coal, oil and gas are due to market conditions.
Since these costs are primarily recovered through recovery clauses established
by regulators, fluctuations do not materially affect net income.
Coal
PEC anticipates a requirement of approximately 12.4 million to 13.0 million tons
of coal in 2005. Almost all of the coal will be supplied from Appalachian coal
sources in the United States and is primarily delivered by rail.
For 2005, PEC has short-term, intermediate and long-term agreements from various
sources for approximately 102% of its burn requirements of its coal units. All
of these contracts are at fixed prices adjusted annually. The contracts have
expiration dates ranging from 2005 to 2009. PEC will continue to sign contracts
of various lengths, terms and quality to meet its expected burn requirements.
All the coal to be purchased for PEC is considered to be low sulfur coal by
industry standards.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a uranium oxide
concentrate and the conversion of this concentrate into uranium hexafluoride.
Stages III and IV entail the enrichment of the uranium hexafluoride and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
PEC has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirement needs. PEC's nuclear fuel contracts
typically have terms ranging from five to ten years. For a discussion of PEC's
plans with respect to spent fuel storage, see PART I, ITEM 1, "Nuclear Matters."
Hydroelectric
Hydroelectric power is electric energy generated by the force of falling water.
PEC has three hydroelectric generating plants licensed by the FERC: Walters,
Tillery and Blewett. PEC also owns the Marshall Plant, which has a license
exemption. The total maximum dependable capacity for all four units is 218 MW.
PEC is seeking to relicense its Tillery and Blewett Plants. These plants'
licenses currently expire in April 2008. The Walters Plant license will expire
in 2034.
Oil & Gas
Oil and natural gas supply for PEC's generation fleet is purchased under term
and spot contracts from several suppliers. The cost of PEC's oil and gas is
determined by market prices as reported in certain industry publications. PEC
believes that it has access to an adequate supply of oil and gas for the
reasonably foreseeable future. PEC's natural gas transportation is purchased
under term firm transportation contracts with interstate pipelines. PEC also
purchases capacity on a seasonal basis from numerous shippers for its peaking
load requirements. PEC believes that existing contracts for oil are sufficient
to cover its requirements if natural gas is unavailable during a normal winter
period for PEC's combustion turbine and combined cycle fleet.
Purchased Power
PEC purchased approximately 4.0 million MWh, 4.5 million MWh and 5.2 million MWh
of its system energy requirements during 2004, 2003 and 2002, respectively, and
had available 1,498 MW, 1,810 MW and 1,737 MW of firm purchased capacity under
contract at the time of peak load during 2004, 2003 and 2002, respectively. PEC
may acquire additional purchased power capacity in the future to accommodate a
portion of its system load needs.
COMPETITION
Electric Industry Restructuring
PEC continues to monitor developments that may occur toward a more competitive
environment and actively participates in regulatory reform deliberations in
North Carolina and South Carolina. PEC expects that both the North Carolina and
South Carolina General Assemblies will continue to monitor the experiences of
states that have implemented electric restructuring legislation.
16
Regional Transmission Organizations
In October 2000, as a result of Order 2000, PEC, along with Duke Energy
Corporation and South Carolina Electric & Gas Company, filed an application with
the FERC for approval of a GridSouth RTO. In July 2001, the FERC issued an order
provisionally approving GridSouth. However, in July 2001, the FERC issued orders
recommending that companies in the southeast engage in a mediation to develop a
plan for a single RTO for the Southeast. PEC participated in the mediation. On
December 22, 2004, the FERC, citing superseding events, voted to close a portion
of the GridSouth docket. The GridSouth Companies asked the FERC for further
clarification as to the portions of the GridSouth docket it intended to address.
On March 2, 2005, the FERC affirmed that it only intended to close the mediation
portion of the GridSouth docket.
See Note 8D for additional discussion of current developments of GridSouth RTO.
Franchises
PEC has nonexclusive franchises with varying expiration dates in most of the
municipalities in which it distributes electric energy in North Carolina and
South Carolina. The general effect of these franchises is to provide for the
manner in which PEC occupies rights-of-way in incorporated areas of
municipalities for the purpose of constructing, operating and maintaining an
energy transmission and distribution system. Of these 239 franchises, 194 have
expiration dates ranging from 2008 to 2061 and 45 of these have no specific
expiration dates. All but 13 of the 194 franchises with expiration dates have a
term of sixty years. The exceptions include three franchises with terms of ten
years, one with a term of twenty years, six with terms of thirty years, two with
terms of forty years and one with a term of fifty years. PEC also serves within
a number of municipalities and in all of its unincorporated areas without
franchise agreements.
Wholesale Competition
See PART I, ITEM 1, "General," under Competition for a discussion of wholesale
competition.
Stranded Costs
See PART I, ITEM 1, "General," under Competition for a discussion of stranded
costs.
REGULATORY MATTERS
General
PEC is subject to the jurisdiction of the NCUC and SCPSC with respect to, among
other things, rates and service for electric energy sold at retail, retail
service territory and issuances of securities. In addition, PEC is subject to
regulation by the FERC with respect to transmission and sales of wholesale
power, accounting and certain other matters. The underlying concept of utility
ratemaking is to set rates at a level that allows the utility to collect
revenues equal to its cost of providing service plus a reasonable rate of return
on its equity. Increased competition as a result of industry restructuring may
affect the ratemaking process.
Retail Rate Matters
The NCUC and the SCPSC authorize retail "base rates" that are designed to
provide a utility with the opportunity to earn a specific rate of return on its
"rate base," or investment in utility plant. These rates are intended to cover
all reasonable and prudent expenses of utility operations and to provide
investors with a fair rate of return. In PEC's most recent rate cases in 1988,
the NCUC and the SCPSC each authorized a return on equity of 12.75% for PEC.
The Clean Smokestacks Act enacted in North Carolina in 2002 (NC Clean Air)
freezes PEC's base retail rates for five years unless there are extraordinary
events beyond the control of PEC, in which case PEC can petition for a rate
increase. See Note 22 and Note 8B to the PGN and PEC Consolidated Financial
Statements, respectively, for further discussion of PEC's rate freeze.
See Note 8B and Note 6B to the PGN and PEC Consolidated Financial Statements,
respectively, for further discussion of PEC's retail rate developments during
2004.
17
Wholesale Rate Matters
PEC is subject to regulation by the FERC with respect to rates for transmission
and sale of electric energy at wholesale, the interconnection of facilities in
interstate commerce (other than interconnections for use in the event of certain
emergency situations), the licensing and operation of hydroelectric projects
and, to the extent the FERC determines, accounting policies and practices. PEC
and its wholesale customers last agreed to a general increase in wholesale rates
in 1988; however, wholesale rates have been adjusted since that time through
contractual negotiations.
See PART I, ITEM 1, "General," under Competition for further discussion of FERC
screens for assessing generation market power.
Fuel Cost Recovery
PEC's operating costs not covered by the utility's base rates include fuel and
purchased power. Each state commission allows electric utilities to recover a
certain portion of these costs through various cost recovery clauses, to the
extent the respective commission determines in an annual hearing that such costs
are prudent. Costs recovered by PEC, by state, are as follows:
o North Carolina - fuel costs and the fuel portion of purchased power
o South Carolina - fuel costs, certain purchased power costs, and emission
allowance expense
Each state commission's determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
NUCLEAR MATTERS
PEC is implementing power uprate projects at its nuclear facilities to increase
electrical generation output. A power uprate was completed at the Harris Plant
during 2001 and at the Robinson Nuclear Plant in 2002. At the Brunswick Plant,
Unit 1 increased its capacity by 52 MW in 2002 and by 66 MW in 2004. Brunswick
Unit 2 increased its capacity by 89 MW in 2003, and an additional increase is
planned for 2005. The total increased generation from all these projects is
estimated to be approximately 300 MW. See PART I, ITEM 1, "Nuclear Matters," for
further discussion of these and other nuclear matters.
ENVIRONMENTAL MATTERS
In the areas of air quality, water quality, control of toxic substances and
hazardous and solid wastes and other environmental matters, PEC is subject to
regulation by various federal, state and local authorities. PEC considers itself
to be in substantial compliance with those environmental regulations currently
applicable to its business and operations and believes it has all necessary
permits to conduct such operations. Environmental laws and regulations
constantly evolve, and the ultimate costs of compliance cannot always be
accurately estimated. The estimated capital costs associated with compliance
with pollution control laws and regulations at the PEC's existing fossil
facilities that it expects to incur from 2005 through 2007 are included in the
"Capital Expenditures" discussion under PART II, ITEM 7, "Liquidity and Capital
Resources."
The provisions of the Comprehensive Environmental Response, CERCLA, authorize
the EPA to require the cleanup of hazardous waste sites. This statute imposes
retroactive joint and several liabilities. Some states, including North and
South Carolina, have similar types of legislation. There are presently nine
former MGP sites and a number of other sites with respect to which PEC has been
notified by the EPA or the State of North Carolina of its potential liability,
as a PRP. Although PEC may incur costs at the sites about which it has been
notified, based upon the current status of these sites, PEC cannot determine the
total costs that may be incurred in connection with all sites at this time. See
Notes 22 and 17 to the PGN and PEC Consolidated Financial Statements,
respectively, for a discussion of PEC's environmental matters.
18
ELECTRIC - PEF
GENERAL
PEF, incorporated in Florida in 1899, is an operating public utility engaged in
the generation, transmission, distribution and sale of electricity. At December
31, 2004, PEF had a total summer generating capacity (including jointly owned
capacity) of approximately 8,544 MW.
PEF provided electric service during 2004 to an average of 1.5 million customers
in west central Florida. Its service territory covers approximately 20,000
square miles and includes the densely populated areas around Orlando, as well as
the cities of St. Petersburg and Clearwater. PEF is interconnected with 21
municipal and 9 rural electric cooperative systems. Major wholesale power sales
customers include Seminole Electric Cooperative, Inc., Florida Power & Light
Company, Tampa Electric Company and the City of Bartow. PEF is subject to the
rules and regulations of the FERC, the FPSC and the NRC. No single customer
accounts for more than 10% of PEF's revenues.
BILLED ELECTRIC REVENUES
PEF's electric revenues, billed by customer class for the last three years, are
shown as a percentage of total PEF electric revenues in the table below:
BILLED ELECTRIC REVENUES
Revenue Class 2004 2003 2002
Residential 53% 55% 55%
Commercial 25% 24% 24%
Industrial 8% 7% 7%
Other retail 6% 6% 6%
Wholesale 8% 8% 8%
Important industries in PEF's territory include phosphate rock mining and
processing, electronics design and manufacturing, and citrus and other food
processing. Other important commercial activities are tourism, health care,
construction and agriculture.
FUEL AND PURCHASED POWER
Sources of Generation
PEF's consumption of various types of fuel depends on several factors, the most
important of which are the demand for electricity by PEF's customers, the
availability of various generating units, the availability and cost of fuel and
the requirements of federal and state regulatory agencies. PEF's total system
generation (including jointly owned capacity) by primary energy source, along
with purchased power for the last three years is presented in the following
table:
ENERGY MIX PERCENTAGES
Fuel Type 2004 2003 2002
Coal (a) 32% 36% 33%
Oil 16% 16% 16%
Nuclear 16% 14% 15%
Gas 16% 13% 15%
Purchased Power 20% 21% 21%
(a) Amounts include synthetic fuel from unrelated third parties.
PEF is generally permitted to pass the cost of fuel and purchased power to its
customers through fuel adjustment clauses. The future prices for and
availability of various fuels discussed in this report cannot be predicted with
19
complete certainty. See "Commodity Price Risk" under Item 7A, QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK and "Risk Factors." However, PEF
believes that its fuel supply contracts, as described below, will be adequate to
meet its fuel supply needs.
PEF's average fuel costs per million Btu for the last three years were as
follows:
AVERAGE FUEL COST
(per million Btu)
2004 2003 2002
Coal (a) $ 2.30 $ 2.42 $ 2.43
Oil 4.67 4.38 3.77
Nuclear 0.49 0.50 0.46
Gas 6.41 5.98 4.06
Weighted-average 3.21 3.07 2.60
(a) Amounts include synthetic fuel from unrelated third parties.
Changes in the unit price for coal, oil and gas are due to market conditions.
Since these costs are primarily recovered through recovery clauses established
by regulators, fluctuations do not materially affect net income.
Coal
PEF anticipates a combined requirement of approximately 6 million tons of coal
in 2005. Approximately 70% of the coal is expected to be supplied from
Appalachian coal sources in the United States and 30% supplied from coal sources
in South America. Approximately 67% of the fuel is expected to be delivered by
rail and the remainder by barge. All of this fuel is supplied by Progress Fuels,
a subsidiary of Progress Energy, pursuant to contracts between PEF and Progress
Fuels.
For 2005, Progress Fuels has medium-term and long-term contracts with various
sources for approximately 115% of the burn requirements of PEF's coal units.
Supply disruption caused by recent hurricanes has made it necessary to build
inventories back to the traditional level of 45 days. These contracts have price
adjustment provisions and have expiration dates ranging from 2005 to 2006.
Progress Fuels will continue to sign contracts of various lengths, terms and
quality to meet PEF's expected burn requirements. All the coal to be purchased
for PEF is considered to be low sulfur coal by industry standards.
Oil and Gas
Oil and natural gas supply for PEF's generation fleet is purchased under term
and spot contracts from several suppliers. The majority of the cost of PEF's oil
and gas is determined by market prices as reported in certain industry
publications. PEF believes that it has access to an adequate supply of oil and
gas for the reasonably foreseeable future. PEF's natural gas transportation is
purchased under term firm transportation contracts with interstate pipelines.
PEF purchases capacity on a seasonal basis from numerous shippers and interstate
pipelines to serve its peaking load requirements. PEF also uses interruptible
transportation contracts on certain occasions when available. PEF believes that
existing contracts for oil are sufficient to cover its requirements if natural
gas is unavailable during certain time periods.
Nuclear
Nuclear fuel is processed through four distinct stages. Stages I and II involve
the mining and milling of the natural uranium ore to produce a uranium oxide
concentrate and the conversion of this concentrate into uranium hexafluoride.
Stages III and IV entail the enrichment of the uranium hexafluoride and the
fabrication of the enriched uranium hexafluoride into usable fuel assemblies.
PEF has sufficient uranium, conversion, enrichment and fabrication contracts to
meet its near-term nuclear fuel requirements needs. PEF's nuclear fuel contracts
typically have terms ranging from five to ten years. For a discussion of PEF's
plans with respect to spent fuel storage, see PART I, ITEM I, "Nuclear Matters."
20
Purchased Power
PEF, along with other Florida utilities, buys and sells power in the wholesale
market on a short-term and long-term basis. At December 31, 2004, PEF had a
variety of purchase power agreements for the purchase of approximately 1,498 MW
of firm power. These agreements include (1) long-term contracts for the purchase
of about 484 MW of purchased power with other investor-owned utilities,
including a contract with The Southern Company for approximately 414 MW, and (2)
approximately 821 MW of capacity under contract with certain QFs. The capacity
currently available from QFs represents about 9% of PEF's total installed system
capacity.
COMPETITION
Electric Industry Restructuring
PEF continues to monitor developments toward a more competitive environment and
actively participates in regulatory reform deliberations in Florida. Movement
toward deregulation in this state has been affected by developments related to
deregulation of the electric industry in other states.
In response to a legislative directive, the FPSC and the Florida Department of
Environment and Protection (FDEP) submitted in February 2003 a joint report on
renewable electric generating technologies for Florida. The report assessed the
feasibility and potential magnitude of renewable electric capacity for Florida,
and summarized the mechanisms other states have adopted to encourage renewable
energy. The report did not contain any policy recommendations. The Company
cannot anticipate when, or if, restructuring legislation will be enacted or if
the Company would be able to support it in its final form.
Regional Transmission Organizations
As a result of Order 2000, PEF, Florida Power & Light Company and Tampa Electric
Company (collectively, the Applicants) filed with the FERC in October 2000 an
application for approval of a GridFlorida RTO. The GridFlorida proposal is
pending before both the FERC and the FPSC. The FERC provisionally approved the
structure and governance of GridFlorida. In December 2003, the FPSC ordered
further state proceedings and established a collaborative workshop process to be
conducted during 2004. In June 2004, the workshop process was abated pending
completion of a cost-benefit study currently scheduled to be presented at a FPSC
workshop on May 25, 2005, with subsequent action by the FPSC to be thereafter
determined. It is unknown when the FERC or the FPSC will take final action with
regard to the status of GridFlorida or what the impact of further proceedings
will have on the Company's earnings, revenues or pricing. See Note 8D for a
discussion of current developments of GridFlorida RTO.
Franchises
PEF holds franchises with varying expiration dates in 108 of the municipalities
in which it distributes electric energy. PEF also serves 13 other municipalities
and in all its unincorporated areas without franchise agreements. The general
purpose of these franchises is to provide for the manner in which PEF occupies
rights-of-way in incorporated areas of municipalities for the purpose of
constructing, operating and maintaining an energy transmission and distribution
system.
Approximately 39% of PEF's total utility revenues for 2004 were from the
incorporated areas of the 108 municipalities that had franchise ordinances
during the year. Since 2000, PEF has renewed 34 expiring franchises and reached
agreement on a franchise with a city that did not previously have a franchise.
Franchises with five municipalities have expired without renewal.
All but 27 of the existing franchises cover a 30-year period from the date
enacted. The exceptions are 23 franchises, each with a term of 10 years and
expiring between 2005 and 2013; two franchises each with a term of 15 years and
expiring in 2017; one 30-year franchise that was extended in 1999 for 5 years
expiring in 2005; and one franchise with a term of 20 years expiring in 2020. Of
the 108 franchises, 46 expire between January 1, 2005, and December 31, 2015,
and 62 expire between January 1, 2016, and December 31, 2034.
Ongoing negotiations and, in some cases, litigation are taking place with
certain municipalities to reach agreement on franchise terms and to enact new
franchise ordinances. See PART II, ITEM 7, "Other Matters," for a discussion of
PEF's franchise litigation.
21
Wholesale Competition
See PART I, ITEM 1, "General," under Competition for a discussion of wholesale
competition.
Stranded Costs
The largest stranded cost exposure for PEF is its commitment to QFs. PEF has
taken a proactive approach to this industry issue. PEF continues to seek ways to
address the impact of escalating payments from contracts it was obligated to
sign under provisions of PURPA. See PART I, ITEM 1, "General," under Competition
for further discussion.
REGULATORY MATTERS
General
PEF is subject to the jurisdiction of the FPSC with respect to, among other
things, rates and service for electric energy sold at retail, retail service
territory and issuances of securities. In addition, PEF is subject to regulation
by the FERC with respect to transmission and sales of wholesale power,
accounting and certain other matters. The underlying concept of utility
ratemaking is to set rates at a level that allows the utility to collect
revenues equal to its cost of providing service plus a reasonable rate of return
on its equity. Increased competition as a result of industry restructuring may
affect the ratemaking process.
Retail Rate Matters
The FPSC authorizes retail "base rates" that are designed to provide a utility
with the opportunity to earn a specific rate of return on its "rate base," or
average investment in utility plant. These rates are intended to cover all
reasonable and prudent expenses of utility operations and to provide investors
with a fair rate of return.
In March 2002, the parties in PEF's rate case entered into a Stipulation and
Settlement Agreement (the Agreement) related to retail rate matters. The
Agreement was approved by the FPSC and is generally effective from May 1, 2002,
through December 31, 2005. The Agreement eliminates the authorized Return on
Equity (ROE) range normally used by the FPSC for the purpose of addressing
earning levels, provided, however, that if PEF's base rate earnings fall below a
10% return on equity, PEF may petition the FPSC to amend its base rates. The
Agreement is described in more detail in Note 8C.
In January 2005, in anticipation of the expiration of the Agreement, PEF
notified the FPSC that it intends to request an increase in its base rates,
effective January 1, 2006. In its notice, PEF requested the FPSC to approve
calendar year 2006 as the projected test period for setting new base rates. The
request for increased base rates is based on the fact that PEF has faced
significant cost increases over the past decade and expects its operational
costs to continue to increase. These costs include the costs associated with
completion of the Hines 3 generation facility, extraordinary hurricane damage
costs including capital costs which are not expected to be directly recoverable,
the need to replenish the depleted storm reserve and the expected infrastructure
investment necessary to meet high customer expectations, coupled with the
demands placed on PEF as a result of strong customer growth. Related risks are
described in more detail in the "Risk Factors" section.
Fuel and Other Cost Recovery
PEF's operating costs not covered by the utility's base rates include fuel,
purchased power, energy conservation expenses and specific environmental costs.
The state commission allows electric utilities to recover certain of these costs
through various cost recovery clauses, to the extent the commission determines
in an annual hearing that such costs are prudent. In addition, in December 2002,
the FPSC approved an Environmental Cost Recovery Clause (ECRC), which permits
the Company to recover the costs of specified environmental projects to the
extent these expenses are found to be prudent in an annual hearing and not
otherwise included in base rates. Costs are recovered through this recovery
clause in the same manner as the other existing clause mechanisms.
The FPSC's annual determination results in the addition of a rider to a
utility's base rates to reflect the approval of these costs and to reflect any
past over- or under-recovery. Due to the regulatory treatment of these costs and
the method allowed for recovery, changes from year to year have no material
impact on operating results.
22
In accordance with a regulatory order, PEF accrues $6 million annually to a
storm damage reserve and is allowed to defer losses in excess of the accumulated
reserve for major storms. Under the order, the storm reserve is charged with
operation and maintenance expenses related to storm restoration and with capital
expenditures related to storm restoration that are in excess of expenditures
assuming normal operating conditions.
As of December 31, 2004, $291 million of hurricane restoration costs in excess
of the previously recorded storm reserve of $47 million had been classified as a
regulatory asset recognizing the probable recoverability of these costs. On
November 2, 2004, PEF filed a petition with the FPSC to recover $252 million of
storm costs plus interest from retail ratepayers over a two-year period.
Hearings on PEF's petition for recovery of $252 million of storm costs filed
with the FPSC are scheduled to begin on March 30, 2005 (See Note 3).
PEF's January 2005 notice to the FPSC of its intent to file for an increase in
its base rates effective January 1, 2006, anticipates the need to replenish the
depleted storm reserve balance and adjust the annual $6 million accrual in light
of recent storm history to restore the reserve to an adequate level over a
reasonable time period.
NUCLEAR MATTERS
In late 2002, CR3 received a license amendment authorizing a small power level
increase. The power level increase of approximately four MW was implemented in
February 2003.
See PART I, ITEM 1, "Nuclear Matters," for further discussion of these and other
nuclear matters.
ENVIRONMENTAL MATTERS
There are two former MGP sites and other sites associated with PEF that have
required or are anticipated to require investigation and/or remediation costs.
In addition, there are distribution substations and transformers that are also
anticipated to incur investigation and remediation costs. At this time, PEF
cannot determine the total costs that may be incurred in connection with the
remediation of all sites. See Note 22 for further discussion of these
environmental matters.
FUELS
The Fuels business segment owns an array of assets that produce, transport and
deliver fuel and provide related services for the open market. The Fuels
business segment has subsidiaries that produce oil and gas products, blend and
transload coal, mine coal and produce a solid coal-based synthetic fuel. This
product has been classified as a synthetic fuel within the meaning of Section 29
of the Internal Revenue Service Code (Section 29). Sales of synthetic fuel
therefore qualify for tax credits, as more fully described below.
The current combined assets of Fuels that are involved in fuel extraction,
manufacturing and delivery include:
o Natural gas properties in Texas and Louisiana producing approximately 22
Bcf equivalent per year;
o Five terminals on the Ohio River and its tributaries, part of the trucking,
rail and barge network for coal delivery;
o Two active coal-mining complexes, expected to produce approximately 3 to 5
million tons per year:
o Four wholly owned synthetic fuel entities, a majority owned synthetic fuel
entity and a minority interest in one synthetic fuel entity, capable of
producing up to 16 million tons per year;
o Majority-ownership in a barge partnership that transports coal products
from the mouth of the Mississippi River to PEF's Crystal River facility in
Florida.
During 2003, Progress Fuels acquired approximately 200 natural gas-producing
wells with proven reserves of approximately 190 Bcf from Republic Energy, Inc.
and three other privately owned companies, all headquartered in Texas. The total
cash purchase price for the transactions was approximately $168 million (See
Note 5B).
In December 2004, the Company sold certain gas-producing properties and related
assets owned by Winchester Production, a wholly owned subsidiary of Progress
Fuels Corporation (See Note 4A).
23
SYNTHETIC FUELS TAX CREDITS
The Company has substantial operations associated with the production of
coal-based synthetic fuels. The production and sale of these products qualifies
for federal income tax credits so long as certain requirements are satisfied.
These operations are subject to numerous risks.
Although the Company believes that it operates its synthetic fuel facilities in
compliance with applicable legal requirements for claiming the credits, its four
Earthco facilities are under audit by the IRS. IRS field auditors have taken an
adverse position with respect to the Company's compliance with one of these
legal requirements, and if the Company fails to prevail with respect to this
position it could incur significant liability and/or lose the ability to claim
the benefit of tax credits carried forward or generated in the future.
Similarly, the Financial Accounting Standards Board may issue new accounting
rules that would require that uncertain tax benefits (such as those associated
with the Earthco plants) be probable of being sustained in order to be recorded
on the financial statements; if adopted, this provision could have an adverse
financial impact on the Company.
The Company's ability to utilize tax credits is dependent on having sufficient
tax liability. Any conditions that negatively impact the Company's tax
liability, such as weather, could also diminish the Company's ability to utilize
credits, including those previously generated, and the synthetic fuel is
generally not economical to produce absent the credits. Finally, the tax credits
associated with synthetic fuels may be phased out if market prices for crude oil
exceed certain prices.
The Company's synthetic fuel operations and related risks are described in more
detail in Note 23E and in the "Risk Factors" section.
COMPETITION
Fuels' synthetic fuel operations and coal operations compete in the eastern
United States steam and industrial coal markets. Factors contributing to the
success in these markets include a competitive cost structure and strategic
locations. There are, however, numerous competitors in each of these markets,
although no one competitor is dominant in any industry.
Fuels' gas production operations compete in the East Texas and North Louisiana
region. Factors contributing to success include a competitive cost structure.
Although there are numerous small, independent competitors in this market, the
major oil and gas producers dominate this industry.
ENVIRONMENTAL MATTERS
See Note 22 for a discussion of Fuels' environmental matters.
COMPETITIVE COMMERCIAL OPERATIONS (CCO)
The CCO business segment is responsible for marketing energy in the wholesale
market outside the realm of retail regulation. CCO currently owns six
electricity generation facilities with approximately 3,100 MW of generation
capacity, and it has contractual rights to an additional 2,500 MW of generation
capacity from mixed fuel generation facilities through its agreements with 16
Georgia electric membership cooperatives (EMCs). CCO has contracts for its
combined production capacity of approximately 77% for 2005, approximately 81%
for 2006 and approximately 75% for 2007.
The energy CCO markets is sold under both term contracts and in the spot market.
CCO purchases fuel, such as oil and natural gas for use in the generation of
electricity. The Company believes that there are adequate sources of fuel for
CCO's expected fuel requirements. CCO also uses financial instruments to manage
the risks associated with fluctuating commodity prices to hedge the economic
value of its portfolio of assets.
In May 2003, PVI acquired from Williams Energy Marketing and Trading, a
subsidiary of the Williams Companies, Inc., a long-term full-requirements power
supply agreement at fixed prices with Jackson, for $188 million. In 2004, PVI
executed wholesale power-supply agreements with 15 Georgia electric membership
cooperatives (EMCs) to serve their electricity needs through 2010.
24
COMPETITION
CCO does not operate in the same environment as regulated utilities. It operates
specifically in the wholesale market, which means competition is its primary
driver. CCO competes in the eastern United States utility markets. Factors
contributing to the success in these markets include a competitive cost
structure and strategic locations.
RAIL SERVICES
The Rail Services business segment is one of the largest integrated and
diversified suppliers of railroad and transit system products and services in
North America and is headquartered in Albertville, Alabama. Rail Services'
principal business functions include two business units: Locomotive and Railcar
Services (LRS) and Engineering and Track-work Services (ETS).
The LRS unit is primarily focused on railroad rolling stock that includes
freight cars, transit cars and locomotives, the repair and maintenance of these
units, the manufacturing or reconditioning of major components for these units
and scrap metal recycling. The ETS unit focuses on rail and other track
components, the infrastructure that supports the operation of rolling stock, and
the equipment used in maintaining the railroad infrastructure and right-of-way.
The Recycling division of the LRS unit supports both business units through its
reclamation of reconditionable material and is a major supplier of recyclable
scrap metal to North American steel mills and foundries through its processing
locations as well as its scrap brokerage operations.
Rail Services' key railroad industry customers are Class 1 railroads, regional
and short line railroads, North American transit systems, railcar and locomotive
builders, and railcar lessors. The U.S. operations are located in 23 states and
include further geographic coverage through mobile crews on a selected basis.
This coverage allows for Rail Services' customer base to be dispersed throughout
the U.S., Canada and Mexico.
In February 2005, Progress Energy signed a definitive agreement to sell its
Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million. Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.
In March 2003, the Company signed a letter of intent to sell the majority of
Railcar Ltd., assets to The Andersons, Inc. A definitive purchase agreement was
signed in November 2003 and the transaction closed in February 2004 (See Note
4C).
ENVIRONMENTAL MATTERS
See Note 22 for a discussion of Rail's environmental matters.
CORPORATE AND OTHER BUSINESS SEGMENT
GENERAL
The Corporate and Other Businesses segment includes the operations of PT LLC and
Strategic Resource Solutions Corp. (SRS) and holding company operations. This
segment also includes other nonregulated operations of PEC and FPC.
PROGRESS TELECOM LLC
In December 2003, PTC and Caronet, both wholly owned subsidiaries of Progress
Energy, and EPIK, a wholly owned subsidiary of Odyssey, contributed
substantially all of their assets and transferred certain liabilities to PT LLC,
a subsidiary of PTC. Subsequently, the stock of Caronet was sold to an affiliate
of Odyssey for $2 million in cash and Caronet became a wholly owned subsidiary
of Odyssey. Following consummation of all the transactions described above, PTC
holds a 55% ownership interest in, and is the parent of, PT LLC; Odyssey holds a
combined 45% ownership interest in PT LLC through EPIK and Caronet. The accounts
of PT LLC have been included in the Company's Consolidated Financial Statements
since the transaction date.
25
PT LLC has data fiber network transport capabilities that stretch from New York
to Miami, Florida, with gateways to Latin America, and conducts primarily a
carrier's carrier business. PT LLC markets wholesale fiber-optic-based capacity
service in the Eastern United States to long-distance carriers, Internet service
providers and other telecommunications companies. PT LLC also markets wireless
structure attachments to wireless communication companies and governmental
entities. At December 31, 2004, PT LLC owned and managed more than 8,500 route
miles and more than 420,000 fiber miles of fiber-optic cable.
PT LLC competes with other providers of fiber-optic telecommunications services,
including local exchange carriers and competitive access providers, in the
Eastern United States.
Lease revenue for dedicated transport and data services is generally billed in
advance on a fixed rate basis and recognized over the period the services are
provided. Revenues relating to design and construction of wireless
infrastructure are recognized upon completion of services for each completed
phase of design and construction.
For additional information regarding asset and investment impairments related to
the Company's investments in the telecommunications industry, see Notes 7 and 10
to the PEC Consolidated Financial Statements.
26
ELECTRIC UTILITY REGULATED OPERATING STATISTICS - PROGRESS ENERGY
- ----------------------------------------------------------------------------------------------------------------------------
Years Ended December 31
2004 2003 2002 2001 2000(d)
- ----------------------------------------------------------------------------------------------------------------------------
Energy supply (millions of kilowatt-hours)
Generated - Steam 50,782 51,501 49,734 48,732 31,132
Nuclear 30,445 30,576 30,126 27,301 23,857
Combustion Turbines/Combined Cycle 9,695 7,819 8,522 6,644 1,337
Hydro 802 955 491 245 441
Purchased 13,466 13,848 14,305 14,469 5,724
- ----------------------------------------------------------------------------------------------------------------------------
Total energy supply (Company share) 105,190 104,699 103,178 97,391 62,491
Jointly owned share (a) 5,395 5,213 5,258 4,886 4,505
- ----------------------------------------------------------------------------------------------------------------------------
Total system energy supply 110,585 109,912 108,436 102,277 66,996
- ----------------------------------------------------------------------------------------------------------------------------
Average fuel cost (per million Btu)
Fossil $ 3.17 $ 2.94 $ 2.62 $ 2.46 $ 1.96
Nuclear fuel $ 0.44 $ 0.44 $ 0.44 $ 0.45 $ 0.45
All fuels $ 2.21 $ 2.05 $ 1.84 $ 1.77 $ 1.30
Energy sales (millions of kilowatt-hours)
Retail
Residential 35,350 34,712 33,993 31,976 15,365
Commercial 24,753 24,110 23,888 23,033 12,221
Industrial 17,105 16,749 16,924 17,204 14,762
Other Retail 4,475 4,382 4,287 4,149 1,626
Wholesale 18,323 19,841 19,204 17,715 15,012
Unbilled 449 189 275 (1,045) 1,098
- ----------------------------------------------------------------------------------------------------------------------------
Total energy sales 100,455 99,983 98,571 93,032 60,084
Company uses and losses 3,936 3,753 3,604 3,478 2,286
- ----------------------------------------------------------------------------------------------------------------------------
Total energy requirements 104,391 103,736 102,175 96,510 62,370
- ----------------------------------------------------------------------------------------------------------------------------
Electric revenues (in millions)
Retail $ 6,066 $ 5,620 $ 5,515 $ 5,462 $ 2,799
Wholesale 843 915 881 923 665
Miscellaneous revenue 244 206 205 172 81
- ----------------------------------------------------------------------------------------------------------------------------
Total electric revenues $ 7,153 $ 6,741 $ 6,601 $ 6,557 $ 3,545
- ----------------------------------------------------------------------------------------------------------------------------
Peak demand of firm load (thousands of kW)
System (b) 19,711 19,876 20,365 19,166 18,874
Company 19,126 19,235 19,746 18,564 18,272
Total regulated capability at year-end (thousands of kW)
Fossil plants 16,522 16,522 16,006 15,826 (e) 14,747
Nuclear plants 4,286 (h) 4,220 (g) 4,127 (f) 4,008 4,008
Hydro plants 218 218 218 218 218
Purchased 2,852 2,826 2,929 2,890 2,278
- ----------------------------------------------------------------------------------------------------------------------------
Total system capability 23,878 23,786 23,280 22,942 21,251
Less jointly owned portion (c) 714 698 682 668 662
- ----------------------------------------------------------------------------------------------------------------------------
Total Company capability - regulated 23,164 23,088 22,598 22,274 20,589
- ----------------------------------------------------------------------------------------------------------------------------
(a) Amounts represent co-owner's share of the energy supplied from the six
generating facilities that are jointly owned.
(b) Amounts represent the combined summer noncoincident system net peaks for
PEC and PEF.
(c) For PEC, this represents Power Agency's retained share of jointly owned
facilities per the Power Coordination Agreement between PEC and Power
Agency.
(d) Amounts include information for PEF since November 30, 2000, the date of
acquisition.
(e) Amount includes 459 MW related to Rowan units that were transferred to PVI
in February 2002.
(f) Amount includes power uprates for Harris, Brunswick 1 and Robinson. The
Maximum Dependable Capability (MDC) for Harris was restated January 2002;
the MDCs for Brunswick 1 and Robinson were restated January 2003.
(g) Amount includes power uprates for CR3 and Brunswick 2. The MDCs were
restated January 2004.
(h) Amount includes power uprate for Brunswick 1; the MDC was restated January
2005.
27
REGULATED OPERATING STATISTICS - PROGRESS ENERGY CAROLINAS
- ----------------------------------------------------------------------------------------------------------------------------
Years Ended December 31
2004 2003 2002 2001 2000
- ----------------------------------------------------------------------------------------------------------------------------
Energy supply (millions of kilowatt-hours)
Generated - Steam 28,632 28,522 28,547 27,913 29,520
Nuclear 23,742 24,537 23,425 21,321 23,275
Combustion Turbines/Combined Cycle 1,926 1,344 1,934 802 733
Hydro 802 955 491 245 441
Purchased 4,023 4,467 5,213 5,296 4,878
- ----------------------------------------------------------------------------------------------------------------------------
Total energy supply (Company share) 59,125 59,825 59,610 55,577 58,847
Power Agency share (a) 4,794 4,670 4,659 4,348 4,505
- ----------------------------------------------------------------------------------------------------------------------------
Total system energy supply 63,919 64,495 64,269 59,925 63,352
- ----------------------------------------------------------------------------------------------------------------------------
Average fuel cost (per million Btu)
Fossil $ 2.52 $ 2.29 $ 2,16 $ 1.91 $ 1.83
Nuclear fuel $ 0.42 $ 0.43 $ 0.43 $ 0.44 $ 0.45
All fuels $ 1.57 $ 1.43 $ 1.38 $ 1.26 $ 1.21
Energy sales (millions of kilowatt-hours)
Retail
Residential 16,003 15,283 15,239 14,372 14,091
Commercial 13,019 12,557 12,468 11,972 11,432
Industrial 13,036 12,749 13,089 13,332 14,446
Other Retail 1,432 1,408 1,437 1,423 1,423
Wholesale 13,221 15,518 15,024 12,996 14,582
Unbilled 91 (44) 270 (534) 679
- ----------------------------------------------------------------------------------------------------------------------------
Total energy sales 56,802 57,471 57,527 53,561 56,653
Company uses and losses 2,323 2,354 2,083 2,016 2,194
- ----------------------------------------------------------------------------------------------------------------------------
Total energy requirements 59,125 59,825 59,610 55,577 58,847
- ----------------------------------------------------------------------------------------------------------------------------
Electric revenues (in millions)
Retail $ 2,953 $ 2,824 $ 2,796 $ 2,666 $ 2,609
Wholesale 575 687 651 634 577
Miscellaneous revenue 100 78 92 44 122
- ----------------------------------------------------------------------------------------------------------------------------
Total electric revenues $ 3,628 $ 3,589 $ 3,539 $ 3,344 $ 3,308
- ----------------------------------------------------------------------------------------------------------------------------
Peak demand of firm load (thousands of kW) (g)
System 11,192 11,771 11,977 11,376 11,157
Company 10,607 11,130 11,358 10,774 10,555
Total regulated capability at year-end (thousands of kW)
Fossil plants 8,816 8,816 8,816 8,648 (c) 7,569
Nuclear plants 3,448 (f) 3,382 (e) 3,293 (d) 3,174 3,174
Hydro plants 218 218 218 218 218
Purchased 1,545 1,513 1,617 1,586 978
- ----------------------------------------------------------------------------------------------------------------------------
Total system capability 14,027 13,929 13,944 13,626 11,939
Less Power Agency-owned portion (b) 645 629 613 599 593
- ----------------------------------------------------------------------------------------------------------------------------
Total Company capability 13,382 13,300 13,331 13,027 11,346
- ----------------------------------------------------------------------------------------------------------------------------
(a) Amounts represent Power Agency's share of the energy supplied from the four
generating facilities that are jointly owned.
(b) Amounts represent Power Agency's retained share of jointly owned facilities
per the Power Coordination Agreement between PEC and Power Agency.
(c) Amount includes 459 MW related to Rowan units that were transferred to PVI
in February 2002.
(d) Amount includes power upgrades for Harris, Brunswick 1 and Robinson. The
MDC for Harris was restated January 2002; the MDCs for Brunswick 1 and
Robinson were restated January 2003.
(e) Amount includes power uprate for Brunswick 2; the MDC was restated January
2004.
(f) Amount includes power uprate for Brunswick 1; the MDC was restated January
2005.
(g) Amount is the summer peak demand.
28
ITEM 2. PROPERTIES
The Company believes that its physical properties and those of its subsidiaries
are adequate to carry on its and their businesses as currently conducted. The
Company and its subsidiaries maintain property insurance against loss or damage
by fire or other perils to the extent that such property is usually insured.
ELECTRIC - PEC
At December 31, 2004, PEC's 18 generating plants represent a flexible mix of
fossil, nuclear, hydroelectric, combustion turbines and combined cycle
resources, with a total summer generating capacity of 12,482 MW. Of this total,
Power Agency owns approximately 694 MW. On December 31, 2004, PEC had the
following generating facilities:
- -----------------------------------------------------------------------------------------------------------
PEC Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- -----------------------------------------------------------------------------------------------------------
STEAM TURBINES
Asheville Skyland, N.C. 2 1964-1971 Coal 100 392
Cape Fear Moncure, N.C. 2 1956-1958 Coal 100 316
Lee Goldsboro, N.C. 3 1952-1962 Coal 100 407
Mayo Roxboro, N.C. 1 1983 Coal 83.83 745 (b)
Robinson Hartsville, S.C. 1 1960 Coal 100 174
Roxboro Roxboro, N.C. 4 1966-1980 Coal 96.32 (c) 2,462 (b)
Sutton Wilmington, N.C. 3 1954-1972 Coal 100 613
Weatherspoon Lumberton, N.C. 3 1949-1952 Coal 100 176
-------- ---------------
Total 19 5,285
COMBINED CYCLE
Cape Fear Moncure, N.C. 2 1969 Oil 100 84
Richmond Hamlet, N.C. 1 2002 Gas/Oil 100 472
-------- ---------------
Total 3 556
COMBUSTION TURBINES
Asheville Skyland, N.C. 2 1999-2000 Gas/Oil 100 330
Blewett Lilesville, N.C. 4 1971 Oil 100 52
Darlington Hartsville, S.C. 13 1974-1997 Gas/Oil 100 812
Lee Goldsboro, N.C. 4 1968-1971 Oil 100 91
Morehead City Morehead City, N.C. 1 1968 Oil 100 15
Richmond Hamlet, N.C. 5 2001-2002 Gas/Oil 100 775
Robinson Hartsville, S.C. 1 1968 Gas/Oil 100 15
Roxboro Roxboro, N.C. 1 1968 Oil 100 15
Sutton Wilmington, N.C. 3 1968-1969 Gas/Oil 100 64
Wayne County Goldsboro, N.C. 4 2000 Gas/Oil 100 668
Weatherspoon Lumberton, N.C. 4 1970-1971 Gas/Oil 100 138
-------- ---------------
Total 42 2,975
NUCLEAR
Brunswick Southport, N.C. 2 1975-1977 Uranium 81.67 1,838 (b)(d)
Harris New Hill, N.C. 1 1987 Uranium 83.83 900 (b)
Robinson Hartsville, S.C. 1 1971 Uranium 100 710
-------- ---------------
Total 4 3,448
HYDRO
Blewett Lilesville, N.C. 6 1912 Water 100 22
Marshall Marshall, N.C. 2 1910 Water 100 5
Tillery Mount Gilead, N.C. 4 1928-1960 Water 100 86
Walters Waterville, N.C. 3 1930 Water 100 105
-------- ---------------
Total 15 218
TOTAL 83 12,482
- -----------------------------------------------------------------------------------------------------------
(a) Amounts represent PEC's net summer peak rating, gross of co-ownership
interest in plant capacity.
(b) Facilities are jointly owned by PEC and Power Agency. The capacities shown
include Power Agency's share.
(c) PEC and Power Agency are co-owners of Unit 4 at the Roxboro Plant. PEC's
ownership interest in this 700 MW turbine is 87.06%.
(d) During 2004, a power uprate increased the net summer capability of Unit 1
to 938 MW. The MDC was restated in January 2005.
29
At December 31, 2004, including both the total generating capacity of 12,482 MW
and the total firm contracts for purchased power of approximately 1,545 MW, PEC
had total capacity resources of approximately 14,027 MW.
The Power Agency has undivided ownership interests of 18.33% in Brunswick Unit
Nos. 1 and 2, 12.94% in Roxboro Unit No. 4 and 16.17% in the Harris Plant and
Mayo Unit No. 1. Otherwise, PEC has good and marketable title to its principal
plants and important units, subject to the lien of its mortgage and deed of
trust, with minor exceptions, restrictions, and reservations in conveyances, as
well as minor defects of the nature ordinarily found in properties of similar
character and magnitude. PEC also owns certain easements over private property
on which transmission and distribution lines are located.
At December 31, 2004, PEC had approximately 6,000 circuit miles of transmission
lines including 300 miles of 500 kilovolt (kV) lines and 3,000 miles of 230 kV
lines. PEC also had approximately 45,000 circuit miles of overhead distribution
conductor and 18,000 circuit miles of underground distribution cable.
Distribution and transmission substations in service had a transformer capacity
of approximately 12,000,000 kilovolt-ampere (kVA) in 2,405 transformers.
Distribution line transformers numbered approximately 509,700 with an aggregate
capacity of approximately 21,000,000 kVA.
ELECTRIC - PEF
At December 31, 2004, PEF's 14 generating plants represent a flexible mix of
fossil, nuclear, combustion turbine and combined cycle resources with a total
summer generating capacity (including jointly owned capacity) of 8,544 MW. At
December 31, 2004, PEF had the following generating facilities:
- ------------------------------------------------------------------------------------------------------------
PEF Summer Net
No. of In-Service Ownership Capability (a)
Facility Location Units Date Fuel (in %) (in MW)
- ------------------------------------------------------------------------------------------------------------
STEAM TURBINES
Anclote Holiday, Fla. 2 1974-1978 Gas/Oil 100 993
Bartow St. Petersburg, Fla. 3 1958-1963 Gas/Oil 100 444
Crystal River Crystal River, Fla. 4 1966-1984 Coal 100 2,302
Suwannee River Live Oak, Fla. 3 1953-1956 Gas/Oil 100 143
-------- -----------------
Total 12 3,882
COMBINED CYCLE
Hines Bartow, Fla. 2 1999-2003 Gas/Oil 100 998
Tiger Bay Fort Meade, Fla. 1 1997 Gas 100 207
-------- -----------------
Total 3 1,205
COMBUSTION TURBINES
Avon Park Avon Park, Fla. 2 1968 Gas/Oil 100 52
Bartow St. Petersburg, Fla. 4 1958-1972 Gas/Oil 100 187
Bayboro St. Petersburg, Fla. 4 1973 Oil 100 184
DeBary DeBary, Fla. 10 1975-1992 Gas/Oil 100 667
Higgins Oldsmar, Fla. 4 1969-1970 Gas/Oil 100 122
Intercession City Intercession City, 14 1974-2000 Gas/Oil 100 (c) 1,041 (b)
Fla.
Rio Pinar Rio Pinar, Fla. 1 1970 Oil 100 13
Suwannee River Live Oak, Fla. 3 1980 Gas/Oil 100 164
Turner Enterprise, Fla. 4 1970-1974 Oil 100 154
University of Gainesville, Fla. 1 1994 Gas 100 35
Florida Cogeneration
-------- -----------------
Total 47 2,619
NUCLEAR
Crystal River Crystal River, Fla. 1 1977 Uranium 91.78 838 (b)
-------- -----------------
Total 1 838
TOTAL 63 8,544
- ------------------------------------------------------------------------------------------------------------
(a) Amounts represent PEF's net summer peak rating, gross of co-ownership
interest in plant capacity.
(b) Facilities are jointly owned. The capacities shown include joint owners'
share.
(c) PEF and Georgia Power Company (Georgia Power) are co-owners of a 143 MW
advanced combustion turbine located at PEF's Intercession City site (P11).
Georgia Power has the exclusive right to the output of this unit during the
months of June through September. PEF has that right for the remainder of
the year.
At December 31, 2004, PEF had total capacity resources of approximately 10,042
MW, including both the total generating capacity of 8,544 MW and the total firm
contracts for purchased power of 1,498 MW.
30
Several entities have acquired undivided ownership interests in CR3 in the
aggregate amount of 8.22%. The joint ownership participants are: City of Alachua
- - 0.08%, City of Bushnell - 0.04%, City of Gainesville - 1.41%, Kissimmee
Utility Authority - 0.68%, City of Leesburg - 0.82%, Utilities Commission of the
City of New Smyrna Beach - 0.56%, City of Ocala - 1.33%, Orlando Utilities
Commission - 1.60% and Seminole Electric Cooperative, Inc. - 1.70%. PEF and
Georgia Power are co-owners of a 143 MW advance combustion turbine located at
PEF's Intercession City site (P11). Georgia Power has the exclusive right to the
output of this unit during the months of June through September. PEF has that
right for the remainder of the year. Otherwise, PEF has good and marketable
title to its principal plants and important units, subject to the lien of its
mortgage and deed of trust, with minor exceptions, restrictions and reservations
in conveyances, as well as minor defects of the nature ordinarily found in
properties of similar character and magnitude. PEF also owns certain easements
over private property on which transmission and distribution lines are located.
At December 31, 2004, PEF had approximately 5,000 circuit miles of transmission
lines including 200 miles of 500 kV lines and about 1,500 miles of 230 kV lines.
PEF also had approximately, 22,000 circuit miles of overhead distribution
conductor and 13,000 circuit miles of underground distribution cable.
Distribution and transmission substations in service had a transformer capacity
of approximately 45,000,000 kVA in 616 transformers. Distribution line
transformers numbered approximately 365,000 with an aggregate capacity of
approximately 18,000,000 kVA.
FUELS
Progress Fuels controls, either directly or through subsidiaries, coal reserves
located in eastern Kentucky and southwestern Virginia of approximately 46
million tons and controls, through mineral leases, additional estimated coal
reserves of approximately 48 million tons. The reserves controlled include
substantial quantities of high quality, low sulfur coal that is appropriate for
use at PEF's existing generating units. Progress Fuels' total production of coal
during 2004 was approximately 3.4 million tons.
In connection with its coal operations, Progress Fuels' business units own and
operate surface and underground mines, coal processing and loadout facilities in
southeastern Kentucky and southwestern Virginia. Other subsidiaries own and
operate a river terminal facility in eastern Kentucky, a railcar-to-barge
loading facility in West Virginia, two bulk commodity terminals on the Kanawha
River near Charleston, West Virginia, and a bulk commodity terminal on the Ohio
River near Huntington, West Virginia. Progress Fuels and its subsidiaries employ
both Company and contract miners in their mining activities.
The Fuels business segment, through its business units, has an interest in six
synthetic fuel entities. Four of the entities are wholly owned, one is majority
owned and one is minority owned. These facilities are in six different locations
in West Virginia, Virginia and Kentucky.
Fuels' oil and gas production in 2004 was 30.4 Bcf equivalent. Fuels has oil and
gas leases in East Texas and Louisiana with total proven oil and gas reserves of
approximately 247 Bcf equivalent.
CCO
At December 31, 2004, CCO had the following nonregulated generation plants in
service.
- --------------------------------------------------------------------------------------------------------------
Construction Commercial Configuration/
Project Location Start Date Operation Date Number of Units MW (a)
- --------------------------------------------------------------------------------------------------------------
Monroe Units 1 and 2 Monroe, Ga. 4Q 1998/1Q 2000 4Q 1999/2Q 2001 Simple-Cycle, 2 315
Rowan Phase I (b) Salisbury, N.C. 1Q 2000 2Q 2001 Simple-Cycle, 3 459
Walton (c) Monroe, Ga. 2Q 2000 2Q 2001 Simple-Cycle, 3 460
DeSoto Units Arcadia, Fla. 2Q 2001 2Q 2002 Simple-Cycle, 2 320
Effingham Rincon, Ga. 1Q 2001 3Q 2003 Combined-Cycle, 1 480
Rowan Phase II (b) Salisbury, N.C. 4Q 2001 2Q 2003 Combined-Cycle, 1 466
Washington (c) Sandersville, 2Q 2002 2Q 2003 Simple-Cycle, 4 600
Ga.
- --------------------------------------------------------------------------------------------------------------
TOTAL 3,100
- --------------------------------------------------------------------------------------------------------------
(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 2,000 railcars and 50
locomotives that are used for the transportation and shipping of coal, steel and
other bulk products.
In February 2005, Progress Energy signed a definitive agreement to sell its
Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million. Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.
PT LLC
PT LLC provides wholesale telecommunications services throughout the
Southeastern United States. PT LLC incorporates more than 420,000 fiber miles of
fiber-optic cable in its network, including more than 189 Points-of-Presence, or
physical locations where a presence for network access exists.
32
ITEM 3. LEGAL PROCEEDINGS
Legal proceedings are included in the discussion of the Company's business in
PART I, ITEM 1 under "Environmental Matters," and are incorporated by reference
herein.
1. U.S. Global, LLC v. Progress Energy, Inc. et al., Case No. 03004028-03 and
Progress Synfuel Holdings, Inc. et al., v. U.S. Global, LLC, Case No.
03004028-03
A number of Progress Energy, Inc. subsidiaries and affiliates are parties to two
lawsuits arising out of an Asset Purchase Agreement dated as of October 19,
1999, by and among U.S. Global LLC (Global), Earthco, certain affiliates of
Earthco (collectively the Earthco Sellers), EFC Synfuel LLC (which is owned
indirectly by Progress Energy, Inc.) and certain of its affiliates, including
Solid Energy LLC, Solid Fuel LLC, Ceredo Synfuel LLC, Gulf Coast Synfuel LLC
(currently named Sandy River Synfuel LLC) (collectively the Progress
Affiliates), as amended by an amendment to Purchase Agreement as of August 23,
2000 (the Asset Purchase Agreement). Global has asserted that pursuant to the
Asset Purchase Agreement it is entitled to (1) an interest in two synthetic fuel
facilities currently owned by the Progress Affiliates, and (2) an option to
purchase additional interests in the two synthetic fuel facilities.
The first suit, U.S. Global, LLC v. Progress Energy, Inc. et al., was filed in
the Circuit Court for Broward County, Florida, in March 2003 (the Florida Global
Case). The Florida Global Case asserts claims for breach of the Asset Purchase
Agreement and other contract and tort claims related to the Progress Affiliates'
alleged interference with Global's rights under the Asset Purchase Agreement.
The Florida Global Case requests an unspecified amount of compensatory damages,
as well as declaratory relief. Following briefing and argument on a number of
dispositive motions on successive versions of Global's complaint, on August 16,
2004, the Progress Affiliates answered the Fourth Amended Complaint by generally
denying all of Global's substantive allegations and asserting numerous
affirmative defenses. The parties are currently engaged in discovery in the
Florida Global Case.
The second suit, Progress Synfuel Holdings, Inc. et al. v. U.S. Global, LLC, was
filed by the Progress Affiliates in the Superior Court for Wake County, North
Carolina, seeking declaratory relief consistent with the Company's
interpretation of the asset Purchase Agreement (the North Carolina Global Case).
Global was served with the North Carolina Global Case on April 17, 2003.
On May 15, 2003, Global moved to dismiss the North Carolina Global Case for lack
of personal jurisdiction over Global. In the alternative, Global requested that
the court decline to exercise its discretion to hear the Progress Affiliates'
declaratory judgment action. On August 7, 2003, the Wake County Superior court
denied Global's motion to dismiss and entered an order staying the North
Carolina Global Case, pending the outcome of the Florida Global Case. The
Progress Affiliates appealed the Superior court's order staying the case. By
order dated September 7, 2004, the North Carolina Court of Appeals dismissed the
Progress Affiliates' appeal.
The Company cannot predict the outcome of these matters, but will vigorously
defend against the allegations.
2. In re Progress Energy, Inc. Securities Litigation, Master File No.
04-CV-636 (JES)
On February 3, 2004, Progress Energy, Inc. was served with a class action
complaint alleging violations of federal security laws in connection with the
Company's issuance of Contingent Value Obligations (CVOs). The action was filed
by Gerber Asset Management LLC in the United States District Court for the
Southern District of New York and names Progress Energy, Inc.'s former Chairman
William Cavanaugh III and Progress Energy, Inc. as defendants. The Complaint
alleges that Progress Energy failed to timely disclose the impact of the
Alternative Minimum Tax required under Sections 55-59 of the Internal Revenue
Code (Code) on the value of certain CVOs issued in connection with the Florida
Progress Corporation merger. The suit seeks unspecified compensatory damages, as
well as attorneys' fees and litigation costs.
On March 31, 2004, a second class action complaint was filed by Stanley Fried,
Raymond X. Talamantes and Jacquelin Talamantes against William Cavanaugh III and
Progress Energy, Inc. in the United States District Court for the Southern
District of New York alleging violations of federal securities laws arising out
of the Company's issuance of CVOs nearly identical to those alleged in the
February 3, 2004, Gerber Asset Management complaint. On April 29, 2004, the
Honorable John E. Sprizzo ordered among other things that (1) the two class
action cases be consolidated, (2) Peak6 Capital Management LLC shall serve as
the lead plaintiff in the consolidated action, and (3) the lead plaintiff shall
file a consolidated amended complaint on or before June 15, 2004.
33
The lead plaintiff filed a consolidated amended complaint on June 15, 2004. In
addition to the allegations asserted in the Gerber Asset Management and Fried
complaints, the consolidated amended complaint alleges that the Company failed
to disclose that excess fuel credits could not be carried over from one tax year
into later years. On July 30, 2004, the Company filed a motion to dismiss the
complaint; plaintiff submitted its opposition brief on September 14, 2004. The
Court heard oral argument on the Company's motion to dismiss on November 15,
2004; it has not, to date, rendered a decision on this motion.
The Company cannot predict the outcome of this matter, but will vigorously
defend against the allegations.
For a discussion of certain other legal matters, see Note 23E to the Progress
Energy Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
NONE
34
EXECUTIVE OFFICERS OF THE REGISTRANTS
Name Age Recent Business Experience
*Robert B. McGehee 61 Chairman and Chief Executive Officer, Progress Energy, May 2004 and
March 2004, respectively, to present. Mr. McGehee joined the Company
(formerly CP&L) in 1997 as Senior Vice President and General Counsel.
Since that time, he has held several senior management positions of
increasing responsibility. Most recently, Mr. McGehee served as
President and Chief Operating Officer of the Company, having
responsibility for the day-to-day operations of the Company's regulated
and nonregulated businesses. Prior to that, Mr. McGehee served as
President and Chief Executive Officer of Progress Energy Service
Company, LLC.
Before joining Progress Energy, Mr. McGehee chaired the board of Wise
Carter Child & Caraway, a law firm headquartered in Jackson, Miss. He
primarily handled corporation, contract, nuclear regulatory and
employment matters. During the 1990s, he also provided significant
counsel to U.S. companies on reorganizations, business growth
initiatives and preparing for deregulation and other industry changes.
William S. Orser 60 Group President, Energy Supply, PEC and PEF, November 2000 to present.
(separating from the Company, effective April 1, 2005.) Mr. Orser is
responsible for the operation of 38 utility and nonregulated power
plants of Progress Energy. He also oversees plant construction and the
organizations that support those plants, including the Company's System
Planning and Operations function.
Mr. Orser joined Progress Energy (formerly CP&L) in 1993 as Executive
Vice President and Chief Nuclear Officer. He later became Executive Vice
President - Energy Supply, PEC, a position he held until the acquisition
of FPC in 2000.
Before joining the Company in April 1993, Mr. Orser was an executive at
the Detroit Edison Company, serving as Executive Vice President -
Nuclear Generation. Previously, he worked with Portland General Electric
Co.
William D. Johnson 51 President and Chief Operating Officer, Progress Energy, January 2005 to
present; Group President, PEC, January 2005 to present; Executive Vice
President, PEC and PEF, November 2000 to present. Mr. Johnson has been
with Progress Energy (formerly CP&L) since 1992 and most recently served
as Group President, Energy Delivery, Progress Energy, January 2004 to
December 2004. Prior to that, he was President, CEO and Corporate
Secretary, Progress Energy Service Company, LLC, October 2002 to
December 2003. He also served as Executive Vice President - Corporate
Relations & Administrative Services, General Counsel and Secretary of
Progress Energy. Mr. Johnson served as Vice President - Legal Department
and Corporate Secretary, CP&L from 1997 to 1999.
Before joining Progress Energy, Johnson was a partner with the Raleigh
office of Hunton & Williams, where he specialized in the representation
of utilities.
35
Peter M. Scott III 55 President and Chief Executive Officer, Progress Energy Service Company,
LLC, January 2004 to present; Executive Vice President, PEC and PEF,
2000 to present. Mr. Scott has been with the Company since May 2000 and
most recently served as Executive Vice President and Chief Financial
Officer of Progress Energy, Inc., May 2000 to December 2003. In that
position, Mr. Scott oversaw the Company's strategic planning, financial
and enterprise risk management functions.
Before joining Progress Energy, Mr. Scott was the president of Scott,
Madden & Associates, Inc., a general management consulting firm
headquartered in Raleigh, N.C. that he founded in 1983. The firm served
clients in a number of industries, including energy and
telecommunications. Particular practice area specialties for Mr. Scott
included strategic planning and operations management.
Geoffrey S. Chatas 42 Executive Vice President and Chief Financial Officer, Progress Energy,
Inc., Progress Energy Service Company, LLC, FPC, PEC and PEF, January
2004 to present. Mr. Chatas oversees the Company's accounting, strategic
planning, tax, financial and regulatory services and enterprise risk
management functions. He previously served as Senior Vice President,
Progress Energy, October 2003 to December 2003.
Mr. Chatas served in various positions with American Electric Power
(AEP), a multi-state energy holding company based in Columbus, Ohio from
1997 until he joined Progress Energy. Mr. Chatas' last position at AEP
was Senior Vice President - Finance and Treasurer for AEP. During his
time at AEP, he managed investor relations and corporate finance. In
addition, Mr. Chatas held executive financial positions at Banc One and
Citibank.
Robert H. Bazemore, Jr. 50 Chief Accounting Officer and Controller, Progress Energy, Inc., June
2000 to present; Controller, FPC and PEF, November 2000 to present;
Chief Accounting Officer, FPC, November 2000 to present; Vice President
and Controller, Progress Energy Service Company, LLC, August 2000 to
present; Chief Accounting Officer and Controller, PEC, May 2000 to
present. Mr. Bazemore has been with Progress Energy (formerly CP&L)
since 1986 and has served in a number of roles in corporate support and
field positions, including Director, CP&L, Operations & Environmental
Support Department, December 1998 to May 2000; Manager, CP&L Financial &
Regulatory Accounting, September 1995 to December 1998.
Prior to joining Progress Energy, Mr. Bazemore worked in managerial and
accounting positions with companies in Roanoke, Va. and Jacksonville,
Fla.
Donald K. Davis 59 Executive Vice President, PEC, May 2000 to present. Mr. Davis is also
President and Chief Executive Officer, SRS, June 2000 to present and was
President and Chief Executive Officer, NCNG, July 2000 to September
2003. Mr. Davis joined the Company in May 2000 as Executive Vice
President, Gas and Energy Services.
Before joining the Company, Mr. Davis was Chairman, President and Chief
Executive Officer of Yankee Atomic Electric Company, and served as
Chairman, President and Chief Executive Officer of Connecticut Atomic
36
Power Company from 1997 to May 2000 where he was responsible for two
electric wholesale generating companies. Before joining Yankee Atomic
Power Co., Davis served as a principal of PRISM Consulting Inc., a
utility management consulting firm he founded in 1992.
Fred N. Day IV 61 President and Chief Executive Officer, PEC, October 2003 to present;
Executive Vice President, PEF, November 2000 to present. Mr. Day
oversees all aspects of Carolinas Delivery operations, including
distribution and customer service, transmission, and products and
services. He previously served as Executive Vice President, PEC and PEF.
During his more than 30 years with Progress Energy (formerly CP&L), Mr.
Day has held several management positions of increasing responsibility.
He was promoted to Vice President - Western Region in 1995.
*H. William Habermeyer, Jr. 62 President and Chief Executive Officer, PEF, November 2000 to present.
Mr. Habermeyer joined Progress Energy (formerly PEC) in 1993 after a
career in the U.S. Navy. During his tenure with the Company, Mr.
Habermeyer has served as Vice President - Nuclear Services and
Environmental Support; Vice President - Nuclear Engineering; and Vice
President - Western Region. While overseeing Western Region operations,
Mr. Habermeyer was responsible for regional distribution management,
customer support and community relations.
C. S. Hinnant 60 Senior Vice President and Chief Nuclear Officer, PEC, June 1998 to
present. Mr. Hinnant is also Senior Vice President, PEF, November 2000
to present. Mr. Hinnant joined Progress Energy (formerly CP&L) in 1972
at the Brunswick Nuclear Plant near Southport, N.C., where he held
several positions in the startup testing and operating organizations. He
left Progress Energy in 1976 to work for Babcock and Wilcox in the
Commercial Nuclear Power Division, returning to Progress Energy in 1977.
Since that time, he has served in various management positions at three
of Progress Energy's nuclear plant sites.
*Jeffrey J. Lyash 43 Senior Vice President, PEF, November 2003 to present. Mr. Lyash oversees
all aspects of energy delivery operations for PEF. Prior to coming to
PEF, Mr. Lyash was Vice President - Transmission in Energy Delivery in
the Carolinas since January 2002.
Mr. Lyash joined Progress Energy in 1993 and spent his first eight years
with the Company at the Brunswick Nuclear Plant in Southport, N.C. His
last position at Brunswick was as Director of site operations.
John R. McArthur 49 Senior Vice President, General Counsel and Secretary of Progress Energy,
January 2004 to present. Mr. McArthur oversees the Audit Services,
Corporate Communications, Legal, Regulatory and Corporate Relations -
Florida, and State Public Affairs departments, and the Environmental and
Health and Safety sections. Mr. McArthur is also Senior Vice President
and Corporate Secretary, FPC and PEC, and Senior Vice President, PEF,
January 1 to present. Previously, he served the Company as Senior Vice
President - Corporate Relations (December 2002 to December 2003) and as
Vice President - Public Affairs (December 2001 to December 2002).
Before joining Progress Energy in December 2001, Mr. McArthur was a
member of North Carolina Governor Mike Easley's senior management team,
37
handling major policy initiatives as well as media and legal affairs. He
also directed Governor Easley's transition team after the election of
2000.
From November of 1997 until November of 2000, Mr. McArthur handled state
government affairs in 10 southeastern states for General Electric Co.
Prior to joining General Electric Co., Mr. McArthur served as chief
counsel in the North Carolina Attorney General's office, where he
supervised utility, consumer, health care, and environmental protection
issues. Before that, he was a partner at Hunton & Williams.
E. Michael Williams 56 Senior Vice President, PEC and PEF, June 2000 and November 2000,
respectively, to present.
Before joining the Company in 2000, Mr. Williams was with Central and
Southwest Corp., Inc. and subsidiaries for 28 years and served in
various positions prior to becoming Vice President - Fossil Generation
in Dallas.
Lloyd M. Yates 44 Senior Vice President, PEC, January 2005 to present. Mr. Yates is
responsible for managing the four regional vice presidents in the PEC
organization. He served PEC as Vice President - Transmission from
November 2003 to December 2004. Mr. Yates served as Vice President -
Fossil Generation for PEC from 1998 to 2003.
Before joining the Company in 1998, Mr. Yates was with PECO Energy,
where he had served in a number of engineering and management roles over
16 years. His last position with PECO was as general manager -Operations
in the Company's power operations group.
*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, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
Progress Energy
Progress Energy's Common Stock is listed on the New York Stock Exchange. The
high and low intra-day stock sales prices for each quarter for the past two
years, and the dividends declared per share are as follows:
- --------------------------------------------------------------------------------
2004 High Low Dividends Declared
- --------------------------------------------------------------------------------
First Quarter $ 47.95 $ 43.02 $0.575
Second Quarter 47.50 40.09 0.575
Third Quarter 44.32 40.76 0.575
Fourth Quarter 46.10 40.47 0.590
- --------------------------------------------------------------------------------
2003 High Low Dividends Declared
- --------------------------------------------------------------------------------
First Quarter $46.10 $37.45 $0.560
Second Quarter 48.00 38.99 0.560
Third Quarter 45.15 39.60 0.560
Fourth Quarter 46.00 41.60 0.575
- --------------------------------------------------------------------------------
The December 31 closing price of the Company's Common Stock was $45.24 for 2004
and $45.26 for 2003. As of March 4, 2005, the Company had 67,160 holders of
record of Common Stock.
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Progress
Energy's subsidiaries have provisions restricting dividends in certain limited
circumstances (See Note 13B).
Issuer purchases of equity securities for fourth quarter of 2004 are as follows:
- ----------------------------------------------------------------------------------------------------------------
(a) (b) (c) (d)
Maximum Number (or
Total Number of Shares Approximate Dollar
Total Number of Average (or Units) Purchased as Value) of Shares (or
Shares Price Paid Part of Publicly Units) that May Yet Be
(or Units) Per Share Announced Plans or Purchased Under the
Period Purchased(1) (or Unit) Programs(1) Plans or Programs(1)
- ----------------------------------------------------------------------------------------------------------------
October 1 - October 31(2) 191,436 $ 41.90 N/A N/A
- ----------------------------------------------------------------------------------------------------------------
November 1 - November 30 N/A N/A N/A N/A
- ----------------------------------------------------------------------------------------------------------------
December 1 - December 31 N/A N/A N/A N/A
- ----------------------------------------------------------------------------------------------------------------
Total: 191,436 $ 41.90 N/A N/A
- ----------------------------------------------------------------------------------------------------------------
(1) As of December 31, 2004, Progress Energy does not have any publicly
announced plans or programs to purchase shares of its common stock.
(2) All shares were purchased in open-market transactions by the plan
administrator to satisfy share delivery requirements under the Progress
Energy 401(k) Savings and Stock Ownership Plan (See Note 11A).
PEC
Since 2000, Progress Energy has owned all of PEC's common stock, and as a result
there is no established public trading market for the stock. PEC has not issued
or repurchased any equity securities since becoming a wholly owned subsidiary of
Progress Energy. For the past three years, PEC has paid quarterly dividends to
Progress Energy totaling the amounts shown in the Statements of Common Equity in
the PEC Consolidated Financial Statements. PEC has provisions restricting
dividends in certain limited circumstances (See Note 8 and 13 to the PEC
Consolidated Financial Statements). PEC does not have any equity compensation
plans under which its equity securities are issued.
39
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.
(in millions, except per share data)
- ----------------------------------------------------------------------------------------------------------------------
Years Ended December 31 2004 2003 2002 2001 2000(a)
- ----------------------------------------------------------------------------------------------------------------------
Operating results
Operating revenues $ 9,772 $ 8,741 $ 8,091 $ 8,129 $ 3,769
Income from continuing
operations before cumulative $ 753 $ 811 $ 552 $ 541 $ 478
effect
Net Income $ 759 $ 782 $ 528 $ 542 $ 478
Per share data
Basic earnings
Income from continuing
operations $ 3.11 $ 3.42 $ 2.54 $ 2.64 $ 3.04
Net income $ 3.13 $ 3.30 $ 2.43 $ 2.65 $ 3.04
Diluted earnings
Income from continuing
operations $ 3.10 $ 3.40 $ 2.53 $ 2.63 $ 3.03
Net income $ 3.12 $ 3.28 $ 2.42 $ 2.64 $ 3.03
Assets (c) $ 25,993 $ 26,093 $ 24,272 $ 23,701 $ 22,875
Capitalization
Common stock equity $ 7,633 $ 7,444 $ 6,677 $ 6,004 $ 5,424
Preferred stock of subsidiaries - not
subject to mandatory redemption 93 93 93 93 93
Minority interest 36 30 18 12 -
Long-term debt, net (b) 9,521 9,934 9,747 8,619 4,904
Current portion of long-term debt 349 868 275 688 184
Short-term obligations 684 4 695 942 4,959
- ---------------------------------------------------------------------------------------------------------------------
Total capitalization and total debt $ 18,316 $ 18,373 $ 17,505 $ 16,358 $ 15,564
- ---------------------------------------------------------------------------------------------------------------------
Dividends declared per common
share $ 2.32 $ 2.26 $ 2.20 $ 2.14 $ 2.08
- ---------------------------------------------------------------------------------------------------------------------
(a) Operating results and balance sheet data include information for FPC since
November 30, 2000, the date of acquisition.
(b) Includes long-term debt to affiliated trust of $270 million at December 31,
2004, and 2003 (See Note 19).
(c) All periods have been restated for the reclassification of certain cost of
removal amounts.
40
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.
- ------------------------------------------------------------------------------------------------------------------
(in millions)
Years Ended December 31 2004 2003 2002 2001 2000(a)
- ------------------------------------------------------------------------------------------------------------------
Operating results
Operating revenues $ 3,629 $ 3,600 $ 3,554 $ 3,360 $ 3,528
Net income $ 461 $ 482 $ 431 $ 364 $ 461
Earnings for common stock $ 458 $ 479 $ 428 $ 361 $ 458
Assets (c) $ 10,787 $ 10,938 $ 10,442 $ 10,640 $ 10,552
Capitalization
Common stock equity $ 3,072 $ 3,237 $ 3,089 $ 3,095 $ 2,852
Preferred stock - not subject to
mandatory redemption 59 59 59 59 59
Long-term debt, net 2,750 3,086 3,048 2,698 3,134
Current portion of long-term debt 300 300 - 600 -
Short-term obligations (b) 337 29 438 309 486
- ------------------------------------------------------------------------------------------------------------------
Total capitalization and total debt $ 6,518 $ 6,711 $ 6,634 $ 6,761 $ 6,531
- ------------------------------------------------------------------------------------------------------------------
(a) Operating results and balance sheet data do not include information for
NCNG, SRS, Monroe Power Company or PVI subsequent to July 1, 2000, the date
PEC distributed its ownership interest in the stock of these companies to
Progress Energy.
(b) Includes notes payable to affiliated companies, related to the money pool
program, of $116 million, $25 million and $48 million at December 31, 2004,
2003 and 2001, respectively.
(c) All periods have been restated for the reclassification of certain cost of
removal amounts.
41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following Management's Discussion and Analysis contains forward-looking
statements that involve estimates, projections, goals, forecasts, assumptions,
risks and uncertainties that could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. Please review
the "Risk Factors" sections and "SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for
a discussion of the factors that may impact any such forward-looking statements
made herein.
Management's Discussion and Analysis should be read in conjunction with the
Progress Energy Consolidated Financial Statements.
INTRODUCTION
The Company's reportable business segments and their primary operations include:
o Progress Energy Carolinas Electric (PEC Electric) - primarily engaged
in the generation, transmission, distribution and sale of electricity
in portions of North Carolina and South Carolina;
o Progress Energy Florida (PEF) - primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of
Florida;
o Competitive Commercial Operations (CCO) - engaged in nonregulated
electric generation operations and marketing activities primarily in
the southeastern United States;
o Fuels - primarily engaged in natural gas production in Texas and
Louisiana, coal mining and related services, and the production of
synthetic fuels and related services, which are located in Kentucky,
West Virginia and Virginia; and
o Rail Services (Rail) - engaged in various rail and railcar-related
services in 23 states, Mexico and Canada.
The Progress Ventures business unit consists of the Fuels and CCO operating
segments. The Corporate and Other category includes other businesses engaged in
other nonregulated business areas, including telecommunications, primarily in
the eastern United States, and energy services operations and holding company
results, which do not meet the requirements for separate segment reporting
disclosure.
In 2004, the Company realigned its business segments to no longer report the
other nonregulated businesses as a reportable business segment. For comparative
purposes, 2003 and 2002 segment information has been restated to align with the
2004 reporting structure.
Strategy
Progress Energy is an integrated energy company, with its primary focus on the
end-use and wholesale electricity markets. The Company operates in retail
utility markets in the southeastern United States and competitive markets in the
eastern United States. The target is to develop a business mix of approximately
80% regulated and 20% nonregulated business. The Company is focused on achieving
the following key goals: restoring balance sheet strength and flexibility,
disciplined capital and operations and maintenance (O&M) management to support
earnings and current dividend policy and achieving constructive regulatory
frameworks in all three regulated jurisdictions. A summary of the significant
financial objectives or issues impacting Progress Energy, its regulated
utilities and nonregulated operations is addressed more fully in the following
discussion.
PROGRESS ENERGY, INC.
Progress Energy has several key financial objectives, the first of which is to
achieve sustainable earnings growth in its three core energy businesses, which
include PEC Electric, PEF and Progress Ventures (excluding synthetic fuels). In
addition, the Company seeks to continue its track record of dividend growth, as
the Company has increased its dividend for 17 consecutive years, and 29 of the
last 30. The Company also seeks to restore balance sheet strength and
flexibility by reducing its debt to total capitalization ratio through selected
asset sales, free cash flow (defined as cash from operations less capital
expenditures and common dividends) and increased equity from retained earnings
and ongoing equity issuances.
42
In the short-term, the Company's ability to achieve its objectives will be
impacted by, among other things, its ability to recover storm costs incurred
during 2004, cash flow available to reduce debt after funding capital
expenditures and common dividends, obtaining a reasonable rate agreement in
Florida at the expiration of the current agreement in December 2005 and the
outcome of the ongoing Internal Revenue Service (IRS) audit of the Company's
synthetic fuel facilities. The Company's long-term challenges include escalating
nonfuel operating costs, the need for sufficient earnings growth to sustain the
track record of dividend growth, and the scheduled expiration of the Section 29
tax credit program for its synthetic fuels business at the end of 2007.
The Company's ability to meet its financial objectives is largely dependent on
the earnings and cash flows of its two regulated utilities. The regulated
utilities contributed $797 million of net income and produced 100% of
consolidated cash flow from operations in 2004. In addition, Fuels contributed
$180 million of net income, of which $91 million represented synthetic fuel net
income. Partially offsetting the net income contribution provided by the
regulated utilities and Fuels was a loss of $236 million recorded at Corporate
and Other, primarily related to interest expense on holding company debt.
While the Company's synthetic fuel operations currently provide significant
earnings that are scheduled to expire at the end of 2007, the associated cash
flow benefits from synthetic fuels are expected to come in the future when
deferred tax credits are ultimately utilized. Credits that have been generated
but not yet utilized are carried forward indefinitely as alternative minimum tax
credits and will provide positive cash flow when utilized. At December 31, 2004,
deferred credits were $745 million. See Note 23E and the "Risk Factors" section
for additional information on the Company's synthetic fuel operations and its
ability to utilize its current and future tax credits.
Progress Energy reduced its debt to total capitalization ratio to 57.6% at the
end of 2004 as compared to 58.8% at the end of 2003. The Company seeks to
continue to improve this ratio as it plans to reduce total debt with proceeds
from asset sales, free cash flow (defined as cash from operations less capital
expenditures and common dividends) and growth in equity from retained earnings
and ongoing equity issuances. The Company expects total capital expenditures to
be approximately $1.3 billion in both 2005 and 2006.
Progress Energy's ratings outlook was changed to "negative" from "stable" in
2004 by both Moody's and Standard & Poor's (S&P). Both ratings agencies cited
the uncertainty around the timing of storm cost recovery, potential delays in
the Company's de-leveraging plan, uncertainty about the upcoming rate case in
Florida and uncertainty about the IRS audit of the Company's synthetic fuel
partnerships in their ratings actions. The change in outlook has not materially
affected Progress Energy's access to liquidity or the cost of its short-term
borrowings. If Standard & Poor's lowers Progress Energy's senior unsecured
rating one ratings category to BB+ from its current rating, it would be a
noninvestment grade rating. The effect of a noninvestment grade rating would
primarily be to increase borrowing costs. The Company's liquidity would
essentially remain unchanged as the Company believes it could borrow under its
revolving credit facilities instead of issuing commercial paper for its
short-term borrowing needs. However, there would be additional funding
requirements of approximately $450 million due to ratings triggers embedded in
various contracts. See "Guarantees" Section under FUTURE LIQUIDITY AND CAPITAL
RESOURCES below and "Risk Factors" for more information regarding the potential
impact on the Company's financial condition and results of operations resulting
from a ratings downgrade.
REGULATED UTILITIES
The regulated utilities earnings and operating cash flows are heavily influenced
by weather, including related storm damage, the economy, demand for electricity
related to customer growth, actions of regulatory agencies and cost controls.
Both PEC Electric and PEF operate in retail service territories that are
forecasted to have income and population growth higher than the U.S. average. In
recent years, lower industrial sales mainly related to weakness in the textile
sector at PEC Electric have negatively impacted earnings growth. The Company
does not expect any significant improvement in industrial sales in the near
term. These combined factors under normal weather conditions are expected to
contribute approximately 2% annual retail kilowatt-hour (KWh) sales growth at
PEC Electric and approximately 3% annual retail kilowatt-hour (KWh) sales growth
at PEF through at least 2007. The utilities must continue to invest significant
capital in new generation, transmission and distribution facilities to support
this load growth. Subject to regulatory approval, these investments are expected
to increase the utilities' rate base, upon which additional return can be
realized that creates the basis for long-term financial growth in the utilities.
The Company will meet this load growth through the two previously planned
approximately 500 MW combined-cycle units at PEF's Hines Energy Complex in 2005
and 2007. The contribution from the utilities' regulated wholesale business is
expected to increase slightly in 2005 and be relatively flat over the following
few years.
43
While the two utilities expect retail sales growth in the future, they are
facing rising costs. The Company began a cost-management initiative in late 2004
to permanently reduce by $75-$100 million the projected growth in the Company's
annual nonfuel O&M costs by the end of 2007. See "Cost Management Initiative"
under RESULTS OF OPERATIONS for more information. The utilities expect capital
expenditures to be approximately $1.1 billion in both 2005 and 2006. The Company
will continue an approximate $900 million program of installing new
emission-control equipment at PEC's coal-fired power plants in North Carolina.
Operating cash flows are expected to be sufficient to fund capital spending in
2005 and in 2006.
The costs associated with the unprecedented series of major hurricanes that
impacted the Company's service territories significantly impacted the utility
operations in 2004. Restoration of the Company's systems from hurricane-related
damage cost almost $400 million. Although PEF has filed for recovery of
approximately $252 million of these storm costs, the timing of recovery is not
certain at this time. See OTHER MATTERS below for more information on storm
costs incurred during 2004.
PEC Electric and PEF continue to monitor progress toward a more competitive
environment. No retail electric restructuring legislation has been introduced in
the jurisdictions in which PEC Electric and PEF operate. As part of the Clean
Smokestacks bill in North Carolina and an agreement with the Public Service
Commission of South Carolina (SCPSC), PEC Electric is operating under a rate
freeze in North Carolina through 2007 and an agreement not to seek a base retail
electric rate increase in South Carolina through 2005. PEF is operating under a
retail rate agreement in Florida through 2005. PEF has initiated a rate
proceeding in 2005 regarding its future base rates. See Note 8 for further
discussion of the utilities' retail rates.
NONREGULATED BUSINESSES
The Company's primary nonregulated businesses are CCO, Fuels and Progress Rail.
Cash flows and earnings of the nonregulated businesses are impacted largely by
the ability to obtain additional term contracts or sell energy on the spot
market at favorable terms, the volume of synthetic fuel produced and tax credits
utilized, and volumes and prices of both coal and natural gas sales.
Progress Energy expects an excess of supply in the wholesale electric energy
market for the next several years. During 2004, CCO entered into additional
wholesale power contracts with cooperatives in Georgia and will serve
approximately one-third of the Georgia cooperative market starting in 2005. CCO
completed the build out of its nonregulated generation assets in 2003 and
currently has total capacity of 3,100 MW. The Company has no current plans to
expand its portfolio of nonregulated generating plants. CCO short-term
challenges include absorbing the fixed costs associated with these plants and
the general weakness in wholesale power markets. Three above-market tolling
agreements for approximately 1,200 MW of capacity expired at the end of 2004.
CCO has replaced the expired agreements with the increased cooperative load in
Georgia. The increased cooperative load in Georgia will significantly increase
CCO's revenue and cost of sales from 2004 to 2005 with lower margins expected.
Currently CCO has contracts for its planned production capacity, which includes
callable resources from the cooperatives, of approximately 77% for 2005, 81% for
2006 and 75% for 2007. CCO will continue its optimization strategy for the
nonregulated generation portfolio.
Fuels will continue to develop its natural gas production asset base both as a
long-term economic hedge for the Company's nonregulated generation fuel needs
and to continue its presence in natural gas markets that will allow it to
provide attractive returns for the Company's shareholders.
The Company has begun exploring strategic alternatives regarding the Fuels' coal
mining business, which could include divesting assets. As of December 31, 2004,
the carrying value of long-lived assets of the coal mining business was $66
million.
The Company, through its subsidiaries, is a majority owner in five entities and
a minority owner in one entity that owns facilities that produce synthetic fuel
as defined under the Internal Revenue Code. The production and sale of the
synthetic fuel from these facilities qualifies for tax credits under Section 29
if certain requirements are satisfied. These facilities have private letter
rulings (PLRs) from the IRS with respect to their synthetic fuel operations.
However, these PLRs do not address placed-in-service date requirements. The
Company has resolved certain synthetic fuel tax credit issues with the IRS and
44
is continuing to work with the IRS to resolve any remaining issues. The Company
cannot predict the final resolution of any outstanding matters. The Company has
no current plans to alter its synthetic fuel production schedule as a result of
these matters. The Company plans to produce approximately 8 to 12 million tons
of synthetic fuel in 2005. Through December 31, 2004, the Company had generated
approximately $1.5 billion of synthetic fuel tax credits to date (including FPC
prior to the acquisition by the Company). See additional discussion of synthetic
fuel tax credits in Note 23E and in the "Risk Factors" section.
In February 2005, Progress Energy signed a definitive agreement to sell its
Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million. Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.
Progress Energy and its consolidated subsidiaries are subject to various risks.
For a complete discussion of these risks, see the Risk Factors section.
RESULTS OF OPERATIONS
FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002
In this section, earnings and the factors affecting earnings are discussed. The
discussion begins with a summarized overview of the Company's consolidated
earnings, which is followed by a more detailed discussion and analysis by
business segment.
Overview
For the year ended December 31, 2004, Progress Energy's net income was $759
million or $3.13 per share compared to $782 million or $3.30 per share for the
same period in 2003. The decrease in net income as compared to prior year was
due primarily to:
o Reduction in synthetic fuel earnings due to lower synthetic fuel sales due
to the impact of hurricanes during the year.
o Lower off-system wholesale sales, primarily at PEC Electric.
o Higher O&M expenses at PEC Electric.
o Recording of litigation settlement reached in the civil suit by Strategic
Resource Solutions (SRS).
o Decreased nonregulated generation earnings due to receipt of a contract
termination payment on a tolling agreement in 2003, loss recognized on
early extinguishment of debt in 2004 and higher fixed costs and interest
charges in 2004.
o Reduction in revenues due to customer outages in Florida associated with
the hurricanes.
o Increased interest charges due to the reversal of interest expense for
resolved tax matters in 2003.
Partially offsetting these items were:
o Favorable weather in the Carolinas.
o Reduction in revenue sharing provisions in Florida.
o Favorable customer growth in both the Carolinas and Florida.
o Increased margins as a result of the allowed return on the Hines 2 Plant in
Florida.
o Increased earnings for natural gas operations, which include the gain
recorded on the disposition of certain Winchester Production Company
assets.
o Increased earnings for Rail operations.
o Unrealized gains recorded on contingent value obligations (CVOs).
o Reduction in impairments recorded for an investment portfolio and
long-lived assets.
o Reduction in losses recorded for discontinued operations.
o Reduction in losses recorded for changes in accounting principles.
For the year ended December 31, 2003, Progress Energy's net income was $782
million, or $3.30 per share, compared to $528 million, or $2.43 per share, for
the same period in 2002. Income from continuing operations before the cumulative
effect of changes in accounting principles and discontinued operations was $811
million in 2003, a 47% increase from $552 million in 2002. Net income for 2003
increased compared to 2002 primarily due to the inclusion in 2002 of an
impairment of $265 million after-tax related to assets in the telecommunications
and rail businesses. The Company recorded impairments of $23 million after-tax
in 2003 on an investment portfolio and on long-lived assets. The increase in net
income in 2003 of $12 million, excluding the impairments, is primarily due to:
45
o Increase in retail customer growth at the utilities.
o Growth in natural gas production and sales.
o Higher synthetic fuel sales.
o Absence of severe storm costs incurred in 2002 in the Carolinas.
o Lower loss recorded in 2003 related to the sale of North Carolina Natural
Gas Company (NCNG), with the majority of the loss on the sale being
recorded in 2002.
o Lower interest charges in 2003.
Partially offsetting these items were the:
o Net impact of the 2002 Florida Rate settlement.
o Impact of the change in the fair value of the CVOs.
o Milder weather in 2003 as compared to 2002.
o Increased benefit-related costs.
o Higher depreciation expense at both utilities and the Fuels and CCO
segments.
o The impact of changes in accounting principles in 2003.
Basic earnings per share decreased in 2004 and increased in 2003 due in part to
the factors outlined above. Dilution related to issuances under the Company's
Investor Plus and employee benefit programs in 2004 also reduced basic earnings
per share by $0.06 in 2004. Dilution related to a November 2002 equity issuance
of 14.7 million shares and issuances under the Company's Investor Plus and
employee benefit programs in 2002 and 2003 also reduced basic earnings per share
by $0.33 in 2003.
Beginning in the fourth quarter of 2003, the Company ceased recording portions
of the Fuels segment's operations, primarily synthetic fuel facilities, one
month in arrears. As a result, earnings for the year ended December 31, 2003,
included 13 months of operations, resulting in a net income increase of $2
million for the year.
The Company's segments contributed the following profit or loss from continuing
operations:
- ---------------------------------------------------------------------------------------------------------------
(in millions)
- ---------------------------------------------------------------------------------------------------------------
2004 Change 2003 Change 2002
- ---------------------------------------------------------------------------------------------------------------
PEC Electric $ 464 $ (51) $ 515 $ 2 $ 513
PEF 333 38 295 (28) 323
Fuels 180 (55) 235 59 176
CCO (4) (24) 20 (7) 27
Rail services 16 17 (1) 41 (42)
- ---------------------------------------------------------------------------------------------------------------
Total segment profit (loss) 989 (75) 1,064 67 997
Corporate and other (236) 17 (253) 192 (445)
- ---------------------------------------------------------------------------------------------------------------
Total income from continuing operations 753 (58) 811 259 552
Discontinued operations, net of tax 6 14 (8) 16 (24)
Cumulative effect of changes in accounting
principles - 21 (21) (21) -
- ---------------------------------------------------------------------------------------------------------------
Net income $ 759 $ (23) $ 782 $ 254 $ 528
- ---------------------------------------------------------------------------------------------------------------
In March 2003, the SEC completed an audit of Progress Energy Service Company,
LLC (Service Company), and recommended that the Company change its cost
allocation methodology for allocating Service Company costs. As part of the
audit process, the Company was required to change the cost allocation
methodology for 2003 and record retroactive reallocations between its affiliates
in the first quarter of 2003 for allocations originally made in 2001 and 2002.
This change in allocation methodology and the related retroactive adjustments
have no impact on consolidated expense or earnings. The new allocation
methodology, as compared to the previous allocation methodology, generally
decreases expenses in the regulated utilities and increases expenses in the
nonregulated businesses. The regulated utilities' reallocations are within O&M
expense, while the diversified businesses' reallocations are generally within
diversified business expenses. The impact on the individual lines of business is
included in the following discussions.
46
Cost Management Initiative
On February 28, 2005, as part of a previously announced cost management
initiative, the executive officers of the Company approved a workforce
restructuring. The restructuring will result in a reduction of approximately 450
positions and is expected to be completed in September of 2005. The cost
management initiative is designed to permanently reduce by $75-100 million the
projected growth in the Company's annual operation and maintenance expenses by
the end of 2007. In addition to the workforce restructuring, the cost management
initiative includes a voluntary enhanced retirement program.
In connection with the cost management initiative, the Company expects to incur
one-time pre-tax charges of approximately $130 million. Approximately $30
million of that amount relates to payments for severance benefits, and will be
recognized in the first quarter of 2005 and paid over time. The remaining
approximately $100 million will be recognized in the second quarter of 2005 and
relates primarily to postretirement benefits that will be paid over time to
those eligible employees who elect to participate in the voluntary enhanced
retirement program. Approximately 3,500 of the Company's 15,700 employees are
eligible to participate in the voluntary enhanced retirement program. The total
cost management initiative charges could change significantly depending upon how
many eligible employees elect early retirement under the voluntary enhanced
retirement program and the salary, service years and age of such employees (See
Note 24).
Energy Delivery Capitalization Practice
The Company has reviewed its capitalization policies for its Energy Delivery
business units in PEC and PEF. That review indicated that in the areas of outage
and emergency work not associated with major storms and allocation of indirect
costs, both PEC and PEF should revise the way that they estimate the amount of
capital costs associated with such work. The Company has implemented such
changes effective January 1, 2005, which include more detailed classification of
outage and emergency work and result in more precise estimation and a process of
retesting accounting estimates on an annual basis. As a result of the changes in
accounting estimates for the outage and emergency work and indirect costs, a
lesser proportion of PEC's and PEF's costs will be capitalized on a prospective
basis. The Company estimates that the combined impact for both utilities in 2005
will be that approximately $55 million of costs that would have been capitalized
under the previous policies will be expensed. Pursuant to SFAS No. 71, PEC and
PEF have informed the state regulators having jurisdiction over them of this
change and that the new estimation process will be implemented effective January
1, 2005. The Company has also requested a method change from the IRS.
Progress Energy Carolinas Electric
PEC Electric contributed segment profits of $464 million, $515 million and $513
million in 2004, 2003 and 2002, respectively. The decrease in profits for 2004
as compared to 2003 is primarily due to higher O&M charges and lower wholesale
revenues partially offset by the favorable impact of weather, increased revenues
from customer growth and a reduction in investment losses and impairment charges
compared to the prior year. The slight increase in profits in 2003, when
compared to 2002, was primarily due to customer growth, strong wholesale sales
during the first quarter of 2003, lower Service Company allocations and lower
interest costs, which were offset by unfavorable weather in 2003, higher
depreciation expense and increased benefit-related costs.
REVENUES
PEC Electric's electric revenues and the percentage change by year and by
customer class are as follows:
- -------------------------------------------------------------------------------------------------
(in millions)
- -------------------------------------------------------------------------------------------------
Customer Class 2004 % Change 2003 % Change 2002
- -------------------------------------------------------------------------------------------------
Residential $ 1,324 5.2 $ 1,259 1.5 $ 1,241
Commercial 888 4.5 850 2.2 832
Industrial 659 3.6 636 (1.4) 645
Governmental 82 3.8 79 1.3 78
- -------------------------------------------------------------------------------------------------
Total retail revenues 2,953 4.6 2,824 1.0 2,796
Wholesale 575 (16.3) 687 5.5 651
Unbilled 10 - (6) - 15
Miscellaneous 90 7.1 84 9.1 77
- -------------------------------------------------------------------------------------------------
Total electric revenues $ 3,628 1.1 $ 3,589 1.4 $ 3,539
- -------------------------------------------------------------------------------------------------
47
PEC Electric's electric energy sales and the percentage change by year and by
customer class are as follows:
- -------------------------------------------------------------------------------------------------
(in thousands of MWh)
- -------------------------------------------------------------------------------------------------
Customer Class 2004 % Change 2003 % Change 2002
- -------------------------------------------------------------------------------------------------
Residential 16,003 4.7 15,283 0.3 15,239
Commercial 13,019 3.7 12,557 0.7 12,468
Industrial 13,036 2.3 12,749 (2.6) 13,089
Governmental 1,431 1.6 1,408 (2.0) 1,437
- -------------------------------------------------------------------------------------------------
Total retail energy sales 43,489 3.6 41,997 (0.6) 42,233
Wholesale 13,222 (14.8) 15,518 3.3 15,024
Unbilled 91 - (44) - 270
- -------------------------------------------------------------------------------------------------
Total MWh sales 56,802 1.2 57,471 (0.1) 57,527
- -------------------------------------------------------------------------------------------------
PEC Electric's revenues, excluding recoverable fuel revenues of $933 million and
$901 million for 2004 and 2003, respectively, increased $7 million. The increase
in revenues was due primarily to increased retail revenues of $35 million as a
result of favorable weather, with cooling degree days 16% above prior year.
Retail customer growth contributed an additional $55 million in revenues in
2004. PEC Electric's retail customer base increased as approximately 26,000 new
customers were added in 2004. The increase in retail revenues was offset
partially by lower wholesale revenues. Wholesale revenues decreased $86 million
when compared to $393 million in 2003. The decrease in PEC Electric's wholesale
revenues in 2004 from 2003 is primarily the result of reduced excess generation
sales. Revenues for 2003 included strong sales to the northeastern United States
as a result of favorable market conditions. In addition, lower contracted
capacity compared to 2003 further reduced wholesale revenues. The remaining
reduction in wholesale revenues is attributable to an inelastic power market.
While the cost of fuel continues to rise, the power market prices have not
responded as quickly to the fuel increases. The differential between fuel cost
and market price limited opportunities to enter the market. PEC monitors its
wholesale contract portfolio on a regular basis. During 2003 and 2004, several
contracts expired or were renegotiated at lower prices. Due to the slightly
depressed wholesale market and increased competition, this trend could continue
as contracts are renewed in the upcoming years. The expiration and renegotiation
of wholesale contracts is a normal business activity. PEC actively manages its
portfolio by seeking to sign new contracts to replace expiring arrangements.
PEC Electric's revenues, excluding recoverable fuel revenues of $901 million and
$851 million in 2003 and 2002, respectively, were unchanged from 2002 to 2003.
Milder weather in 2003, when compared to 2002, accounted for a $61 million
retail revenue reduction. While heating degree days in 2003 were 4.8% above
prior year, cooling degree days were 25.2% below prior year. However, the more
severe weather in the northeast region of the United States during the first
quarter of 2003 drove a $19 million increase in wholesale revenues.
Additionally, retail customer growth in 2003 generated an additional $42 million
of revenues in 2003. PEC Electric's retail customer base increased as
approximately 23,000 new customers were added in 2003.
Downturns in the economy during 2002 and 2003 impacted energy usage within the
industrial customer class. Total industrial revenues, excluding fuel revenues,
declined during 2003 when compared to 2002 by $13 million, as sales to
industrial customers decreased due to a general industrial slowdown. Decreases
in the textile industry and the chemical industry were among the largest. This
declining trend leveled out in 2004 as industrial sales increased in the primary
and fabricated metal, chemicals, lumber and food industries. Industrial sales
growth is expected to be flat or very low as expired textile quotas are expected
to lower textile sales and balance gains in other industries.
EXPENSES
Fuel and Purchased Power
Fuel and purchased power costs represent the costs of generation, which include
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses, and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that are subject to recovery is
deferred for future collection or refund to customers.
Fuel and purchased power expenses were $1.137 billion for 2004, which represents
a $16 million increase compared to the same period in the prior year. Fuel used
in electric generation increased $11 million to $836 million compared to the
prior year. This increase is due to an increase in fuel used in generation of
$78 million due to higher fuel costs and a change in generation mix. Higher fuel
costs are being driven primarily by an increase in coal prices. Outages at
48
several nuclear facilities during the year resulted in increased combustion
turbine generation, which has a higher average fuel cost. See Part I, Item I,
"Fuel and Purchased Power" of Electric - PEC for a summary of average fuel
costs. The increase in fuel used in generation is offset by a reduction in
deferred fuel expense as a result of the under-recovery of current period fuel
costs. Purchased power expenses increased $5 million to $301 million compared to
prior year. The increase in purchased power is due primarily to an increase in
price.
Fuel and purchased power expenses were $1.121 billion for 2003, which represents
a $22 million increase compared to the same period in the prior year. Fuel used
in electric generation increased $73 million in 2003, compared to prior year,
primarily due to higher prices incurred for coal, oil and natural gas used
during generation. Costs for fuel per Btu increased for all three commodities
during the year. See Part I, Item I, "Fuel and Purchased Power" of Electric -
PEC for a summary of average fuel costs. Purchased power expense decreased $51
million in 2003, compared to $347 million in 2002, mainly due to a decrease in
the volume purchased as milder weather reduced system requirements and due to
the renegotiation at more favorable terms of two contracts that expired during
the year.
Operations and Maintenance (O&M)
O&M expenses were $871 million for 2004, which represents an $89 million
increase compared to 2003. This increase is driven primarily by higher outage
costs and storm costs in 2004 than in the prior year. Outages increased O&M
costs by $29 million primarily due to an increase in the number and scope of
nuclear plant outages in 2004. In addition, costs associated with restoration
efforts after severe storms increased O&M expense $18 million. Storm costs for
2004 included costs related to an ice storm and Hurricanes Charley and Ivan in
the North Carolina service territory. PEC Electric also incurred storm costs in
2003; however, the Company requested and the NCUC approved deferral of these
costs. The Company did not seek to defer costs associated with the ice storm,
which hit the North Carolina service territory, and Hurricanes Charley and Ivan.
O&M expenses also increased $9 million due to higher salary- and benefit-related
expenditures. In addition, O&M charges in the prior year were favorably impacted
by $16 million related to the retroactive reallocation of Service Company costs.
O&M expenses were $782 million in 2003, which represents a $20 million decrease
compared to 2002. O&M expense in 2002 included severe storm costs of $27
million. Those costs, along with lower 2003 Service Company allocations of $16
million, due to the change in allocation methodology as required by the SEC in
early 2003, are the primary reasons for decreased O&M expenses. This decrease
was partially offset by higher benefit-related costs of $21 million. PEC
Electric incurred O&M costs of $25 million related to three severe storms in
2003. The NCUC allowed deferral of $24 million of these storm costs. These costs
are being amortized over a five-year period, beginning in the months the
expenses were incurred. PEC Electric amortized $3 million of these costs in
2003, which is included in depreciation and amortization expense on the
Consolidated Income Statement.
Depreciation and Amortization
Depreciation and amortization expense was $570 million for 2004, which
represents an $8 million increase compared to 2003. This increase is
attributable primarily to the impact of the NC Clean Air legislation. PEC
Electric recorded the maximum amortization allowed under the legislation in
2004. NC Clean Air amortization increased $100 million to $174 million in 2004
compared to $74 million in 2003. Depreciation expense also increased $9 million
for assets placed in service. These increases were partially offset by a
reduction in depreciation expense related to depreciation studies filed during
the year. During 2004, PEC met the requirements of both the NCUC and the SCPSC
for the implementation of depreciation studies that allowed the utility to
reduce the rates used to calculate depreciation expense. The annual reduction in
depreciation expense is approximately $82 million compared to 2003. The
reduction is due primarily to extended lives at each of PEC's nuclear units. The
new rates became effective January 2004.
Depreciation and amortization increased $38 million in 2003, compared to $524
million in 2002. Depreciation and amortization increased $74 million related to
the 2003 impact of the NC Clean Air legislation and decreased $53 million
related to the 2002 impact of the accelerated nuclear amortization program. Both
programs are approved by the state regulatory agencies and are discussed further
at Notes 8B and 22. In addition, depreciation increased $19 million due to
additional assets placed into service.
49
Taxes Other than on Income
Taxes other than on income were $173 million for 2004, which represents an $11
million increase compared to the prior year. This increase is due primarily to
an increase in gross receipts taxes of $8 million related to an increase in
revenues and a 2004 adjustment related to the prior year. The remaining variance
in other taxes is due to an increase in property taxes of $7 million due to
higher property appraisals partially offset by a reduction in payroll taxes of
$4 million.
Taxes other than on income were $162 million in 2003, which represents a $4
million increase compared to prior year. This increase is due to an increase in
property taxes and payroll taxes of $2 million each.
Interest Expense
Net interest expense was $192 million, $197 million and $212 million in 2004,
2003 and 2002, respectively. Declines in interest expense in 2003 resulted from
reduced short-term debt and refinancing certain long-term debt with lower
interest rate debt.
Income Tax Expense
Income tax expense was $237 million, $238 million and $237 million in 2004, 2003
and 2002, respectively. In 2004, 2003 and 2002, $22 million, $24 million and $35
million, respectively, of the tax benefit that was previously held at the
Company's holding company was allocated to PEC Electric. As required by an SEC
order issued in 2002, certain holding company tax benefits are allocated to
profitable subsidiaries. Other fluctuations in income taxes are primarily due to
changes in pre-tax income.
Progress Energy Florida
PEF contributed segment profits of $333 million, $295 million and $323 million
in 2004, 2003 and 2002, respectively. Profits for 2004 increased due to
favorable customer growth, a reduction in the provision for revenue sharing,
favorable wholesale revenues, the additional return on investment on the Hines 2
plant and reduced O&M expenses. These items were partially offset by unfavorable
weather, a reduction in revenues related to the hurricanes, increased interest
expense and increased depreciation expense from assets placed in service. The
decrease in profits in 2003, when compared to 2002, was primarily due to the
impact of the 2002 rate case stipulation, higher benefit-related costs primarily
related to higher pension expense, higher depreciation and the unfavorable
impact of weather. These amounts were partially offset by continued customer
growth and lower interest charges.
In 2002, PEF's profits were affected by the outcome of the rate case
stipulation, which included a one-time retroactive revenue refund, a decrease in
retail rates of 9.25% (effective May 1, 2002), provisions for revenue sharing
with the retail customer base, lower depreciation and amortization and increased
service revenue rates (See Note 8C).
REVENUES
PEF's electric revenues and the percentage change by year and by customer class,
as well as the impact of the rate case settlement on revenue, are as follows:
- -----------------------------------------------------------------------------------------------
(in millions)
- -----------------------------------------------------------------------------------------------
Customer Class 2004 % Change 2003 % Change 2002
- -----------------------------------------------------------------------------------------------
Residential $ 1,806 6.8 $ 1,691 2.8 $ 1,645
Commercial 853 15.3 740 1.2 731
Industrial 254 16.0 219 3.8 211
Governmental 211 16.6 181 4.6 173
Revenue sharing refund (11) - (35) - (5)
Retroactive retail rate refund - - - - (35)
- ------------------------------------------------ ----------------- -------------
Total retail revenues 3,113 11.3 2,796 2.8 2,720
Wholesale 268 18.1 227 (1.3) 230
Unbilled 7 - (2) - (3)
Miscellaneous 137 4.6 131 13.9 115
- ------------------------------------------------ ----------------- -------------
Total electric revenues $ 3,525 11.8 $ 3,152 2.9 $ 3,062
- -----------------------------------------------------------------------------------------------
50
PEF's electric energy sales and the percentage change by year and by customer
class are as follows:
- ---------------------------------------------------------------------------------------------
(in thousands of MWh)
- ---------------------------------------------------------------------------------------------
Customer Class 2004 % Change 2003 % Change 2002
- ---------------------------------------------------------------------------------------------
Residential 19,347 (0.4) 19,429 3.6 18,754
Commercial 11,734 1.6 11,553 1.2 11,420
Industrial 4,069 1.7 4,000 4.3 3,835
Governmental 3,044 2.4 2,974 4.4 2,850
- ----------------------------------------------- ---------------- -------------
Total retail energy sales 38,194 0.6 37,956 3.0 36,859
Wholesale 5,101 18.0 4,323 3.4 4,180
Unbilled 358 - 233 - 5
- ----------------------------------------------- ---------------- -------------
Total MWh sales 43,653 2.6 42,512 3.6 41,044
- ---------------------------------------------------------------------------------------------
PEF's revenues, excluding recoverable fuel and other pass-through revenues of
$2.007 billion and $1.692 billion for 2004 and 2003, respectively, increased $58
million. This increase was due primarily to favorable customer growth, which
increased revenues $34 million. PEF has 37,000 additional retail customers
compared to prior year. Revenues were also favorably impacted by a reduction in
the provision for revenue sharing of $24 million. Results for 2003 included an
additional refund of $18 million related to the 2002 revenue sharing provision
as ordered by the FPSC in July 2003. In addition, improved wholesale sales
increased revenues by $11 million. Included in fuel revenues is the recovery of
depreciation and capital costs associated with the Hines Unit 2, which was
placed into service in December 2003 and contributed $36 million in additional
revenues in 2004. The recovery of the Hines Unit 2 costs through the fuel clause
is in accordance with the 2002 rate stipulation (See Note 8C). These increases
were partially offset by the reduction in revenues related to customer outages
for Hurricanes Charley, Frances and Jeanne of approximately $12 million and the
impact of milder weather in the current year of $10 million.
PEF's revenues, excluding recoverable fuel and other pass-through revenues of
$1.692 billion and $1.602 billion in 2003 and 2002, respectively, were unchanged
from 2002 to 2003. Revenues were favorably impacted by $49 million in 2003,
primarily as a result of customer growth (approximately 36,000 additional
customers). In addition, other operating revenues were favorable by $16 million
due primarily to higher wheeling and transmission revenues and higher service
charge revenues (resulting from increased rates allowed under the 2002 rate
settlement). These increases were offset by the negative impact of the rate
settlement, which decreased revenues, lower wholesale sales and the impact of
unfavorable weather. The provision for revenue sharing increased $12 million in
2003 compared to the $5 million provision recorded in 2002. Revenues in 2003
were also impacted by the final resolution of the 2002 revenue sharing
provisions, as the FPSC issued an order in July 2003 that required PEF to refund
an additional $18 million to customers related to 2002. The 9.25% rate reduction
from the settlement accounted for an additional $46 million decline in revenues.
The 2003 impact of the rate settlement was partially offset by the absence of
the prior year interim rate refund of $35 million. Lower wholesale revenues
(excluding fuel revenues) of $17 million and the $8 million impact of milder
weather also reduced base revenues during 2003.
EXPENSES
Fuel and Purchased Power
Fuel and purchased power costs represent the costs of generation, which include
fuel purchases for generation, as well as energy purchased in the market to meet
customer load. Fuel and purchased power expenses are recovered primarily through
cost recovery clauses, and, as such, changes in these expenses do not have a
material impact on earnings. The difference between fuel and purchased power
costs incurred and associated fuel revenues that are subject to recovery is
deferred for future collection or refund to customers.
Fuel and purchased power expenses were $1.742 billion in 2004, which represents
a $306 million increase compared to 2003. This increase is due to increases in
fuel used in electric generation and purchased power expenses of $305 million
and $1 million, respectively. Higher system requirements and increased fuel
costs in the current year account for $87 million of the increase in fuel used
in electric generation. The remaining increase is due to the recovery of fuel
expenses that were deferred in the prior year, partially offset by the deferral
of current year under-recovered fuel expenses. In November 2003, the FPSC
approved PEF's request for a cost adjustment in its annual fuel filing due to
the rising costs of fuel. The new rates became effective January 2004.
51
Fuel used in generation and purchased power expenses were $1.436 billion in
2003, which represents an $87 million increase compared to the prior year.
Higher costs to generate electricity and higher purchased power costs as a
result of an increase in volume due to system requirements and higher natural
gas prices resulted in a $229 million increase partially offset by the deferral
of 2003 under-recovered fuel and purchased power expense of $142 million.
Operations and Maintenance (O&M)
O&M expenses were $630 million in 2004, which represents a $10 million decrease
when compared to the prior year. This decrease is primarily related to favorable
benefit-related costs of $16 million, primarily due to lower pension costs which
resulted from improved pension asset performance.
O&M expenses were $640 million in 2003, which represents a $49 million increase
when compared to the prior year. The increase is largely related to increases in
certain benefit-related expenses of $36 million, which consisted primarily of
higher pension expense of $27 million and higher operational costs related to
the CR3 nuclear outage and plant maintenance.
Depreciation and Amortization
Depreciation and amortization expense was $281 million for 2004, which
represents a decrease of $26 million when compared to the prior year, primarily
due to the amortization of the Tiger Bay regulatory asset in the prior year. The
Tiger Bay regulatory asset, for contract termination costs, was recovered
pursuant to an agreement between PEF and the FPSC that was approved in 1997. The
amortization of the regulatory asset was calculated using revenues collected
under the fuel adjustment clause; as such, fluctuations in this expense did not
have an impact on earnings. During 2003, Tiger Bay amortization was $47 million.
The Tiger Bay asset was fully amortized in September 2003. The decrease in Tiger
Bay amortization was partially offset by additional depreciation for assets
placed in service, including depreciation for Hines Unit 2, of approximately $9
million. This depreciation expense is being recovered through the fuel cost
recovery clause as allowed by the FPSC. See discussion of the return on Hines 2
in the revenues analysis above.
Depreciation and amortization was $307 million in 2003, which represents an
increase of $12 million when compared to 2002. Depreciation increased primarily
as a result of additional assets being placed into service that were partially
offset by lower amortization of the Tiger Bay regulatory asset of $2 million,
which was fully amortized in September 2003.
Taxes Other than on Income
Taxes other than on income were $254 million in 2004, which represents an
increase of $13 million compared to the prior year. This increase is due to
increases in gross receipts and franchise taxes of $8 million and $7 million,
respectively, related to an increase in revenues and an increase in property
taxes of $5 million due to increases in property placed in service and tax
rates. These increases were partially offset by a reduction in payroll taxes of
$7 million.
Taxes other than on income were $241 million in 2003, which represents an
increase of $13 million compared to prior year. This increase was due to
increases in payroll taxes of $10 million and increases in gross receipts and
franchise taxes of $4 million combined.
Interest Expense
Interest charges, net were $114 million in 2004, which represents an increase of
$23 million compared to the prior year. Interest charges, net were $91 million
in 2003, which represents a $15 million decrease compared to the prior year. The
fluctuations were primarily due to interest costs in 2003 being favorably
impacted by the reversal of interest expense due to the resolution of certain
tax matters.
Income Tax Expense
Income tax expense was $174 million, $147 million and $163 million in 2004, 2003
and 2002, respectively. In 2004, 2003 and 2002, $14 million, $13 million and $20
million, respectively, of the tax benefit that was previously held at the
Company's holding company was allocated to PEF. As required by an SEC order
issued in 2002, certain holding company tax benefits are allocated to profitable
subsidiaries. Other fluctuations in income taxes are primarily due to changes in
pre-tax income.
52
Diversified Businesses
The Company's diversified businesses consist of the Fuels segment, the CCO
segment and the Rail Services segment.
Fuels
The Fuels' segment operations include synthetic fuels production, natural gas
production, coal extraction and terminal operations. Beginning in the fourth
quarter of 2003, the Company ceased recording portions of Fuels' segment
operations, primarily synthetic fuel facilities, one month in arrears. As a
result, earnings for the year ended December 31, 2003, included 13 months of
operations, resulting in a net income increase of $2 million for the year.
The following summarizes Fuels' segment profits:
- ---------------------------------------------------------------------
(in millions) 2004 2003 2002
- ---------------------------------------------------------------------
Synthetic fuel operations $ 91 $ 205 $ 156
Natural gas operations 85 34 10
Coal fuel and other operations 4 (4) 10
- ---------------------------------------------------------------------
Segment profits $ 180 $ 235 $ 176
- ---------------------------------------------------------------------
SYNTHETIC FUEL OPERATIONS
The production and sale of synthetic fuel generate operating losses, but qualify
for tax credits under Section 29 of the Code, which more than offset the effect
of such losses (See Note 23E).
The operations resulted in the following losses (prior to tax credits):
- -------------------------------------------------------------------------
(in millions) 2004 2003 2002
- -------------------------------------------------------------------------
Tons sold 8.3 12.4 11.2
After-tax losses (excluding tax credits) $ (124) $ (141) $ (135)
Tax credits 215 346 291
- -------------------------------------------------------------------------
Net profit $ 91 $ 205 $ 156
- -------------------------------------------------------------------------
The Company's synthetic fuel production levels and the amount of tax credits it
can claim each year are a function of the Company's projected consolidated
regular federal income tax liability. Synthetic fuel operations' net profits
decreased in 2004 as compared to 2003 due primarily to a decrease in synthetic
fuel production and an increase in operating expenses in 2004. The Company's
total synthetic fuel production of approximately eight million tons in 2004 is
down compared to 2003 production levels of approximately 12 million tons as a
result of hurricane costs, which reduced the Company's projected 2004 regular
tax liability and its corresponding ability to record tax credits from its
synthetic fuel production. In addition, earnings in 2003 include a $13 million
favorable tax credit true-up related to 2002.
As of September 30, 2004, the Company anticipated an ability to record
approximately five million tons of synthetic fuels production based on the
Company's projected regular tax liability for 2004. This estimate was based upon
the Company's projected casualty loss as a result of the storms. Therefore, the
Company recorded a charge of $79 million in the third quarter for tax credits
associated with approximately 2.7 million tons sold during the year that the
Company anticipated it would not be able to use. On November 2, 2004, PEF filed
a petition with the FPSC to recover $252 million of storm costs plus interest
from customers over a two-year period. Based on a reasonable expectation at
December 31, 2004, that the FPSC will grant the requested recovery of the storm
costs, the Company's loss from the casualty is less than originally anticipated.
Accordingly, as of December 31, 2004, the Company's anticipated 2004 tax
liability supported credits on approximately eight million tons. Therefore, the
Company recorded tax credits of $90 million for the quarter ended December 31,
2004, for tax credits associated with approximately three million tons sold
during the year that the Company now anticipates can be used. As of December 31,
2004, the Company anticipates that approximately $7 million of tax credits
associated with approximately 0.2 million tons sold during the year could not be
used (See Note 23E). The Company ceased operations at its Earthco facilities for
the last three months of 2004 due to the decrease in the Company's projected
2004 tax liability, and these facilities were restarted in January 2005.
53
The Company believes its right to recover storm costs is well established;
however, the Company cannot predict the timing or outcome of this matter. If the
FPSC should deny PEF's petition for the recovery of storm costs in 2005, there
could be a material impact on the amount of 2005 synthetic fuel production and
results of operations.
Synthetic fuels' net profits for 2003 increased as compared to 2002 due to
higher sales, improved margins and a higher tax credit per ton. The 2003 tax
credits also include a $13 million favorable true-up from 2002. Additionally,
synthetic fuels' results in 2003 include 13 months of operations for some
facilities. Prior to the fourth quarter of 2003, results of these synthetic
fuels' operations had been recognized one month in arrears. The net impact of
this action increased net income by $2 million for the year.
NATURAL GAS OPERATIONS
Natural gas operations generated profits of $85 million, $34 million and $10
million for the years ended December 31, 2004, 2003 and 2002, respectively.
Natural gas profits increased $51 million in 2004 compared to 2003. This
increase is attributable primarily to the gain recognized on the sale of gas
assets during the year. In December 2004, the Company sold certain gas-producing
properties and related assets owned by Winchester Production Company, Ltd.
(North Texas gas operations). Because the sale significantly altered the ongoing
relationship between capitalized costs and remaining proved reserves, under the
full-cost method of accounting the pre-tax gain of $56 million ($31 million net
of taxes) was recognized in earnings rather than as a reduction of the basis of
the Company's remaining oil and gas properties. In addition, an increase in
production, coupled with higher gas prices in 2004, contributed to the increased
earnings in 2004 as compared to 2003. Production levels increased resulting from
the acquisition of North Texas Gas in late February 2003 and increased drilling
in 2004. Volume and prices have increased 21% and 16%, respectively, for 2004
compared to 2003.
Natural gas profits increased to $34 million in 2003 compared to $10 million in
2002. The increase in production and price resulting from the acquisitions of
Westchester in 2002 (renamed Winchester Energy in 2004) and North Texas Gas in
the first quarter of 2003 drove increased revenue and earnings in 2003 compared
to 2002. In October 2003, the Company completed the sale of certain
gas-producing properties owned by Mesa Hydrocarbons, LLC (Mesa). See Notes 5B
and 4D to the Progress Energy Consolidated Financial Statements for discussions
of the North Texas Gas acquisitions and the Mesa disposition.
The following table summarizes the production and revenues of the natural gas
operations by location:
- ------------------------------------------------------------------------------
2004 2003 2002
- ------------------------------------------------------------------------------
Production in Bcf equivalent
East Texas/LA gas operations 20 13 6
North Texas gas operations 10 7 -
Mesa - 5 7
- ------------------------------------------------------------------------------
Total production 30 25 13
- ------------------------------------------------------------------------------
Revenues in millions
East Texas/LA gas operations $110 $ 65 $24
North Texas gas operations 52 38 -
Mesa - 13 15
- ------------------------------------------------------------------------------
Total revenues $162 $ 116 $39
- ------------------------------------------------------------------------------
Gross margin
In millions of $ $ 126 $ 91 $29
As a % of revenues 78% 78% 74%
- ------------------------------------------------------------------------------
COAL FUEL AND OTHER OPERATIONS
Coal fuel and other operations generated profits of $4 million, losses of $4
million and profits of $10 million for the years ended December 31, 2004, 2003
and 2002, respectively. The increase in profits for 2004 is primarily due to
higher volumes and margins for coal fuel operations of $16 million after-tax. In
addition, coal results in 2003 included the recording of an impairment of
certain assets at the Kentucky May coal mine totaling $11 million after-tax.
This favorability was offset by a reduction in profits of $7 million after-tax
for fuel transportation operations related to the waterborne transportation
ruling by the FPSC (See Note 8C). Profits were also negatively impacted by
higher corporate costs of $10 million in 2004. Corporate costs in the prior year
included $4 million of favorability related to the reduction of an environmental
reserve (See Note 22). The remaining unfavorability in corporate costs is
attributable to increased interest expense related to unresolved tax matters and
higher professional fees.
54
Coal fuel and other operations profits decreased $9 million from 2002 to 2003.
The decrease is due primarily to the recording of an impairment of certain
assets at the Kentucky May coal mine totaling $11 million after-tax. The
decrease in profits is also due to the impact of the retroactive Service Company
allocation in 2003.
The Company is exploring strategic alternatives regarding the Fuels' coal mining
business, which could include divesting these assets. As of December 31, 2004,
the carrying value of long-lived assets of the coal mining business was $66
million. The Company cannot currently predict the outcome of this matter.
Competitive Commercial Operations
CCO generates and sells electricity to the wholesale market from nonregulated
plants. These operations also include marketing activities. The following
summarizes the annual revenues, gross margin and segment profits from the CCO
plants:
- -------------------------------------------------------
(in millions) 2004 2003 2002
- -------------------------------------------------------
Total revenues $ 240 $ 170 $ 92
Gross margin
In millions of $ $ 158 $ 141 $ 83
As a % of revenues 66% 83% 90%
Segment profits (losses) $ (4) $ 20 $ 27
- -------------------------------------------------------
CCO's operations generated segment losses of $4 million in 2004 compared to
segment profits of $20 million in 2003. Results for 2004 were favorably impacted
by increased gross margin, which was more than offset by higher fixed costs and
costs associated with the extinguishment of debt. Revenues increased for 2004
due to increased revenues from marketing and tolling contracts offset by a
termination payment received on a marketing contract in 2003. Expenses for the
cost of fuel and purchased power to supply marketing contracts partially offset
the increased revenues netting to an increase in gross margin for 2004 as
compared to 2003. Fixed costs increased $16 million pre-tax from additional
depreciation and amortization on plants placed into service in 2003 and from an
increase in interest expense of $13 million pre-tax due primarily to interest no
longer being capitalized due to the completion of construction in the prior
year. In addition, plant operating expenses increased $12 million pre-tax
primarily due to higher gas transportation service charges, which increased over
prior year due to a full period of expenses being reflected in current year
results. CCO results for 2004 also include losses of $15 million pre-tax
associated with the extinguishment of a debt obligation. CCO terminated the
Genco financing arrangement in December 2004. The $15 million pre-tax loss is
comprised of a $9 million write-off of remaining unamortized debt issuance costs
and a $6 million realized loss on exiting the related interest rate hedge.
Expenses were favorably impacted by a reduction in Service Company allocations.
Results for 2003 were negatively impacted by the retroactive reallocation of
Service Company costs of $3 million ($2 million after-tax).
CCO's operations generated segment profits of $20 million in 2003 compared to
segment profits of $27 million in 2002. The increase in revenue for 2003 when
compared to 2002 is primarily due to increased contracted capacity on newly
constructed plants, energy revenue from a new, full-requirements power supply
contract and a tolling agreement termination payment received during the first
quarter. Generating capacity increased from 1,554 MW at December 31, 2002, to
3,100 MW at December 31, 2003, with the Effingham, Rowan Phase 2 and Washington
plants being placed in service in 2003. In the second quarter of 2003, PVI
acquired from Williams Energy Marketing and Trading a full-requirements power
supply agreement with Jackson Electric Membership Corporation in Georgia for
$188 million, which resulted in additional revenues of $21 million when compared
to the same periods in 2002. The revenue increases related to higher volumes
were partially offset by higher depreciation costs of $22 million, increased
interest charges of $16 million and other fixed charges.
The Company has contracts for its planned production capacity, which includes
callable resources from the cooperatives, of approximately 77% for 2005,
approximately 81% for 2006 and approximately 75% for 2007. The Company continues
to seek opportunities to optimize its nonregulated generation portfolio.
Rail Services
Rail Services' (Rail) operations represent the activities of Progress Rail and
include railcar and locomotive repair, track-work, rail parts reconditioning and
sales, scrap metal recycling, railcar leasing and other rail-related services.
55
Rail-contributed segment profits of $16 million for 2004 compared with segment
losses of $1 million and $42 million for the years ended December 31, 2003, and
2002, respectively. Results in 2004 were favorably impacted by the strong scrap
metal market in 2004. Revenues were $1.131 billion in 2004, which represents an
increase of $284 million compared to prior year. This increase is due primarily
to increased volumes and higher prices in recycling operations and in part to
increased production and sales in locomotive and railcar services and
engineering and track services. Tonnage for recycling operations is up
approximately 35% on an annualized basis compared to 2003. The increase in
tonnage, coupled with an increase in the average index price of approximately
80%, accounts for the significant increase in revenues year over year. The
American Metal Market index price for #1 railroad heavy melt (which is used as
the index for buying and selling of railcars) has increased to $191 as of
December 31, 2004, from $106 as of December 31, 2003. Cost of goods sold was
$990 million in 2004, which represents an increase of $252 million compared to
the prior year. The increase in costs of goods sold is due to increased costs
for inventory, labor and operations as a result of the increased volume in the
recycling operations, locomotive and railcar services and engineering and track
services. In addition, results in 2003 were negatively impacted by the
retroactive reallocation of Service Company costs of $3 million after-tax. The
favorability related to the reallocation was offset by an increase in general
and administrative costs in 2004 related primarily to higher professional fees
associated with divestiture efforts. See discussion below.
Rail's operations generated segment losses of $1 million in 2003 compared to
segment losses of $42 million in 2002. The reduction in losses in 2003 compared
to 2002 is due primarily to an impairment charge recorded in 2002. The net loss
in 2002 includes a $40 million after-tax estimated impairment of assets held for
sale related to Railcar Ltd., a leasing subsidiary of Progress Rail (See Note
4D). Excluding the impairment recorded in 2002, profits for Rail were flat year
over year 2003 compared to 2002.
In February 2005, Progress Energy signed a definitive agreement to sell its
Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales
price of $405 million. Proceeds from the sale are expected to be used to reduce
debt. See Note 24 for more information.
Corporate & Other
Corporate and Other consists of the operations of Progress Energy Holding
Company (the holding company), Progress Energy Service Company and other
consolidating and nonoperating entities. Corporate and Other also includes other
nonregulated business areas including the operations of SRS and the
telecommunication operations.
OTHER NONREGULATED BUSINESS AREAS
Progress Energy's other business areas include the operations of SRS and the
telecommunications operations. SRS was engaged in providing energy services to
industrial, commercial and institutional customers to help manage energy costs
primarily in the southeastern United States. During 2004, SRS sold its
subsidiary, Progress Energy Solutions (PES). With the disposition of PES, the
Company exited this business area. Telecommunication operations provide
broadband capacity services, dark fiber and wireless services in Florida and the
eastern United States. In December 2003, PTC and Caronet, both wholly owned
telecommunication subsidiaries of Progress Energy, and EPIK, a wholly owned
subsidiary of Odyssey, contributed substantially all of their assets and
transferred certain liabilities to PT LLC, a subsidiary of PTC. The accounts of
PT LLC have been included in the Company's Consolidated Financial Statements
since the transaction date. See additional discussion on the telecommunication
business combination in Note 5A.
Other nonregulated business areas contributed segment losses of $38 million
compared to losses of $24 million for the years ended December 31, 2004, and
2003, respectively. SRS recorded a net loss of $27 million for 2004 compared to
a net loss of $6 million for 2003. The increased loss compared to the prior year
is due primarily to the recording of the litigation settlement reached with San
Francisco United School District (the District) related to civil proceedings. In
June 2004, SRS reached a settlement with the District that settled all
outstanding claims for approximately $43 million pre-tax ($29 million
after-tax). The reduction in earnings due to the settlement was offset partially
by a gain recognized on the sale of Progress Energy Solutions. Telecommunication
operations recorded a net loss of $5 million in 2004 compared to a net profit of
$2 million in 2003. The increase in losses compared to prior year is due to an
increase in fixed costs, mainly depreciation expense, and professional fees
related to the merger with EPIK. The increased losses at SRS and
telecommunication operations were offset partially by a reduction in losses at
the nonutility subsidiaries of PEC. The nonutility subsidiaries of PEC
contributed segment losses of $6 million and $18 million for the years ended
December 31, 2004, and 2003, respectively. Included in the 2003 segment losses
is an investment impairment of $6 million after-tax on the Affordable Housing
portfolio held by the nonutility subsidiaries of PEC (See Note 10B). A reduction
in investment losses accounted for the remaining favorability compared to prior
year.
56
Other nonregulated business areas contributed segment losses of $24 million in
2003 compared to $250 million for the year ended December 31, 2002. The 2002
segment losses include an asset impairment and other charges in the
telecommunications business of $225 million after-tax. See discussion of
impairments at Note 10 of the Consolidated Financial Statements.
CORPORATE SERVICES
Corporate Services (Corporate) includes the operations of the holding company,
Progress Energy Service Company and other consolidating and nonoperating
entities, as summarized below:
- ------------------------------------------------------------------------------------------------
Income (Expense) (in millions)
- ------------------------------------------------------------------------------------------------
2004 Change 2003 Change 2002
- ------------------------------------------------------------------------------------------------
Other interest expense $ (270) $ 15 $ (285) $ (10) $ (275)
Contingent value obligations 9 18 (9) (37) 28
Tax reallocation (37) 1 (38) 18 (56)
Other income taxes 102 (22) 124 11 113
Other income (expense) (2) 19 (21) (16) (5)
- ------------------------------------------------------------------------------------------------
Segment loss $ (198) $ 31 $ (229) $ (34) $ (195)
- ------------------------------------------------------------------------------------------------
The other interest expense decrease for 2004 compared to 2003 is partially due
to the repayment of a $500 million unsecured note by the Holding Company on
March 1, 2004, which reduced interest expense by $27 million pre-tax for 2004.
This reduction was offset by interest no longer being capitalized due to the
completion of construction in the CCO segment in 2003. Approximately $10 million
($6 million after-tax) was capitalized in 2003. No interest expense was
capitalized during 2004. Interest expense increased $10 million in 2003 compared
to 2002 due to a decrease of $9 million in the amount of interest capitalized
related to the construction of plants by CCO which was completed in 2003.
Progress Energy issued 98.6 million contingent value obligations (CVOs) in
connection with the acquisition of FPC in 2000. Each CVO represents the right to
receive contingent payments based on the performance of four synthetic fuel
facilities owned by Progress Energy. The payments, if any, are based on the net
after-tax cash flows the facilities generate. At December 31, 2004, 2003 and
2002, the CVOs had a fair market value of approximately $13 million, $23 million
and $14 million, respectively. Progress Energy recorded unrealized losses of $9
million for 2003 and an unrealized gain of $9 million and $28 million for 2004
and 2002, respectively, to record the changes in fair value of CVOs, which had
average unit prices of $0.14, $0.23 and $0.14 at December 31, 2004, 2003 and
2002, respectively.
Progress Energy and its affiliates file a consolidated federal income tax
return. The consolidated income tax of Progress Energy is allocated to
subsidiaries in accordance with the Intercompany Income Tax Allocation Agreement
(Tax Agreement). The Tax Agreement provided an allocation that recognizes
positive and negative corporate taxable income. The Tax Agreement provides for
an equitable method of apportioning the carryover of uncompensated tax benefits.
Progress Energy tax benefits not related to acquisition interest expense are
allocated to profitable subsidiaries, beginning in 2002, in accordance with a
Public Utility Holding Company Act of 1935, as amended (PUHCA) order.
Other income taxes benefit decreased for 2004 compared to 2003 due primarily to
increased taxes booked at the Holding Company of $21 million. Income taxes
increased an additional $9 million at the Holding Company as a result of a
reserve booked related to identified state tax deficiencies. Other income taxes
benefit decreased for 2003 compared to 2002 primarily for the tax allocation to
the profitable subsidiaries. Other fluctuations in income taxes are primarily
due to changes in pre-tax income.
Discontinued Operations
In 2002, the Company approved the sale of NCNG to Piedmont Natural Gas Company,
Inc. As a result, the operating results of NCNG were reclassified to
discontinued operations for all reportable periods. In September 2003, Progress
Energy completed the sale of NCNG and ENCNG for net proceeds of approximately
$450 million in September 2003. Progress Energy incurred a loss from
discontinued operations of $8 million for 2003 compared with a loss of $24
million for 2002. During the year ended December 31, 2004, the Company recorded
a reduction to the loss on the sale of NCNG of approximately $6 million related
to deferred taxes (See Note 4E).
Cumulative Effect of Accounting Changes
In 2003, Progress Energy recorded adjustments for the cumulative effects of
changes in accounting principles due to the adoption of several new accounting
pronouncements. These adjustments totaled to a $21 million loss after-tax, which
was due primarily to new Financial Accounting Standards Board (FASB) guidance
related to the accounting for certain contracts. This guidance discusses whether
57
the pricing in a contract that contains broad market indices qualifies for
certain exceptions that would not require the contract to be recorded at its
fair value. PEC Electric had a purchase power contract with Broad River LLC that
did not meet the criteria for an exception, and a negative fair value adjustment
was recorded in 2003 for $23 million after-tax (See Note 18A).
APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The Company prepared its Consolidated Financial Statements in accordance with
accounting principles generally accepted in the United States. In doing so,
certain estimates were made that were critical in nature to the results of
operations. The following discusses those significant estimates that may have a
material impact on the financial results of the Company and are subject to the
greatest amount of subjectivity. Senior management has discussed the development
and selection of these critical accounting policies with the Audit Committee of
the Company's Board of Directors.
Utility Regulation
As discussed in Note 8, the Company's regulated utilities segments are subject
to regulation that sets the prices (rates) the Company is permitted to charge
customers based on the costs that regulatory agencies determine the Company is
permitted to recover. At times, regulators permit the future recovery through
rates of costs that would be currently charged to expense by a nonregulated
company. This rate-making process results in deferral of expense recognition and
the recording of regulatory assets based on anticipated future cash inflows. As
a result of the changing regulatory framework in each state in which the Company
operates, a significant amount of regulatory assets has been recorded. The
Company continually reviews these assets to assess their ultimate recoverability
within the approved regulatory guidelines. Impairment risk associated with these
assets relates to potentially adverse legislative, judicial or regulatory
actions in the future. Additionally, the state regulatory agencies often provide
flexibility in the manner and timing of the depreciation of property, nuclear
decommissioning costs and amortization of the regulatory assets. Note 8 provides
additional information related to the impact of utility regulation on the
Company.
Asset Impairments
As discussed in Note 10, the Company evaluates the carrying value of long-lived
assets for impairment whenever indicators exist. Examples of these indicators
include current period losses combined with a history of losses, or a projection
of continuing losses, or a significant decrease in the market price of a
long-lived asset group. If an indicator exists, the asset group held and used is
tested for recoverability by comparing the carrying value to the sum of
undiscounted expected future cash flows directly attributable to the asset
group. If the asset group is not recoverable through undiscounted cash flows or
if the asset group is to be disposed of, an impairment loss is recognized for
the difference between the carrying value and the fair value of the asset group.
A high degree of judgment is required in developing estimates related to these
evaluations and various factors are considered, including projected revenues and
cost and market conditions.
Due to the reduction in coal production at the Kentucky May coal mine, the
Company evaluated its long-lived assets in 2003 and recorded an impairment of
$17 million before tax ($11 million after tax). Fair value was determined based
on discounted cash flows. During 2002, the Company recorded pre-tax long-lived
asset impairments of $305 million related to its telecommunications business.
The fair value of these assets was determined considering various factors,
including a valuation study heavily weighted on a discounted cash flow
methodology and using market approaches as supporting information.
58
The Company continually reviews its investments to determine whether a decline
in fair value below the cost basis is other than temporary. In 2003, PEC's
affordable housing investment (AHI) portfolio was reviewed and deemed to be
impaired based on various factors, including continued operating losses of the
AHI portfolio and management performance issues arising at certain properties
within the AHI portfolio. As a result, PEC recorded an impairment of $18 million
on a pre-tax basis during 2003. PEC also recorded an impairment of $3 million
for a cost investment. During 2002, the Company recorded pre-tax impairments to
its cost method investment in Interpath of $25 million. The fair value of this
investment was determined considering various factors, including a valuation
study heavily weighted on a discounted cash flow methodology and using market
approaches as supporting information. These cash flows included numerous
assumptions, including, the pace at which the telecommunications market would
rebound. In the fourth quarter of 2002, the Company sold its remaining interest
in Interpath for a nominal amount.
Under the full-cost method of accounting for oil and gas properties, total
capitalized costs are limited to a ceiling based on the present value of
discounted (at 10%) future net revenues using current prices, plus the lower of
cost or fair market value of unproved properties. The ceiling test takes into
consideration the prices of qualifying cash flow hedges as of the balance sheet
date. If the ceiling (discounted revenues) is not equal to or greater than total
capitalized costs, the Company is required to write-down capitalized costs to
this level. The Company performs this ceiling test calculation every quarter. No
write-downs were required in 2004, 2003 or 2002.
Goodwill
As discussed in Note 9, effective January 1, 2002, the Company adopted FASB
Statement No. 142, "Goodwill and Other Intangible Assets," which requires that
goodwill be tested for impairment at least annually and more frequently when
indicators of impairment exist. The Company completed the initial transitional
goodwill impairment test, which indicated that the Company's goodwill was not
impaired as of January 1, 2002. The Company performed the annual goodwill
impairment test for the CCO segment in the first quarters of 2004 and 2003, and
the annual goodwill impairment test for the PEC Electric and PEF segments in the
second quarters of 2004 and 2003, each of which indicated no impairment. If the
fair values for the utility segments were lower by approximately 10%, there
still would be no impact on the reported value of their goodwill. The carrying
amounts of goodwill at December 31, 2004 and 2003, for reportable segments PEC
Electric, PEF and CCO, are $1,922 million, $1,733 million and $64 million,
respectively. In December 2003, $7 million in goodwill was acquired as part of
Progress Telecommunications Corporation's partial acquisition of EPIK and was
reported in the Corporate and Other segment. The Company revised the preliminary
EPIK purchase price allocation as of September 2004, and the $7 million of
goodwill was reallocated to certain tangible assets acquired based on the
results of valuations and appraisals.
Synthetic Fuels Tax Credits
As discussed in Note 23E, Progress Energy, through the Fuels business unit, owns
facilities that produce synthetic fuel as defined under the Internal Revenue
Code. The production and sale of the synthetic fuels from these facilities
qualifies for tax credits under Section 29 if certain requirements are
satisfied, including a requirement that the synthetic fuels differs
significantly in chemical composition from the coal used to produce such
synthetic fuels and that the fuel was produced from a facility placed in service
before July 1, 1998. The amount of Section 29 credits that the Company is
allowed to claim in any calendar year is limited by the amount of the Company's
regular federal income tax liability. Synthetic fuels tax credit amounts allowed
but not utilized are carried forward indefinitely as deferred alternative
minimum tax credits on the Consolidated Balance Sheets. All of Progress Energy's
synthetic fuel facilities have received PLRs from the IRS with respect to their
operations, although these do not address placed-in-service date determinations.
The PLRs do not limit the production on which synthetic fuel credits may be
claimed. The current Section 29 tax credit program expires at the end of 2007.
These tax credits are subject to review by the IRS, and if Progress Energy fails
to prevail through the administrative or legal process, there could be a
significant tax liability owed for previously taken Section 29 credits, with a
significant impact on earnings and cash flows. Additionally, the ability to use
tax credits currently being carried forward could be denied. See further
discussion in "OTHER MATTERS" below, Note 23E and in the "Risk Factors" section.
Pension Costs
As discussed in Note 17A, Progress Energy maintains qualified noncontributory
defined benefit retirement (pension) plans. The Company's reported costs are
dependent on numerous factors resulting from actual plan experience and
assumptions of future experience. For example, such costs are impacted by
employee demographics, changes made to plan provisions, actual plan asset
returns and key actuarial assumptions, such as expected long-term rates of
return on plan assets and discount rates used in determining benefit obligations
and annual costs.
59
Due to a slight decline in the market interest rates for high-quality (AAA/AA)
debt securities, which are used as the benchmark for setting the discount rate
used to present value future benefit payments, the Company lowered the discount
rate to 5.9% at December 31, 2004, which will increase the 2005 benefit costs
recognized, all other factors remaining constant. Plan assets performed well in
2004, with returns of approximately 14%. That positive asset performance will
result in decreased pension costs in 2005, all other factors remaining constant.
Evaluations of the effects of these and other factors have not been completed,
but the Company estimates that the total cost recognized for pensions in 2005
will be approximately $12 to $20 million higher than the amount recorded in
2004.
The Company has pension plan assets with a fair value of approximately $1.8
billion at December 31, 2004. The Company's expected rate of return on pension
plan assets is 9.25%. The Company reviews this rate on a regular basis. Under
Statement of Financial Accounting Standards No. 87, "Employer's Accounting for
Pensions" (SFAS No. 87), the expected rate of return used in pension cost
recognition is a long-term rate of return; therefore, the Company would adjust
that return only if its fundamental assessment of the debt and equity markets
changes or its investment policy changes significantly. The Company believes
that its pension plans' asset investment mix and historical performance support
the long-term rate of 9.25% being used. The Company did not adjust the rate in
response to short-term market fluctuations such as the abnormally high market
return levels of the latter 1990s, recent years' market declines and the market
rebound in 2003 and 2004. A 0.25% change in the expected rate of return for 2004
would have changed 2004 pension costs by approximately $4 million.
Another factor affecting the Company's pension costs, and sensitivity of the
costs to plan asset performance, is its selection of a method to determine the
market-related value of assets, i.e., the asset value to which the 9.25%
expected long-term rate of return is applied. SFAS No. 87 specifies that
entities may use either fair value or an averaging method that recognizes
changes in fair value over a period not to exceed five years, with the method
selected applied on a consistent basis from year to year. The Company has
historically used a five-year averaging method. When the Company acquired
Florida Progress Corporation (Florida Progress) in 2000, it retained the Florida
Progress historical use of fair value to determine market-related value for
Florida Progress pension assets. Changes in plan asset performance are reflected
in pension costs sooner under the fair value method than the five-year averaging
method, and, therefore, pension costs tend to be more volatile using the fair
value method. For example, in 2004 the expected return for assets subject to the
averaging method was 2% lower than in 2003, whereas the expected return for
assets subject to the fair value method was 24% higher than in 2003.
Approximately 50% of the Company's pension plan assets is subject to each of the
two methods.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Progress Energy is a registered holding company and, as such, has no operations
of its own. The Company's primary cash needs at the holding company level are
its common stock dividend and interest expense and principal payments on its
$4.3 billion of senior unsecured debt. The ability to meet these needs is
dependent on the earnings and cash flows of its two electric utilities and
nonregulated subsidiaries, and the ability of those subsidiaries to pay
dividends or repay funds to Progress Energy.
Other significant cash requirements of the Company arise primarily from the
capital-intensive nature of its electric utility operations and expenditures for
its diversified businesses, primarily those of the Fuels segment.
The Company relies upon its operating cash flow, primarily generated by its two
regulated electric utility subsidiaries, commercial paper and bank facilities,
and its ability to access long-term debt and equity capital markets for sources
of liquidity.
The majority of the Company's operating costs are related to its two regulated
electric utilities, and a significant portion of these costs is recovered from
customers through fuel and energy cost recovery clauses.
As a registered holding company under Public Utility Holding Company Act of 1935
(PUHCA), Progress Energy obtains approval from the SEC for the issuance and sale
of securities as well as the establishment of intercompany extensions of credit
(utility and nonutility money pools). PEC and PEF participate in the utility
money pool, which allows the two utilities to lend and borrow between each
other. A nonutility money pool allows Progress Energy's nonregulated operations
to lend and borrow funds among each other. Progress Energy can lend money to the
utility and nonutility money pools but cannot borrow funds.
60
Cash from operations, asset sales and the issuance of common stock are expected
to fund capital expenditures and common dividends for 2005. Any excess cash
proceeds would be used to reduce debt. To the extent necessary, short- and
long-term debt may also be used as a source of liquidity.
The Company believes its internal and external liquidity resources will be
sufficient to fund its current business plans. Risk factors associated with
commercial paper backup credit facilities and credit ratings are discussed below
and in the "Risk Factors" section of this report.
The following discussion of the Company's liquidity and capital resources is on
a consolidated basis.
HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002
Cash Flows from Operations
Cash from operations is the primary source used to meet operating requirements
and capital expenditures. Net cash provided by operating activities from
continuing operations for the three years ending December 31, 2004, 2003 and
2002 were $1.6 billion, $1.7 billion and $1.6 billion, respectively.
Cash from operating activities for 2004 when compared with 2003 decreased $117
million, as the net result of the impact of hurricane costs, partially offset by
the impact of an under-recovery of fuel costs in 2003. The increase in cash from
operating activities for 2003 when compared with 2002 is largely the result of
improved operating results at PEC.
During the third quarter of 2004, four hurricanes struck significant portions of
the Company's service territories, with the most significant impact on PEF's
territory. Restoration of the Company's systems from storm-related damage cost
an estimated $398 million. PEC's cost totaled $13 million, of which $12 million
was charged to O&M and $1 million was charged to capital. PEF's cost totaled
$385 million, of which $338 million was charged to Storm Damage Reserve pursuant
to a regulatory order and $47 million was charged to capital. On November 2,
2004, PEF filed a petition with the Florida Public Service Commission (FPSC) to
recover $252 million of storm costs plus interest from retail rate payers over a
two-year period (See Note 3).
Progress Energy is allowed to recover fuel costs incurred by PEC and PEF through
their respective fuel cost recovery surcharges. Fuel price volatility can lead
to over- or under-recovery of fuel costs, as changes in fuel prices are not
immediately reflected in fuel surcharges due to regulatory lag in setting the
surcharges. As a result, fuel price volatility can be both a source of and a
drag on liquidity resources, depending on what phase of the cycle of price
volatility the Company is experiencing. In addition, in 2004 PEF agreed with the
FPSC to use a two-year period to determine the surcharge for the underrecovered
fuel costs incurred in 2004 (See Note 8C).
Investing Activities
Net cash used in investing activities for the three years ending December 31,
2004, 2003 and 2002 were $0.9 billion, $1.5 billion and $2.2 billion,
respectively.
Utility property additions for the Company's regulated electric operations were
$1.0 billion or approximately 75% of consolidated capital expenditures in 2004
and $1.0 billion or approximately 58% of consolidated capital expenditures in
2003, excluding proceeds from asset sales. Capital expenditures for the
regulated electric operations are primarily for normal construction activity and
ongoing capital expenditures related to environmental compliance programs.
Capital expenditures for the nonregulated operations are primarily for natural
gas development activities and normal construction activity.
Excluding proceeds from sales of subsidiaries and other investments, cash used
in investing activities decreased approximately $887 million in 2004 when
compared with 2003. The decrease is due primarily to the acquisition of a
nonregulated generation contract and acquisition of gas assets in 2003 and net
proceeds from short-term investments in 2004, compared to net purchases of
short-term investments in 2003.
Excluding proceeds from sales of subsidiaries and other investments, cash used
in investing activities was $2.1 billion in 2003, down approximately $119
million when compared with 2002. The decrease is due primarily to lower utility
property additions due to completion of Hines 2 construction at PEF and lower
acquisitions of nonregulated assets.
61
During 2004, sales of subsidiaries and other investments primarily included
proceeds from the sale of Railcar Ltd. assets of approximately $75 million and
proceeds of approximately $251 million related to the sale of natural gas assets
in the Forth Worth basin of Texas. Progress Energy used the proceeds from these
sales to reduce indebtedness, including $241 million to pay off the Progress
Genco Ventures, LLC, bank facility.
During 2003, the Company realized approximately $450 million of net cash
proceeds from the sale of NCNG and ENCNG. The Company also received net proceeds
of approximately $97 million in October 2003 for the sale of its Mesa gas
properties in Colorado. Progress Energy used the proceeds from these sales to
reduce indebtedness, primarily commercial paper, then outstanding.
During 2003, the Company acquired approximately 200 natural gas-producing wells
for a cash purchase price of $168 million. The Company also acquired a long-term
full-requirements power supply agreement with Jackson Electric Membership
Corporation for a cash payment of $188 million.
During 2002, the Company purchased two electric generation projects for a cash
purchase price of $348 million.
Financing Activities
Net cash (used in) provided by financing activities for the three years ending
December 31, 2004, 2003 and 2002 were $(720), $(192) million and $581 million,
respectively. See Note 13 for details of debt and credit facilities.
For 2004 and 2003, cash from operations exceeded net cash used in investing
activities by $735 million and $178 million, respectively, due primarily to
asset sales, which allowed for a net decrease in cash provided by financing
activities. For 2002, net cash used in investing activity exceeded cash from
operations by $574 million, which resulted in net cash from financing activities
of $581 million.
In addition to the financing activities discussed under "Overview," the
financing activities of the Company included:
2005
o In January 2005, the Company used proceeds from the issuance of commercial
paper to pay off $260 million of revolving credit agreement (RCA) loans.
o On January 31, 2005, Progress Energy, Inc. entered into a new $600 million
revolving credit agreement, which expires December 30, 2005. This facility
was added to provide additional liquidity during 2005 due in part to the
uncertainty of the timing of storm restoration cost recovery from the
hurricanes in Florida during 2004. The credit agreement includes a defined
maximum total debt to total capital ratio of 68% and a minimum interest
coverage ratio of 2.5 to 1. The credit agreement also contains various
cross-default and other acceleration provisions. On February 4, 2005, $300
million was drawn under the new facility to reduce commercial paper and pay
off the remaining amount of RCA loans outstanding.
o In March 2005, Progress Energy, Inc.'s five-year credit facility was
amended to increase the maximum total debt to total capital ratio from 65%
to 68% in anticipation of the potential impacts of proposed accounting
rules for uncertain tax positions. See Notes 2 and 23E.
2004
o During the fourth quarter of 2004, Progress Energy and its subsidiaries PEC
and PEF borrowed a net total of $475 million under certain revolving credit
facilities. The borrowed funds were used to pay off maturing commercial
paper and for other cash needs. A summary of RCA loans and available
capacity as of December 31, 2004, is as follows:
62
- --------------------------------------------------------------------------------------------------------------
(in millions)
Company Description Total Outstanding Available
- --------------------------------------------------------------------------------------------------------------
Progress Energy, Inc. 5-Year (expiring 8/5/09) $ 1,130 $ 160 $ 970
Progress Energy Carolinas, Inc. 364-Day (expiring 7/27/05) 165 90 75
Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 - 285
Progress Energy Florida, Inc. 364-Day (expiring 3/29/05) 200 170 30
Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 55 145
Less: amounts reserved(a) - - (574)
- --------------------------------------------------------------------------------------------------------------
Total credit facilities $ 1,980 $ 475 $ 931
- --------------------------------------------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding or
backing letters of credit, they are not available for additional
borrowings.
o On December 17, 2004, the Company used proceeds from the sale of natural
gas assets to extinguish Progress Genco Ventures, LLC's $241 million bank
facility (See Note 13D).
o Progress Energy took advantage of favorable market conditions and entered
into a new $1.1 billion five-year line of credit, effective August 5, 2004,
and expiring August 5, 2009. This facility replaced Progress Energy's $250
million 364-day line of credit and its three-year $450 million line of
credit, which were both scheduled to expire in November 2004.
o On July 28, 2004, PEC extended its $165 million 364-day line of credit,
which was scheduled to expire on July 29, 2004. The line of credit will
expire on July 27, 2005.
o On July 1, 2004, PEF paid at maturity $40 million 6.69% Medium-Term Notes
Series B with commercial paper proceeds and cash from operations.
o On April 30, 2004, PEC redeemed $35 million of Darlington County 6.6%
Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover
County 6.3% Series Pollution Control Bonds at 101.5% of par, and $2 million
of Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with
cash from operations.
o On March 1, 2004, Progress Energy used available cash and proceeds from the
issuance of commercial paper to pay at maturity $500 million 6.55% senior
unsecured notes. Cash and commercial paper capacity for this retirement was
created primarily from proceeds of the sale of assets in 2003.
o On February 9, 2004, Progress Capital Holdings, Inc., paid at maturity $25
million 6.48% medium term notes with available cash from operations.
o On January 15, 2004, PEC paid at maturity $150 million 5.875% First
Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also
paid at maturity $150 million 7.875% First Mortgage Bonds with commercial
paper proceeds and cash from operations.
o For 2004, the Company issued approximately 1 million shares of its common
stock for approximately $73 million in net proceeds from its Investor Plus
Stock Purchase Plan and its employee benefit and stock option plans, net of
purchases of restricted shares. For 2004, the dividends paid on common
stock were approximately $558 million.
2003
o Progress Energy obtained a three-year financing order, allowing it to issue
up to $2.8 billion of long-term securities, $1.5 billion of short-term
debt, and $3 billion in parent guarantees. Progress Energy issued
approximately 8 million shares of common stock for approximately $304
million in net proceeds from its Investor Plus Stock Purchase Plan and its
employee benefit plans, net of purchases of restricted shares. For 2003,
the dividends paid on common stock were approximately $541 million.
o PEC redeemed $250 million and issued $600 million in first mortgage bonds.
63
o PEF redeemed $250 million, issued $950 million and paid at maturity $180
million in first mortgage bonds. PEF also paid at maturity $35 million in
medium-term notes.
o Progress Capital Holdings, Inc., paid at maturity $58 million in
medium-term notes.
o Progress Genco Ventures, LLC, terminated its $50 million working capital
credit facility. Under its related construction facility, Genco had drawn
$241 million at December 31, 2003.
2002
o Progress Energy issued $800 million in senior unsecured notes. Progress
Energy issued approximately 2 million shares representing approximately $86
million in proceeds from its Investor Plus Stock Purchase Plan and its
employee benefit plans.
o PEC issued and redeemed $500 million in senior unsecured notes and $48.5
million in pollution control obligations. PEC also redeemed $150 million
and paid at maturity $100 million in first mortgage bonds.
o PEF issued and redeemed $241 million in pollution control obligations and
paid at maturity $30 million in medium-term notes.
o Progress Capital Holdings, Inc., paid at maturity $50 million in
medium-term notes.
o Progress Genco Ventures, LLC, obtained a $440 million bank facility,
including $50 million for working capital. During the year, $130 million of
the facility was terminated. The amount outstanding at December 31, 2002,
was $225 million.
o In November 2002, the Company issued 14.7 million shares of common stock
for net cash proceeds of approximately $600 million, which were primarily
used to retire commercial paper. For 2002, the dividends paid on common
stock were approximately $480 million.
FUTURE LIQUIDITY AND CAPITAL RESOURCES
The Company's two electric utilities produced over 100% of consolidated cash
from operations in 2004. It is expected that the two electric utilities will
continue to produce a majority of the consolidated cash flows from operations
over the next several years as its nonregulated investments, primarily
generation assets, improve asset utilization and increase their operating cash
flows.
PEF notified the FPSC in January 2005 of its intent to file for an increase in
its base rates effective January 1, 2006. If approved by the FPSC, an increase
in PEF's base rates would increase future operating cash flows. PEF has faced
significant cost increases over the past decade and expects its operational
costs to continue to increase. These costs include the costs associated with
completion of the Hines 3 generation facility, extraordinary hurricane damage
costs including capital costs not expected to be directly recoverable, the need
to replenish the depleted storm reserve and the expected infrastructure
investment necessary to meet high customer expectations, coupled with the
demands placed on PEF as a result of strong customer growth. If the FPSC does
not approve PEF's request to increase base rates, the Company's results of
operations and financial condition could be negatively impacted. The Company
cannot predict the outcome of this matter. Related risks are described in more
detail in the "Risk Factors" section.
In addition, Fuels' synthetic fuel operations do not currently produce positive
operating cash flow due to the difference in timing of when tax credits are
recognized for financial reporting purposes and when tax credits are realized
for tax purposes. See Note 23E for further discussion.
Capital Expenditures
Total cash from operations provided the funding for the Company's capital
expenditures, including property additions, nuclear fuel expenditures and
diversified business property additions during 2004, excluding proceeds from
asset sales of $366 million.
64
As shown in the table below, Progress Energy expects the majority of its capital
expenditures to be incurred at its regulated operations. See Note 8F for a
discussion of expected impacts on future capital expenditures due to changes in
capitalization practice for regulated operations. The Company anticipates its
regulated capital expenditures will increase in 2005 due to increased spending
on Clean Air initiatives. Forecasted nonregulated expenditures relate primarily
to Progress Fuels and its gas operations, mainly for drilling new wells.
- ----------------------------------------------------------------------------------------------
Actual Forecasted
----------- -------------------------------------------
(in millions) 2004 2005 2006 2007
- ----------------------------------------------------------------------------------------------
Regulated capital expenditures $ 998 $ 1,030 $ 1,040 $ 1,090
Nuclear fuel expenditures 101 120 90 150
AFUDC - borrowed funds (6) (10) (10) (10)
Nonregulated capital expenditures 236 190 180 190
- ----------------------------------------------------------------------------------------------
Total $ 1,329 $ 1,330 $ 1,300 $ 1,420
- ----------------------------------------------------------------------------------------------
Regulated capital expenditures in the table above include total expenditures
from 2005 through 2006 of approximately $65 million expected to be incurred at
PEC fossil-fueled electric generating facilities to comply with Section 110 of
the Clean Air Act, referred to as the NOx SIP Call.
The Company also expects to incur expenditures of approximately $15 million ($10
million at PEC and $5 million at PEF) from 2005 through 2007 and additional
expenditures of approximately $70 million to $100 million ($10 million to $20
million at PEC and $60 million to $80 million at PEF) from 2008 through 2009 for
compliance with the Section 316(b) requirements of the Clean Water Act (See Note
22).
In June 2002, legislation was enacted in North Carolina requiring the state's
electric utilities to reduce the emissions of nitrogen oxide (NOx) and sulfur
dioxide (SO2) from coal-fired power plants. PEC expects its capital costs to
meet these emission targets will be approximately $895 million by 2013. For the
years 2005 through 2007, the Company expects to incur approximately $475 million
of total capital costs associated with this legislation, which is included in
the table above (See Note 22).
All projected capital and investment expenditures are subject to periodic review
and revision and may vary significantly depending on a number of factors
including, but not limited to, industry restructuring, regulatory constraints,
market volatility and economic trends.
Other Cash Needs
As of December 31, 2004, on a consolidated basis, the Company had $349 million
of long-term debt maturing in 2005. Progress Energy expects to pay these
maturities using funds from operations, issuance of new long-term debt,
commercial paper borrowings and/or issuance of new equity securities.
In 2006, $800 million of Progress Energy senior unsecured notes will mature. The
Company expects to fund the maturity using proceeds from the sale of the
Progress Rail subsidiary, issuance of new long-term debt, commercial paper
borrowings and/or issuance of new equity securities.
During the fourth quarter of 2004, Progress Energy announced the launch of a new
cost management initiative aimed at achieving nonfuel O&M expense reductions of
$75 million to $100 million annually by the end of 2007. In connection with this
cost management initiative, the Company expects to incur one-time pre-tax
charges of approximately $130 million. Approximately $30 million of that amount
relates to payments for severance benefits, which will be recognized in the
first quarter of 2005 and paid over time. The remaining approximately $100
million will be recognized in the second quarter of 2005 and relates primarily
to postretirement benefits that will be paid over time to those eligible
employees who elect to participate in the voluntary enhanced retirement program
(See Note 24).
Credit Facilities
At December 31, 2004, the Company and its subsidiaries had committed lines of
credit and outstanding balances as shown in the table in Note 13. All of the
credit facilities supporting the credit were arranged through a syndication of
financial institutions. There are no bilateral contracts associated with these
facilities.
65
The Company's financial policy precludes issuing commercial paper in excess of
its supporting lines of credit. At December 31, 2004, the Company had $424
million of commercial paper outstanding, $150 million reserved for backing of
letters of credit and an additional $475 million drawn directly from the credit
facilities, leaving $931 million available for issuance or drawdown. In
addition, the Company has requirements to pay minimal annual commitment fees to
maintain its credit facilities. At December 31, 2003, the Company had $4 million
of commercial paper outstanding. The Company expects to continue to use
commercial paper issuances as a source of liquidity as long as it maintains its
current short-term ratings.
All of the credit facilities include a defined maximum total debt-to-total
capital ratio (leverage) and coverage ratios. The Company is in compliance with
these covenants at December 31, 2004. See Note 13 for a discussion of the credit
facilities' financial covenants, material adverse change clause provisions and
cross-default provisions. At December 31, 2004, the calculated ratios for the
companies, pursuant to the terms of the agreements, are as disclosed in Note 13.
Both PEC and PEF plan to enter into new five-year lines of credit in 2005 to
replace their existing credit facilities.
The Company has on file with the SEC a shelf registration statement under which
senior notes, junior debentures, common and preferred stock and other trust
preferred securities are available for issuance by the Company. At December 31,
2004, the Company had approximately $1.1 billion available under this shelf
registration.
Progress Energy and PEF each have an uncommitted bank bid facility authorizing
each of them to borrow and reborrow, and have loans outstanding at any time, up
to $300 million and $100 million, respectively. At December 31, 2004, there were
no outstanding loans against these facilities.
PEC currently has on file with the SEC a shelf registration statement under
which it can issue up to $900 million of various long-term securities. PEF
currently has on file registration statements under which it can issue an
aggregate of $750 million of various long-term debt securities.
Both PEC and PEF can issue First Mortgage Bonds under their respective First
Mortgage Bond indentures. At December 31, 2004, PEC and PEF could issue up to
$2.9 billion and $3.7 billion, respectively, based on property additions and
$2.2 billion and $176 million, respectively, based upon retirements.
The following table shows Progress Energy's and Progress Energy Carolinas'
capital structure at December 31:
- --------------------------------------------------------------------------------
Progress Energy PEC
------------------------- ---------------------------
2004 2003 2004 2003
- --------------------------------------------------------------------------------
Common stock 41.7% 40.5% 47.1% 48.2%
Preferred stock and
minority interest 0.7% 0.7% 0.9% 0.9%
Total debt 57.6% 58.8% 52.0% 50.9%
- --------------------------------------------------------------------------------
The amount and timing of future sales of company securities will depend on
market conditions, operating cash flow, asset sales and the specific needs of
the Company. The Company may from time to time sell securities beyond the amount
needed to meet capital requirements in order to allow for the early redemption
of long-term debt, the redemption of preferred stock, the reduction of
short-term debt or for other general corporate purposes.
66
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.
Outlook Negative Negative Stable
Corporate credit rating n/a BBB n/a
Senior unsecured debt Baa2 BBB- BBB-
Commercial paper P-2 A-3 n/a
- ---------------------------------------------------------------------------------------------------
Progress Energy Carolinas, Inc.
Corporate credit rating n/a BBB n/a
Commercial paper P-2 A-3 F2
Senior secured debt A3 BBB A-
Senior unsecured debt Baa1 BBB BBB+
- ---------------------------------------------------------------------------------------------------
Progress Energy Florida, Inc.
Corporate credit rating n/a BBB n/a
Commercial paper P-2 A-3 F2
Senior secured debt A2 BBB A-
Senior unsecured debt A3 BBB BBB+
- ---------------------------------------------------------------------------------------------------
FPC Capital I
Preferred stock* Baa2 BB+ n/a
- --------------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Senior unsecured debt* Baa1 BBB- n/a
- ---------------------------------------------------------------------------------------------------
*Guaranteed by Florida Progress Corporation.
These ratings reflect the current views of these rating agencies, and no
assurances can be given that these ratings will continue for any given period of
time. However, the Company monitors its financial condition as well as market
conditions that could ultimately affect its credit ratings.
On February 11, 2005, Moody's credit rating agency announced that it lowered the
ratings of PEF, Progress Capital Holdings and FPC Capital Trust I and changed
their rating outlooks to stable from negative. Moody's affirmed the ratings of
Progress Energy and PEC. The rating outlooks continue to be stable at PEC and
negative at Progress Energy. Moody's stated that it took this action primarily
due to declining cash flow coverages and rising leverage, higher O&M costs,
uncertainty regarding the timing of hurricane cost recovery, regulatory risks
associated with the upcoming rate case in Florida and ongoing capital
requirements to meet Florida's growing demand.
On October 19, 2004, S&P changed Progress Energy's outlook from stable to
negative. S&P cited the uncertainties regarding the timing of the recovery of
hurricane costs, the Company's debt reduction plans and the IRS audit of the
Company's Earthco synthetic fuels facilities as the reasons for the change in
outlook. On October 25, 2004, S&P reduced the short-term debt rating of Progress
Energy, PEC and PEF to A-3 from A-2, as a result of their change in outlook
discussed above.
On October 20, 2004, Moody's changed its outlook for Progress Energy from stable
to negative and placed the ratings of PEF under review for possible downgrade.
PEC's ratings were affirmed by Moody's.
Moody's cited the following reasons for its change in the outlook for Progress
Energy: financial ratios that are weak for its current rating category; rising
O&M, pension, benefit and insurance costs; and delays in executing its
deleveraging plan. With respect to PEF, Moody's cited declining cash flow
coverages and rising leverage over the last several years, expected funding
needs for a large capital expenditure program, risks with regard to its upcoming
2005 rate case and the timing of hurricane cost recovery as reasons for putting
its ratings under review.
The changes by S&P and Moody's do not trigger any debt or guarantee collateral
requirements, nor do they have any material impact on the overall liquidity of
Progress Energy or any of its affiliates. To date, Progress Energy's, PEC's and
PEF's access to the commercial paper markets has not been materially impacted by
the rating agencies' actions. However, the changes have increased the interest
rate incurred on its short-term borrowings by 0.25% to 0.875%.
67
If Standard & Poor's lowers Progress Energy's senior unsecured rating one
ratings category to BB+ from its current rating, it would be a noninvestment
grade rating. The effect of a noninvestment grade rating would primarily be to
increase borrowing costs. The Company's liquidity would essentially remain
unchanged, as the Company believes it could borrow under its revolving credit
facilities instead of issuing commercial paper for its short-term borrowing
needs. However, there would be additional funding requirements of approximately
$450 million due to ratings triggers embedded in various contracts, as more
fully described below under "Guarantees" and "Risk Factors."
The Company and its subsidiaries' debt indentures and credit agreements do not
contain any "ratings triggers," which would cause the acceleration of interest
and principal payments in the event of a ratings downgrade. However, in the
event of a downgrade, the Company and/or its subsidiaries may be subject to
increased interest costs on the credit facilities backing up the commercial
paper programs. In addition, the Company and its subsidiaries have certain
contracts that have provisions triggered by a ratings downgrade to a rating
below investment grade. These contracts include counterparty trade agreements,
derivative contracts, certain Progress Energy guarantees and various types of
third-party purchase agreements.
OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
The Company's off-balance sheet arrangements and contractual obligations are
described below.
Guarantees
As a part of normal business, Progress Energy and certain wholly owned
subsidiaries enter into various agreements providing future financial or
performance assurances to third parties that are outside the scope of Financial
Accounting Standards Board (FASB) Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN No. 45). These agreements are entered into
primarily to support or enhance the creditworthiness otherwise attributed to
Progress Energy and subsidiaries on a stand-alone basis, thereby facilitating
the extension of sufficient credit to accomplish the subsidiaries' intended
commercial purposes. The Company's guarantees include performance obligations
under power supply agreements, tolling agreements, transmission agreements, gas
agreements, fuel procurement agreements and trading operations. The Company's
guarantees also include standby letters of credit, surety bonds and guarantees
in support of nuclear decommissioning. At December 31, 2004, the Company had
issued $1.3 billion of guarantees for future financial or performance assurance.
Management does not believe conditions are likely for significant performance
under the guarantees of performance issued by or on behalf of affiliates.
The majority of contracts supported by the guarantees contain provisions that
trigger guarantee obligations based on downgrade events to below investment
grade (below BBB- or Baa3), ratings triggers, monthly netting of exposure and/or
payments and offset provisions in the event of a default. The recent outlook
changes from S&P and Moody's do not trigger any guarantee obligations. As of
December 31, 2004, if the guarantee obligations were triggered, the maximum
amount of liquidity requirements to support ongoing operations within a 90-day
period, associated with guarantees for the Company's nonregulated portfolio and
power supply agreements was $450 million. The Company would meet this obligation
with cash or letters of credit.
As of December 31, 2004, Progress Energy had guarantees issued on behalf of
third parties of approximately $10 million. See Note 23D for a discussion of
guarantees in accordance with FIN No. 45.
Market Risk and Derivatives
Under its risk management policy, the Company may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. See Note 18 and Item 7A,
"Quantitative and Qualitative Disclosures About Market Risk," for a discussion
of market risk and derivatives.
Contractual Obligations
The Company is party to numerous contracts and arrangements obligating it to
make cash payments in future years. These contracts include financial
arrangements such as debt agreements and leases, as well as contracts for the
purchase of goods and services. Amounts in the following table are estimated
based upon contractual terms and actual amounts will likely differ from amounts
presented below. Further disclosure regarding the Company's contractual
obligations is included in the respective notes. The Company takes into
consideration the future commitments when assessing its liquidity and future
financing needs. The following table reflects Progress Energy's contractual cash
obligations and other commercial commitments at December 31, 2004, in the
respective periods in which they are due:
68
- -------------------------------------------------------------------------------------------------------------------
Less than 1 More than 5
(in millions) Total year 1-3 years 3-5 years years
- -------------------------------------------------------------------------------------------------------------------
Long-term debt (a) (See Note 13) $ 9,942 $ 349 $ 1,637 $ 1,387 $ 6,569
Interest payments on long-term debt and
interest rate derivatives (b) 3,064 301 489 423 1,851
Capital lease obligations (See Note 23C) 50 4 8 7 31
Operating leases (See Note 23C) 597 66 113 112 306
Fuel and purchased power (c) (See Note 23A) 13,010 2,692 3,088 1,346 5,884
Other purchase obligations (See Note 23A) 633 151 134 80 268
NC Clean Air capital
commitments (See Note 22) 764 170 297 143 154
Other commitments (d)(e) 243 42 70 26 105
- -------------------------------------------------------------------------------------------------------------------
Total $ 28,303 $ 3,775 $ 5,836 $ 3,524 $ 15,168
- -------------------------------------------------------------------------------------------------------------------
a. The Company's maturing debt obligations are generally expected to be
refinanced with new debt issuances in the capital markets. However, the
Company does plan to annually reduce its debt to total capitalization
leverage by one to two percentage points over the next few years through
selected asset sales, free cash flow and increased equity from retained
earnings and ongoing equity issuances.
b. Interest payments on long-term debt and interest rate derivatives are based
on the interest rate effective as of December 31, 2004, and the LIBOR
forward curve as of December 31, 2004, respectively.
c. Fuel and purchased power commitments represent the majority of the
Company's remaining future commitments after its debt obligations.
Essentially all of the Company's fuel and purchased power costs are
recovered through pass-through clauses in accordance with North Carolina,
South Carolina and Florida regulations and therefore do not require
separate liquidity support.
d. In 2008, PEC must begin transitioning amounts currently retained internally
to its external decommissioning funds. The transition of $131 million must
be complete by December 31, 2017, and at least 10% must be transitioned
each year.
e. The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties)
through 2007 (See Note 23B).
OTHER MATTERS
Synthetic Fuels Tax Credits
The Company has substantial operations associated with the production of
coal-based synthetic fuels. The production and sale of these products qualifies
for federal income tax credits so long as certain requirements are satisfied.
These operations are subject to numerous risks.
Although the Company believes that it operates its synthetic fuel facilities in
compliance with applicable legal requirements for claiming the credits, its four
Earthco facilities are under audit by the IRS. IRS field auditors have taken an
adverse position with respect to the Company's compliance with one of these
legal requirements, and if the Company fails to prevail with respect to this
position, it could incur significant liability and/or lose the ability to claim
the benefit of tax credits carried forward or generated in the future.
Similarly, the Financial Accounting Standards Board may issue new accounting
rules that would require that uncertain tax benefits (such as those associated
with the Earthco plants) be probable of being sustained in order to be recorded
on the financial statements; if adopted, this provision could have an adverse
financial impact on the Company.
The Company's ability to utilize tax credits is dependent on having sufficient
tax liability. Any conditions that negatively impact the Company's tax
liability, such as weather, could also diminish the Company's ability to utilize
credits, including those previously generated, and the synthetic fuel is
generally not economical to produce absent the credits. Finally, the tax credits
associated with synthetic fuels may be phased out if market prices for crude oil
exceed certain prices.
The Company's synthetic fuel operations and related risks are described in more
detail in Note 23E and in the "Risk Factors" section.
69
Hurricane Costs
Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of the
Company's service territories during the third quarter of 2004, significantly
impacting PEF's territory. As of December 31, 2004, restoration of the Company's
systems from hurricane-related damage was estimated at $398 million. PEC
incurred restoration costs of $13 million, of which $12 million was charged to
operation and maintenance expense and $1 million was charged to capital
expenditures. PEF had estimated total costs of $385 million, of which $47
million was charged to capital expenditures, and $338 million was charged to the
storm damage reserve pursuant to a regulatory order.
In accordance with a regulatory order, PEF accrues $6 million annually to a
storm damage reserve and is allowed to defer losses in excess of the accumulated
reserve for major storms. Under the order, the storm reserve is charged with
operation and maintenance expenses related to storm restoration and with capital
expenditures related to storm restoration that are in excess of expenditures
assuming normal operating conditions. As of December 31, 2004, $291 million of
hurricane restoration costs in excess of the previously recorded storm reserve
of $47 million had been classified as a regulatory asset recognizing the
probable recoverability of these costs. On November 2, 2004, PEF filed a
petition with the FPSC to recover $252 million of storm costs plus interest from
retail ratepayers over a two-year period. Storm reserve costs of $13 million
were attributable to wholesale customers. The Company has received approval from
the FERC to amortize these costs consistent with recovery of such amounts in
wholesale rates. PEF continues to review the restoration cost invoices received.
Given that not all invoices have been received as of December 31, 2004, PEF will
update its petition with the FPSC upon receipt and audit of all actual charges
incurred. Hearings on PEF's petition for recovery of $252 million of storm costs
filed with the FPSC are scheduled to begin on March 30, 2005.
On November 17, 2004, the Citizens of the State of Florida, by and through
Harold McLean, Public Counsel, and the Florida Industrial Power Users Group
(FIPUG), (collectively, Joint Movants), filed a Motion to Dismiss PEF's petition
to recover the $252 million in storm costs. On November 24, 2004, PEF responded
in opposition to the motion, which was also the FPSC staff's position in its
recommendation to the Commission on December 21, 2004, that it should deny the
Motion to Dismiss. On January 4, 2005, the Commission ruled in favor of PEF and
denied the Joint Movant's Motion to Dismiss.
PEF's January 2005 notice to the FPSC of its intent to file for an increase in
its base rates effective January 1, 2006, anticipates the need to replenish the
depleted storm reserve balance and adjust the annual $6 million accrual in light
of recent storm history to restore the reserve to an adequate level over a
reasonable time period.
PEC does not have an ongoing regulatory mechanism to recover storm costs;
therefore, hurricane restoration costs recorded in the third quarter of 2004
were charged to operations and maintenance expenses or capital expenditures
based on the nature of the work performed. In connection with other storms, PEC
has previously sought and received permission from the NCUC and the SCPSC to
defer storm expenses and amortize them over a five-year period. PEC did not seek
deferral of 2004 storm costs from the NCUC (See Note 8B).
Regulatory Environment and Matters
The Company's electric utility operations in North Carolina, South Carolina and
Florida are regulated by the NCUC, the Public Service Commission of South
Carolina (SCPSC) and the FPSC, respectively. The electric businesses are also
subject to regulation by the FERC, the NRC and other federal and state agencies
common to the utility business. In addition, the Company is subject to SEC
regulation as a registered holding company under PUHCA. As a result of
regulation, many of the fundamental business decisions, as well as the rate of
return the electric utilities are permitted to earn, are subject to the approval
of governmental agencies.
PEC and PEF continue to monitor any developments toward a more competitive
environment and have actively participated in regulatory reform deliberations in
North Carolina, South Carolina and Florida. Movement toward deregulation in
these states has been affected by recent developments, including developments
related to deregulation of the electric industry in other states. The Company
expects the legislatures in all three states will continue to monitor the
experiences of states that have implemented electric restructuring legislation.
The Company cannot anticipate when, or if, any of these states will move to
increase competition in the electric industry.
The retail rate matters affected by the regulatory authorities are discussed in
detail in Notes 8B and 8C. This discussion identifies specific retail rate
matters, the status of the issues and the associated effects to the Company's
consolidated financial statements.
70
The regulatory authorities continue to evaluate issues related to the formation
of Regional Transmission Organizations. The Company cannot predict the outcome
of these matters on the Company's earnings, revenues or prices or the
investments in GridSouth and GridFlorida (See Note 8D).
A FERC order issued in November 2001 on certain unaffiliated utilities'
triennial market-based wholesale power rate authorization updates required
certain mitigation actions that those utilities would need to take for
sales/purchases within their control areas and required those utilities to post
information on their Web sites regarding their power systems' status. As a
result of a request for rehearing filed by certain market participants, FERC
issued an order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December 2003,
the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. In April 2004, the FERC issued two orders concerning
utilities' ability to sell wholesale electricity at market-based rates. In the
first order, the FERC adopted two new interim screens for assessing potential
generation market power of applicants for wholesale market-based rates, and
described additional analyses and mitigation measures that could be presented if
an applicant does not pass one of these interim screens. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order. In
the second order, the FERC initiated a rulemaking to consider whether the FERC's
current methodology for determining whether a public utility should be allowed
to sell wholesale electricity at market-based rates should be modified in any
way. PEF does not have market-based rate authority for wholesale sales in
peninsular Florida. Given the difficulty PEC believes it would experience in
passing one of the interim screens, on August 12, 2004, PEC notified the FERC
that it would revise its Market-based Rate tariff to restrict it to sales
outside PEC's control area and file a new cost-based tariff for sales within
PEC's control area that incorporates the FERC's default cost-based rate
methodologies for sales of one year or less. PEC anticipates making this filing
in the first quarter of 2005. Although the Company cannot predict the ultimate
outcome of these changes, the Company does not anticipate that the current
operations of PEC or PEF would be impacted materially if they were unable to
sell power at market-based rates in their respective control areas.
Franchise Litigation
Three cities, with a total of approximately 18,000 customers, have litigation
pending against PEF in various circuit courts in Florida. As previously
reported, three other cities, with a total of approximately 30,000 customers,
have subsequently settled their lawsuits with PEF and signed new, 30-year
franchise agreements. The lawsuits principally seek (1) a declaratory judgment
that the cities have the right to purchase PEF's electric distribution system
located within the municipal boundaries of the cities, (2) a declaratory
judgment that the value of the distribution system must be determined through
arbitration, and (3) injunctive relief requiring PEF to continue to collect from
PEF's customers, and remit to the cities, franchise fees during the pending
litigation, and as long as PEF continues to occupy the cities' rights-of-way to
provide electric service, notwithstanding the expiration of the franchise
ordinances under which PEF had agreed to collect such fees. The circuit courts
in those cases have entered orders requiring arbitration to establish the
purchase price of PEF's electric distribution system within five cities. Two
appellate courts have upheld those circuit court decisions and authorized the
cities to determine the value of PEF's electric distribution system within the
cities through arbitration.
Arbitration in one of the cases (with the 13,000-customer City of Winter Park)
was completed in February 2003. That arbitration panel issued an award in May
2003 setting the value of PEF's distribution system within the City of Winter
Park (the City) at approximately $32 million, not including separation and
reintegration and construction work in progress, which could add several million
dollars to the award. The panel also awarded PEF approximately $11 million in
stranded costs, which, according to the award, decrease over time. In September
2003, Winter Park voters passed a referendum that would authorize the City to
issue bonds of up to approximately $50 million to acquire PEF's electric
distribution system. While the City has not yet definitively decided whether it
will acquire the system, on April 26, 2004, the City Commission voted to proceed
with the acquisition. The City sought and received wholesale power supply bids
and on June 24, 2004, executed a wholesale power supply contract with PEF. On
May 12, 2004, the City solicited bids to operate and maintain the distribution
system and awarded a contract in January 2005. The City has indicated that its
goal is to begin electric operations in June 2005. On February 10, 2005, PEF
filed a petition with the Florida Public Service Commission to relieve the
Company of its statutory obligation to serve customers in Winter Park on June 1,
2005, or at such time when the City is able to provide retail service. At this
time, whether and when there will be further proceedings regarding the City of
Winter Park cannot be determined.
Arbitration with the 2,500-customer Town of Belleair was completed in June 2003.
In September 2003, the arbitration panel issued an award in that case setting
the value of the electric distribution system within the Town at approximately
$6 million. The panel further required the Town to pay to PEF its requested $1
million in separation and reintegration costs and $2 million in stranded costs.
71
The Town has not yet decided whether it will attempt to acquire the system;
however, on January 18, 2005, it issued a request for proposals for wholesale
power supply and to operate and maintain the distribution system. Proposals are
due in early March 2005. In February 2005, the Town Commission also voted to put
the issue of whether to acquire the distribution system to a voter referendum on
or before October 2, 2005. At this time, whether and when there will be further
proceedings regarding the Town of Belleair cannot be determined.
Arbitration in the remaining city's litigation (the 1,500-customer City of
Edgewood) has not yet been scheduled. On February 17, 2005, the parties filed a
joint motion to stay the litigation for a 90-day period during which the parties
will discuss potential settlement.
A fourth city (the 7,000-customer City of Maitland) is contemplating
municipalization and has indicated its intent to proceed with arbitration to
determine the value of PEF's electric distribution system within the City.
Maitland's franchise expires in August 2005. At this time, whether and when
there will be further proceedings regarding the City of Maitland cannot be
determined.
As part of the above litigation, two appellate courts reached opposite
conclusions regarding whether PEF must continue to collect from its customers
and remit to the cities "franchise fees" under the expired franchise ordinances.
PEF filed an appeal with the Florida Supreme Court to resolve the conflict
between the two appellate courts. On October 28, 2004, the Court issued a
decision holding that PEF must collect from its customers and remit to the
cities franchise fees during the interim period when the city exercises its
purchase option or executes a new franchise. The Court's decision should not
have a material impact on the Company.
Legal
The Company is subject to federal, state and local legislation and court orders.
These matters are discussed in detail in Note 23E. This discussion identifies
specific issues, the status of the issues, accruals associated with issue
resolutions and the associated exposures to the Company.
Nuclear
Nuclear generating units are regulated by the NRC. In the event of
noncompliance, the NRC has the authority to impose fines, set license
conditions, shut down a nuclear unit or some combination of these, depending
upon its assessment of the severity of the situation, until compliance is
achieved. The nuclear units are periodically removed from service to accommodate
normal refueling and maintenance outages, repairs and certain other
modifications (See Notes 6 and 23E).
Environmental Matters
The Company is subject to federal, state and local regulations addressing air
and water quality, hazardous and solid waste management and other environmental
matters. These environmental matters are discussed in detail in Note 22. This
discussion identifies specific environmental issues, the status of the issues,
accruals associated with issue resolutions and the associated exposures to the
Company. The Company accrues costs to the extent they are probable and can be
reasonably estimated. It is reasonably possible that additional losses, which
could be material, may be incurred in the future.
New Accounting Standards
See Note 2 for a discussion of the impact of new accounting standards.
PEC
The information required by this item is incorporated herein by reference to the
following portions of Progress Energy's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate to PEC:
RESULTS OF OPERATIONS; LIQUIDITY AND CAPITAL RESOURCES; FUTURE OUTLOOK and OTHER
MATTERS.
The following Management's Discussion and Analysis and the information
incorporated herein by reference contain forward-looking statements that involve
estimates, projections, goals, forecasts, assumptions, risks and uncertainties
that could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. Please review "Risk Factors" and
"SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS" for a discussion of the factors
that may impact any such forward-looking statements made herein.
72
RESULTS OF OPERATIONS
The results of operations for the PEC consolidated for the years ended December
31 are summarized in the table below. The results of operations for the PEC
Electric segment are identical in all material respects between PEC and Progress
Energy for all periods presented. The primary difference between the results of
operations of the PEC Electric segment and the consolidated PEC results of
operations relate to the nonelectric operations, as summarized below:
- --------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- --------------------------------------------------------------------------------
PEC Electric income before cumulative effect $ 464 $ 515 $ 513
Caronet net income (loss) - 5 (79)
Other nonelectric net loss (6) (18) (6)
Cumulative effect of accounting change - (23) -
- --------------------------------------------------------------------------------
Earnings for common stock $ 458 $ 479 $ 428
- --------------------------------------------------------------------------------
Caronet's results of operations for 2002 includes after-tax impairments of $87
million for other-than-temporary declines in the value of the assets of Caronet
and Caronet's investment in Interpath (See Note 7A to the PEC Consolidated
Financial Statements). The stock of Caronet was sold in December 2003 (See Note
1A to the PEC Consolidated Financial Statements).
The other nonelectric subsidiaries of PEC contributed segment losses of $6
million and $18 million for the years ended December 31, 2004 and 2003,
respectively. The Other nonelectric results for 2003 include investment
impairments of $6 million after-tax on the Affordable Housing portfolio held by
the nonutility subsidiaries of PEC. (See Note 7B to the PEC Consolidated
Financial Statements.) A reduction in investment losses accounted for the
remaining favorability compared to prior year.
In 2003, PEC Electric recorded cumulative effects of changes in accounting
principles due to the adoption of a new accounting pronouncement. This
adjustment totaled to a $23 million loss due primarily to the new FASB guidance
related to the accounting for the purchase power contract with Broad River LLC
(See Note 13A to the PEC Consolidated Financial Statements).
Note 1D to the PEC Consolidated Financial Statements discusses its significant
accounting policies. The most critical accounting policies and estimates that
impact PEC's consolidated financial statements are the economic impacts of
utility regulation and asset impairment policies, described in more detail in
the Progress Energy Management's Discussion and Analysis section.
LIQUIDITY AND CAPITAL RESOURCES
Overview
PEC has primarily used a combination of unsecured notes, first mortgage bonds,
pollution control bonds, commercial paper facilities and revolving credit
agreements for liquidity needs in excess of cash provided by operations.
During 2004, PEC extended its $165 million 364-day line of credit to July 27,
2005 and PEC's three-year $285 million line of credit expires July 31, 2005.
As discussed above in the Progress Energy "Overview," in October 2004, S&P
reduced the short-term debt rating of PEC to A-3 from A-2. As a result of the
impact of these actions on PEC's ability to access the commercial paper markets,
PEC has borrowed on its revolving credit agreements. As of December 31, 2004,
the total amount of outstanding borrowings on PEC's revolving credit agreements
was $90 million. The borrowed funds were used to pay off maturing commercial
paper and for other cash needs.
The changes by S&P do not trigger any debt or guarantee collateral requirements,
nor do they have any material impact on the overall liquidity of PEC. To date,
PEC's access to the commercial paper markets has not been materially impacted by
the rating agencies' actions. However, the changes have increased the interest
rate incurred on its short-term borrowings by 0.25% to 0.875%.
73
PEC expects to have sufficient resources to meet its future obligations either
through internally generated funds, its short term-term borrowing facilities or
through the issuance of long-term debt.
HISTORICAL FOR 2004 AS COMPARED TO 2003 AND 2003 AS COMPARED TO 2002
In 2004, cash provided by operating activities decreased when compared to 2003.
The decrease was caused primarily by a $89 million under-recovery of fuel costs
and a $76 million decrease in payables to affiliates. In 2003, cash provided by
operating activities increased when compared to 2002, largely as a result of
improved operating results.
In 2004, cash used in investing activities decreased approximately $257 million
in 2004 when compared with 2003. The decrease is primarily to net proceeds from
short-term investments in 2004, compared to net purchases in 2003. The decrease
is partially offset by an increase in capital expenditures, primarily related to
increased spending for NC Clean Air legislation, and an increase in nuclear fuel
additions.
See the discussion above for Progress Energy under "Financing Activities" for
information regarding PEC's financing activities.
FUTURE LIQUIDITY AND CAPITAL RESOURCES
PEC's estimated capital requirements for 2005, 2006 and 2007 are $650 million,
$670 million and $680 million, respectively, and primarily reflect construction
expenditures to support customer growth, add regulated generation and upgrade
existing facilities. See Note 6E to the PEC Consolidated Financial Statements
for a discussion of expected impacts on future capital expenditures due to
changes in capitalization practice for PEC. PEC expects to fund its capital
requirements primarily through internally generated funds. In addition, PEC has
$450 million in credit facilities that support the issuance of commercial paper.
Access to the commercial paper market and the utility money pool provide
additional liquidity to help meet PEC's working capital requirements. PEC plans
to enter into a new five-year line of credit in 2005 that will replace these two
expiring facilities.
See Note 9 to the PEC Consolidated Financial Statements for information on PEC's
available credit facilities at December 31, 2004.
OFF-BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
PEC's off-balance sheet arrangements and contractual obligations are described
below.
Market Risk and Derivatives
Under its risk management policy, PEC may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. See Note 13 and Item 7A,
"Quantitative and Qualitative Disclosures About Market Risk," for a discussion
of market risk and derivatives.
Contractual Obligations
PEC is party to numerous contracts and arrangements obligating it to make cash
payments in future years. These contracts include financial arrangements such as
debt agreements and leases, as well as contracts for the purchase of goods and
services. Amounts in the following table are estimated based upon contractual
terms and will likely differ from amounts presented below. Further disclosure
regarding PEC's contractual obligations is included in the respective notes to
the PEC Consolidated Financial Statements. PEC takes into consideration the
future commitments when assessing its liquidity and future financing needs. The
following table reflects Progress Energy's contractual cash obligations and
other commercial commitments at December 31, 2004, in the respective periods in
which they are due:
74
- --------------------------------------------------------------------------------------------------------
Less than More than
(in millions) Total 1 year 1-3 years 3-5 years 5 years
- --------------------------------------------------------------------------------------------------------
Long-term debt (a) (See Note 9) $ 3,069 $ 300 $ 200 $ 700 $ 1,869
Interest payments on long-term debt
and interest rate derivatives (b) 1,342 150 285 207 700
Capital lease obligations (See Note 18B) 35 2 4 4 25
Operating leases (See Note 18B) 187 28 37 25 97
Fuel and purchased power (c) (See Note 18A) 3,427 786 1,098 431 1,112
Other purchase obligations (See Note 18A) 25 12 - - 13
North Carolina clean air capital commitments
(See Note 17) 764 170 297 143 154
Other commitments (d) 131 - - 26 105
- --------------------------------------------------------------------------------------------------------
Total $ 8,980 $ 1,448 $ 1,921 $ 1,536 $ 4,075
- --------------------------------------------------------------------------------------------------------
a. The Company's maturing debt obligations are generally expected to be
refinanced with new debt issuances in the capital markets. However, the
Company does plan to annually reduce its debt to total capitalization
leverage by one to two percentage points over the next few years through
selected asset sales, free cash flow and increased equity from retained
earnings and ongoing equity issuances.
b. Interest payments on long-term debt and interest rate derivatives are based
on the interest rate effective as of December 31, 2004, and the LIBOR
forward curve as of December 31, 2004, respectively.
c. Fuel and purchased power commitments represent the majority of the
Company's remaining future commitments after its debt obligations.
Essentially all of the Company's fuel and purchased power costs are
recovered through pass-through clauses in accordance with North Carolina,
South Carolina and Florida regulations and therefore do not require
separate liquidity support.
d. In 2008, PEC must begin transitioning amounts currently retained internally
to its external decommissioning funds. The transition of $131 million must
be complete by December 31, 2017, and at least 10% must be transitioned
each year.
75
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Progress Energy, Inc.
Market risk represents the potential loss arising from adverse changes in market
rates and prices. Certain market risks are inherent in the Company's financial
instruments, which arise from transactions entered into in the normal course of
business. The Company's primary exposures are changes in interest rates with
respect to its long-term debt and commercial paper, and fluctuations in the
return on marketable securities with respect to its nuclear decommissioning
trust funds. The Company manages its market risk in accordance with its
established risk management policies, which may include entering into various
derivative transactions.
These financial instruments are held for purposes other than trading. The risks
discussed below do not include the price risks associated with nonfinancial
instrument transactions and positions associated with the Company's operations,
such as purchase and sales commitments and inventory.
Interest Rate Risk
The Company manages its interest rate risks through the use of a combination of
fixed and variable rate debt. Variable rate debt has rates that adjust in
periods ranging from daily to monthly. Interest rate derivative instruments may
be used to adjust interest rate exposures and to protect against adverse
movements in rates.
The following tables provide information at December 31, 2004 and 2003, about
the Company's interest rate risk-sensitive instruments. The tables present
principal cash flows and weighted-average interest rates by expected maturity
dates for the fixed and variable rate long-term debt and FPC obligated
mandatorily redeemable securities of trust. The tables also include estimates of
the fair value of the Company's interest rate risk-sensitive instruments based
on quoted market prices for these or similar issues. For interest rate swaps and
interest rate forward contracts, the tables present notional amounts and
weighted-average interest rates by contractual maturity dates for 2005-2009 and
thereafter and the fair value of the related hedges. Notional amounts are used
to calculate the contractual cash flows to be exchanged under the interest rate
swaps and the settlement amounts under the interest rate forward contracts. See
Note 18 for more information on interest rate derivatives.
- -----------------------------------------------------------------------------------------------------------------------
December 31, 2004 Fair Value
December 31,
(dollars in millions) 2005 2006 2007 2008 2009 Thereafter Total 2004
- -----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 349 $ 908 $ 674 $ 827 $ 400 $ 5,399 $ 8,557 $ 9,454
Average interest rate 7.38% 6.78% 6.41% 6.27% 5.95% 6.55% 6.54%
Variable rate long-term debt - $ 55 - - $ 160 $ 861 $ 1,076 $ 1,077
Average interest rate - 2.95% - - 3.19% 1.70% 1.99%
Debt to affiliated trust(a) - - - - - $ 309 $ 309 $ 312
Interest rate - - - - - 7.10% 7.10%
Interest rate derivatives:
Pay variable /receive
fixed - - - $(100) - $ (50) $ (150) $ 3
Average pay rate - - - (b) - (b) (b)
Average receive rate - - - 4.10% - 4.65% 4.28%
Interest rate forward
contracts $ 200 - - - - $ 131 $ 331 $ (2)
Average pay rate 3.07% - - - - 4.90% 3.79%
Average receive rate (c) - - - - (b) (b)(c)
- -----------------------------------------------------------------------------------------------------------------------
(a) FPC Capital I - Quarterly Income Preferred Securities.
(b) Rate is 3-month LIBOR, which was 2.56% at December 31, 2004.
(c) Rate is 1-month LIBOR, which was 2.40% at December 31, 2004.
76
- -----------------------------------------------------------------------------------------------------------------------
December 31, 2003 Fair Value
December 31,
(dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003
- -----------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 868 $ 349 $ 909 $ 674 $ 827 $ 5,836 $ 9,463 $ 10,501
Average interest rate 6.67% 7.38% 6.78% 6.41% 6.27% 6.51% 6.55%
Variable rate long-term debt - - - $ 241 - $ 861 $ 1,102 $ 1,103
Average interest rate - - - 3.04% - 1.08% 1.51%
Debt to affiliated trust(a) - - - - - $ 309 $ 309 $ 313
Interest rate - - - - - 7.10% 7.10%
Interest rate derivatives:
Pay variable/receive
fixed - - $(300) $ (350) $ (200) - $ (850) $ (4)
Average pay rate (b) (b) (b) (b)
Average receive rate 2.75% 3.35% 2.93% 3.04%
Payer swaptions - - - - $ 400 - $ 400 $ 5
Average pay rate 4.75%
Average receive rate (b)
Interest rate collars(c) $ 65 - - $ 130 - - $ 195 $ (11)
Cap rate 6.00% 6.50%
Floor rate 4.13% 5.13%
- -----------------------------------------------------------------------------------------------------------------------
(a) FPC Capital I - Quarterly Income Preferred Securities.
(b) Rate is 3-month LIBOR, which was 1.15% at December 31, 2003.
(c) Notional amount is varying with a maximum of $195 million, decreasing to
$130 million after December 2004.
Marketable Securities Price Risk
The Company's electric utility subsidiaries maintain trust funds, pursuant to
NRC requirements, to fund certain costs of decommissioning their nuclear plants.
These funds are primarily invested in stocks, bonds and cash equivalents, which
are exposed to price fluctuations in equity markets and to changes in interest
rates. The fair value of these funds was $1.044 billion and $938 million at
December 31, 2004 and 2003, respectively. The Company actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, target allocation
percentages for various asset classes. The accounting for nuclear
decommissioning recognizes that the Company's regulated electric rates provide
for recovery of these costs net of any trust fund earnings, and, therefore,
fluctuations in trust fund marketable security returns do not affect the
earnings of the Company.
Contingent Value Obligations Market Value Risk
In connection with the acquisition of FPC, the Company issued 98.6 million CVOs.
Each CVO represents the right to receive contingent payments based on the
performance of four synthetic fuel facilities purchased by subsidiaries of FPC
in October 1999. The payments, if any, are based on the net after-tax cash flows
the facilities generate. These CVOs are recorded at fair value, and unrealized
gains and losses from changes in fair value are recognized in earnings. At
December 31, 2004 and 2003, the fair value of these CVOs was $13 million and $23
million, respectively. A hypothetical 10% decrease in the December 31, 2004,
market price would result in a $1 million decrease in the fair value of the
CVOs.
Commodity Price Risk
The Company is exposed to the effects of market fluctuations in the price of
natural gas, coal, fuel oil, electricity and other energy-related products
marketed and purchased as a result of its ownership of energy-related assets.
The Company's exposure to these fluctuations is significantly limited by the
cost-based regulation of PEC and PEF. Each state commission allows electric
utilities to recover certain of these costs through various cost recovery
clauses to the extent the respective commission determines that such costs are
prudent. Therefore, while there may be a delay in the timing between when these
costs are incurred and when these costs are recovered from the ratepayers,
changes from year to year have no material impact on operating results. In
addition, many of the Company's long-term power sales contracts shift
substantially all fuel responsibility to the purchaser. The Company also has oil
price risk exposure related to synfuel tax credits. See discussion in Note 23E.
77
The Company uses natural gas hedging instruments to manage a portion of the
market risk associated with fluctuations in the future sales price of the
Company's natural gas. In addition, the Company may engage in limited economic
hedging activity using natural gas and electricity financial instruments.
In 2004, PEF entered into derivative instruments related to its exposure to
price fluctuations on fuel oil purchases. At December 31, 2004, the fair values
of these instruments were a $2 million long-term derivative asset position
included in other assets and deferred debits and a $5 million short-term
derivative liability position included in other current liabilities. These
instruments receive regulatory accounting treatment. Gains are recorded in
regulatory liabilities and losses are recorded in regulatory assets.
Refer to Note 18 for additional information with regard to the Company's
commodity contracts and use of derivative financial instruments.
The Company performs sensitivity analyses to estimate its exposure to the market
risk of its commodity positions. A hypothetical 10% increase or decrease in
quoted market prices in the near term on the Company's derivative commodity
instruments would not have had a material effect on the Company's consolidated
financial position, results of operations or cash flows as of December 31, 2004.
PEC
PEC has certain market risks inherent in its financial instruments, which arise
from transactions entered into in the normal course of business. PEC's primary
exposures are changes in interest rates, with respect to long-term debt and
commercial paper, and fluctuations in the return on marketable securities, with
respect to its nuclear decommissioning trust funds.
The information required by this item is incorporated herein by reference to the
Quantitative and Qualitative Disclosures About Market Risk insofar as it relates
to PEC.
Interest Rate Risk
The following tables provide information at about PEC's interest rate risk
sensitive instruments:
- ---------------------------------------------------------------------------------------------------------------------------
December 31, 2004 Fair Value
December 31,
(dollars in millions) 2005 2006 2007 2008 2009 Thereafter Total 2004
- ---------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 300 - $ 200 $ 300 $ 400 $ 1,249 $ 2,449 $ 2,686
Average interest rate 7.50% - 6.80% 6.65% 5.95% 6.13% 6.38%
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - 1.71% 1.71%
Interest rate forward contracts - - - - - $ 131 $ 131 $ (2)
Average pay rate 4.90% 4.90%
Average receive rate (a) (a)
- ---------------------------------------------------------------------------------------------------------------------------
(a) Rate is 3-month LIBOR, which was 2.56% at December 31, 2004
- --------------------------------------------------------------------------------------------------------------------------
December 31, 2003 Fair Value
December 31,
(dollars in millions) 2004 2005 2006 2007 2008 Thereafter Total 2003
- --------------------------------------------------------------------------------------------------------------------------
Fixed rate long-term debt $ 300 $ 300 - $ 200 $ 300 $ 1,688 $ 2,788 $ 3,065
Average interest rate 6.9% 7.50% - 6.80% 6.65% 6.09% 6.44%
Variable rate long-term debt - - - - - $ 620 $ 620 $ 621
Average interest rate - - - - - - 1.09%
- --------------------------------------------------------------------------------------------------------------------------
78
Commodity Price Risk
PEC is exposed to the effects of market fluctuations in the price of natural
gas, coal, fuel oil, electricity and other energy-related products marketed and
purchased as a result of its ownership of energy-related assets. PEC's exposure
to these fluctuations is significantly limited by cost-based regulation. Each
state commission allows electric utilities to recover certain of these costs
through various cost recovery clauses to the extent the respective commission
determines that such costs are prudent. Therefore, while there may be a delay in
the timing between when these costs are incurred and when these costs are
recovered from the ratepayers, changes from year to year have no material impact
on operating results. PEC may engage in limited economic hedging activity using
natural gas and electricity financial instruments. Refer to Note 13 to the PEC
Consolidated Financial Statements for additional information with regard to
PEC's commodity contracts and use of derivative financial instruments.
PEC performs sensitivity analyses to estimate its exposure to the market risk of
its commodity positions. A hypothetical 10% increase or decrease in quoted
market prices in the near term on its derivative commodity instruments would not
have had a material effect on PEC's consolidated financial position, results of
operations or cash flows as of December 31, 2004.
79
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.
Reports of Independent Registered Public Accounting Firm
Consolidated Financial Statements - Progress Energy, Inc.:
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 83
Consolidated Balance Sheets at December 31, 2004 and 2003 84-85
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 86
Consolidated Statements of Changes in Common Stock Equity for the Years Ended December 31, 2004,
2003 and 2002 87
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
2003 and 2002 87
Notes to the Consolidated Financial Statements
Note 1 - Organization and Summary of Significant Accounting Policies 88
Note 2 - New Accounting Standards 94
Note 3 - Hurricane Related Costs 95
Note 4 - Divestitures 95
Note 5 - Acquisitions and Business Combinations 97
Note 6 - Property, Plant and Equipment 99
Note 7 - Current Assets 103
Note 8 - Regulatory Matters 103
Note 9 - Goodwill and Other Intangible Assets 108
Note 10 - Impairments of Long-Lived Assets and Investments 109
Note 11 - Equity 109
Note 12 - Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 113
Note 13 - Debt and Credit Facilities 113
Note 14 - Fair Value of Financial Instruments 117
Note 15 - Income Taxes 117
Note 16 - Contingent Value Obligations 119
Note 17 - Benefit Plans 119
Note 18 - Risk Management Activities and Derivatives Transactions 123
Note 19 - Related Party Transactions 125
Note 20 - Financial Information by Business Segment 126
Note 21 - Other Income and Other Expense 128
Note 22 - Environmental Matters 128
Note 23 - Commitments and Contingencies 133
Note 24 - Subsequent Events 141
Note 25 - Consolidated Quarterly Financial Data (Unaudited) 142
80
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc.
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements - Carolina Power & Light Company d/b/a
Progress Energy Carolinas, Inc.:
Consolidated Statements of Income for the Years Ended December 31, 2004, 2003 and 2002 144
Consolidated Balance Sheets at December 31, 2004 and 2003 145
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003
and 2002 146
Consolidated Statements of Retained Earnings for the Years Ended December 31, 2004, 2003
and 2002 147
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2004,
2003 and 2002 147
Notes to the Consolidated Financial Statements
Note 1 - Organization and Summary of Significant Accounting Policies 148
Note 2 - New Accounting Standards 153
Note 3 - Hurricane Related Costs 154
Note 4 - Property, Plant and Equipment 154
Note 5 - Current Assets 157
Note 6 - Regulatory Matters 157
Note 7 - Impairments of Long-Lived Assets and Investments 160
Note 8 - Equity 160
Note 9 - Debt and Credit Facilities 162
Note 10 - Fair Value of Financial Instruments 164
Note 11 - Income Taxes 164
Note 12 - Benefit Plans 166
Note 13 - Risk Management Activities and Derivatives Transactions 169
Note 14 - Related Party Transactions 170
Note 15 - Financial Information by Business Segment 171
Note 16 - Other Income and Other Expense 172
Note 17 - Environmental Matters 172
Note 18 - Commitments and Contingencies 175
Note 19 - Subsequent Event 179
Note 20 - Consolidated Quarterly Financial Data (Unaudited) 179
Report of Independent Registered Public Accounting Firm on Consolidated Financial
Statement Schedule - Progress Energy, Inc. 180
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. 181
Consolidated Financial Statement Schedules for the Years Ended December 31, 2004, 2003 and 2002:
II-Valuation and Qualifying Accounts - Progress Energy, Inc. 182
II-Valuation and Qualifying Accounts - Carolina Power & Light Company
d/b/a Progress Energy Carolinas, Inc. 183
All other schedules have been omitted as not applicable or not required or
because the information required to be shown is included in the Consolidated
Financial Statements or the Notes to the Consolidated Financial Statements.
81
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited the accompanying consolidated balance sheets of Progress Energy,
Inc., and its subsidiaries (the Company) at December 31, 2004 and 2003, and the
related consolidated statements of income, comprehensive income, changes in
common stock equity, and cash flows for each of the three years in the period
ended December 31, 2004. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of the Company at December 31, 2004
and 2003, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2004, in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Notes 1D and 18A to the consolidated financial statements, in
2003, the Company adopted Statement of Financial Accounting Standards No. 143
and Derivatives Implementation Group Issue C20.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, based on the
criteria established in Internal Control--Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission, and our report
dated March 7, 2005, expressed an unqualified opinion on management's assessment
of the effectiveness of the Company's internal control over financial reporting
and an unqualified opinion on the effectiveness of the Company's internal
control over financial reporting.
Deloitte & Touche LLP
82
Raleigh, North Carolina
March 7, 2005
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of INCOME
- -----------------------------------------------------------------------------------------------------
(in millions except per share data)
Years ended December 31 2004 2003 2002
- -----------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 7,153 $ 6,741 $ 6,601
Diversified business 2,619 2,000 1,490
- -----------------------------------------------------------------------------------------------------
Total Operating Revenues 9,772 8,741 8,091
- -----------------------------------------------------------------------------------------------------
Operating Expenses
Utility
Fuel used in electric generation 2,011 1,695 1,586
Purchased power 868 862 862
Operation and maintenance 1,475 1,421 1,390
Depreciation and amortization 878 883 820
Taxes other than on income 425 405 386
Diversified business
Cost of sales 2,288 1,748 1,410
Depreciation and amortization 190 157 118
Impairment of long-lived assets - 17 364
(Gain)/loss on the sale of assets (57) 1 -
Other 218 195 145
- -----------------------------------------------------------------------------------------------------
Total Operating Expenses 8,296 7,384 7,081
- -----------------------------------------------------------------------------------------------------
Operating Income 1,476 1,357 1,010
- -----------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 14 11 15
Impairment of investments - (21) (25)
Other, net 8 (16) 27
- -----------------------------------------------------------------------------------------------------
Total Other Income (Expense) 22 (26) 17
- -----------------------------------------------------------------------------------------------------
Interest Charges
Net interest charges 653 635 641
Allowance for borrowed funds used during construction (6) (7) (8)
- -----------------------------------------------------------------------------------------------------
Total Interest Charges, Net 647 628 633
- -----------------------------------------------------------------------------------------------------
Income from Continuing Operations before Income Tax, Minority
Interest, and Cumulative Effect of Changes in Accounting
Principles 851 703 394
Income Tax Expense (Benefit) 115 (111) (158)
- -----------------------------------------------------------------------------------------------------
Income from Continuing Operations before Minority Interest and
Cumulative Effect of Changes in Accounting Principles 736 814 552
Minority Interest, Net of Tax (17) 3 -
- -----------------------------------------------------------------------------------------------------
Income from Continuing Operations Before Cumulative Effect of 753 811 552
Change in Accounting Principles
Discontinued Operations, Net of Tax 6 (8) (24)
Cumulative Effect of Changes in Accounting Principles,
Net of Tax - (21) -
- -----------------------------------------------------------------------------------------------------
Net Income $ 759 $ 782 $ 528
- -----------------------------------------------------------------------------------------------------
Average Common Shares Outstanding 242 237 217
- -----------------------------------------------------------------------------------------------------
Basic Earnings per Common Share
Income from Continuing Operations before Cumulative Effect of
Changes in Accounting Principles $ 3.11 $ 3.42 $ 2.54
Discontinued Operations, Net of Tax .02 (.03) (.11)
Cumulative Effect of Changes in Accounting Principles,
Net of Tax - (.09) -
- -----------------------------------------------------------------------------------------------------
Net Income $ 3.13 $ 3.30 $ 2.43
- -----------------------------------------------------------------------------------------------------
Diluted Earnings per Common Share
Income from Continuing Operations before Cumulative Effect of
Changes in Accounting Principles $ 3.10 $ 3.40 $ 2.53
Discontinued Operations, Net of Tax .02 (.03) (.11)
Cumulative Effect of Changes in Accounting Principles,
Net of Tax - (.09) -
- -----------------------------------------------------------------------------------------------------
Net Income $ 3.12 $ 3.28 $ 2.42
- -----------------------------------------------------------------------------------------------------
Dividends Declared per Common Share $ 2.32 $ 2.26 $ 2.20
- -----------------------------------------------------------------------------------------------------
83
See Notes to Consolidated Financial Statements.
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (continued)
- ----------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- ----------------------------------------------------------------------------------------
ASSETS
Utility Plant
Utility plant in service $ 22,103 $ 21,680
Accumulated depreciation (8,783) (8,174)
- ----------------------------------------------------------------------------------------
Utility plant in service, net 13,320 13,506
Held for future use 13 13
Construction work in progress 799 559
Nuclear fuel, net of amortization 231 228
- ----------------------------------------------------------------------------------------
Total Utility Plant, Net 14,363 14,306
- ----------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 62 47
Short-term investments 82 226
Receivables 1,084 1,084
Inventory 982 907
Deferred fuel cost 229 270
Deferred income taxes 121 87
Prepayments and other current assets 175 268
- ----------------------------------------------------------------------------------------
Total Current Assets 2,735 2,889
- ----------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 1,064 598
Nuclear decommissioning trust funds 1,044 938
Diversified business property, net 2,010 2,095
Miscellaneous other property and investments 446 464
Goodwill 3,719 3,726
Prepaid pension costs 42 462
Intangibles, net 337 357
Other assets and deferred debits 233 258
- ----------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 8,895 8,898
- ----------------------------------------------------------------------------------------
Total Assets $ 25,993 $ 26,093
- ----------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
84
PROGRESS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS (concluded)
- ------------------------------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- ------------------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
- ------------------------------------------------------------------------------------------------------------
Common Stock Equity
Common stock without par value, 500 million shares authorized,
247 and 246 million shares issued and outstanding, respectively) $ 5,360 $ 5,270
Unearned restricted shares (1 and 1 million shares, respectively) (13) (17)
Unearned ESOP shares (3 and 4 million shares, respectively) (76) (89)
Accumulated other comprehensive loss (164) (50)
Retained earnings 2,526 2,330
- ------------------------------------------------------------------------------------------------------------
Total Common Stock Equity 7,633 7,444
- ------------------------------------------------------------------------------------------------------------
Preferred Stock of Subsidiaries - Not Subject to Mandatory
Redemption 93 93
Minority Interest 36 30
Long-Term Debt, Affiliate 270 270
Long-Term Debt, Net 9,251 9,664
- ------------------------------------------------------------------------------------------------------------
Total Capitalization 17,283 17,501
- ------------------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 349 868
Accounts payable 742 635
Interest accrued 219 228
Dividends declared 145 140
Short-term obligations 684 4
Customer deposits 180 167
Other current liabilities 742 608
- ------------------------------------------------------------------------------------------------------------
Total Current Liabilities 3,061 2,650
- ------------------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Noncurrent income tax liabilities 599 701
Accumulated deferred investment tax credits 176 190
Regulatory liabilities 2,654 2,879
Asset retirement obligations 1,282 1,271
Accrued pension and other benefits 562 508
Other liabilities and deferred credits 376 393
- ------------------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 5,649 5,942
- ------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 22 and 23)
- ------------------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 25,993 $ 26,093
- ------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
85
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
- ------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 759 $ 782 $ 528
Adjustments to reconcile net income to net cash provided by operating
activities
(Income) loss from discontinued operations (6) 8 24
Net (gain) loss on sale of operating assets (57) 1 -
Impairment of long-lived assets and investments - 38 389
Cumulative effect of changes in accounting principles - 21 -
Depreciation and amortization 1,181 1,146 1,099
Deferred income taxes (74) (276) (402)
Investment tax credit (14) (16) (18)
Deferred fuel credit (19) (133) (37)
Cash provided (used) by changes in operating assets and liabilities
Receivables (35) (158) (50)
Inventory (108) 8 (66)
Prepayments and other current assets (18) 39 (24)
Accounts payable 33 37 100
Other current liabilities 82 121 56
Regulatory assets and liabilities (284) (21) 46
Other 167 127 (18)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,607 1,724 1,627
- ------------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross utility property additions (998) (972) (1,169)
Diversified business property additions (236) (584) (558)
Nuclear fuel additions (101) (117) (81)
Proceeds from sales of subsidiaries and other investments 366 579 43
Acquisition of businesses, net of cash - - (365)
Purchases of short-term investments (2,108) (2,813) (2,962)
Proceeds from sales of short-term investments 2,252 2,587 2,962
Acquisition of intangibles (1) (200) (10)
Other (46) (26) (61)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (872) (1,546) (2,201)
- ------------------------------------------------------------------------------------------------------------------------
Financing Activities
Issuance of common stock, net 73 304 687
Issuance of long-term debt, net 421 1,539 1,783
Net increase (decrease) in short-term indebtedness 680 (696) (247)
Retirement of long-term debt (1,353) (810) (1,157)
Dividends paid on common stock (558) (541) (480)
Other 17 12 (5)
- ------------------------------------------------------------------------------------------------------------------------
Net Cash (Used in) Provided by Financing Activities (720) (192) 581
- ------------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 15 (14) 7
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 47 61 54
- ------------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 62 $ 47 $ 61
- ------------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 657 $ 643 $ 651
income taxes (net of refunds) $ 189 $ 177 $ 219
- ------------------------------------------------------------------------------------------------------------------------
Noncash Activities
o In April 2002, Progress Fuels Corporation, a subsidiary of the Company,
acquired 100% of Westchester Gas Company. In conjunction with the purchase,
the Company issued approximately $129 million in common stock (See Note
5D).
o In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, Inc., both indirectly wholly owned subsidiaries of Progress
Energy, and EPIK Communications, Inc., a wholly owned subsidiary of Odyssey
Telecorp, Inc., contributed substantially all of their assets and
transferred certain liabilities to Progress Telecom, LLC, a subsidiary of
PTC (See Note 5A).
- ------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
86
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of CHANGES in COMMON STOCK EQUITY
- ---------------------------------------------------------------------------------------------------------------------------
Accumulated Total
Common Stock Unearned Unearned Other Common
Outstanding Restricted ESOP Comprehensive Retained Stock
(in millions except per share data) Shares Amount Shares Shares Income (Loss) Earnings Equity
- ---------------------------------------------------------------------------------------------------------------------------
Balance, January 1, 2002 219 $ 4,121 $ (14) $ (114) $ (32) $ 2,043 $ 6,004
Net income 528 528
Other comprehensive loss (206) (206)
-----------
Issuance of shares 19 815 815
Purchase of restricted stock (16) (16)
Restricted stock expense recognition 8 8
Cancellation of restricted shares (1) 1 -
Allocation of ESOP shares 16 12 28
Dividends ($2.20 per share) (484) (484)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002 238 4,951 (21) (102) (238) 2,087 6,677
Net income 782 782
Other comprehensive income 188 188
-----------
Issuance of shares 8 305 305
Stock options exercised 4 4
Purchase of restricted stock (1) (7) (8)
Restricted stock expense recognition 10 10
Cancellation of restricted shares (1) 1 -
Allocation of ESOP shares 12 13 25
Dividends ($2.26 per share) (539) (539)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003 246 5,270 (17) (89) (50) 2,330 7,444
Net income 759 759
Other comprehensive loss (114) (114)
-----------
Issuance of shares 1 62 62
Stock options exercised 18 18
Purchase of restricted stock (7) (7)
Restricted stock expense recognition 7 7
Cancellation of restricted shares (4) 4 -
Allocation of ESOP shares 14 13 27
Dividends ($2.32 per share) (563) (563)
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2004 247 $ 5,360 $ (13) $ (76) $ (164) $ 2,526 $ 7,633
- ---------------------------------------------------------------------------------------------------------------------------
PROGRESS ENERGY, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
- ------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Net Income $ 759 $ 782 $ 528
Other Comprehensive Income (Loss)
Changes in net unrealized losses on cash flow hedges (net of tax
benefit of $10, $7 and $18, respectively) (18) (12) (28)
Reclassification adjustment for amounts included in net income
(net of tax expense of ($16), ($11) and ($10), respectively) 26 19 16
Reclassification of minimum pension liability to regulatory
assets (net of tax expense of ($2)) 4 - -
Minimum pension liability adjustment (net of tax benefit
(expense) of $78, ($112) and $121, respectively) (130) 177 (192)
Foreign currency translation and other 4 4 (2)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income (Loss) $ (114) $ 188 $ (206)
- ------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 645 $ 970 $ 322
- ------------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
87
PROGRESS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization
Progress Energy, Inc. (Progress Energy or the Company) is a holding company
headquartered in Raleigh, North Carolina. The Company is registered under
the Public Utility Holding Company Act of 1935 (PUHCA), as amended, and as
such, the Company and its subsidiaries are subject to the regulatory
provisions of PUHCA. Effective January 1, 2003, three of the Company's
subsidiaries, Carolina Power & Light Company (CP&L), Florida Power
Corporation and Progress Ventures, Inc., began doing business under the
assumed names Progress Energy Carolinas, Inc. (PEC), Progress Energy
Florida, Inc. (PEF) and Progress Energy Ventures, Inc. (PVI), respectively.
Through its wholly owned subsidiaries, PEC and PEF, the Company's PEC
Electric and PEF segments are primarily engaged in the generation,
transmission, distribution and sale of electricity in portions of North
Carolina, South Carolina and Florida. The Progress Ventures business unit
consists of the Fuels business segment (Fuels) and Competitive Commercial
Operations (CCO) operating segments. The Fuels segment is involved in
natural gas drilling and production, coal terminal services, coal mining,
synthetic fuel production, fuel transportation and delivery. The CCO
segment includes nonregulated generation and energy marketing activities.
Through the Rail Services (Rail) segment, the Company is involved in
nonregulated railcar repair, rail parts reconditioning and sales and scrap
metal recycling. Through its other business units, the Company engages in
other nonregulated business areas, including telecommunications and energy
management and related services. Progress Energy's legal structure is not
currently aligned with the functional management and financial reporting of
the Progress Ventures business unit. Whether, and when, the legal and
functional structures will converge depends upon legislative and regulatory
action, which cannot currently be anticipated.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of the Company and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable
and the future recovery of the sales price through the ratemaking process
is probable.
The consolidated financial statements of the Company and its subsidiaries
include the majority-owned and controlled subsidiaries. Noncontrolling
interests in the subsidiaries along with the income or loss attributed to
these interests are included in minority interest in both the Consolidated
Balance Sheets and in the Consolidated Statements of Income. The results of
operations for minority interest are reported on a net of tax basis if the
underlying subsidiary is structured as a taxable entity.
Unconsolidated investments in companies over which the Company does not
have control, but has the ability to exercise influence over operating and
financial policies (generally 20%-50% ownership), are accounted for under
the equity method of accounting. These investments are primarily in limited
liability corporations and limited liability partnerships, and the earnings
from these investments are recorded on a pre-tax basis (See Note 21). These
equity method investments are included in miscellaneous other property and
investments in the Consolidated Balance Sheets. At December 31, 2004 and
2003, the Company has equity method investments of approximately $27
million and $36 million, respectively.
Certain investments in debt and equity securities that have readily
determinable market values, and for which the Company does not have
control, are accounted for as available-for-sale securities at fair value
in accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities." These investments include investments held in
trust funds, pursuant to United States Nuclear Regulatory Commission (NRC)
requirements, to fund certain costs of decommissioning nuclear plants. The
fair value of these trust funds was $1.044 billion and $938 million at
December 31, 2004 and 2003, respectively. The Company also actively invests
available cash balances in various financial instruments, such as
tax-exempt debt securities that have stated maturities of 20 years or more.
These instruments provide for a high degree of liquidity through
arrangements with banks that provide daily and weekly liquidity and 7, 28
and 35 day auctions that allow for the redemption of the investment at its
face amount plus earned income. As the Company intends to sell these
instruments generally within 30 days from the balance sheet date, they are
88
classified as current assets. At December 31, 2004 and 2003, the fair value
of these investments was $82 million and $226 million, respectively. Other
investments in debt and equity securities are included in miscellaneous
other property and investments in the Consolidated Balance Sheets. At
December 31, 2004 and 2003, the fair value of these other investments was
$39 million and $39 million, respectively.
Other investments are stated principally at cost. These cost method
investments are included in miscellaneous other property and investments in
the Consolidated Balance Sheets. At December 31, 2004, and 2003, the
Company has approximately $14 million and $14 million, respectively, of
cost method investments.
The results of operations of Rail are reported one month in arrears. During
2003, the Company ceased recording portions of the Fuels' segment
operations one month in arrears. The net impact of this action increased
net income by $2 million for the year.
Certain amounts for 2003 and 2002 have been reclassified to conform to the
2004 presentation. Reclassifications include the reclassification of
instruments used in PEC's cash management program from cash and cash
equivalents to short-term investments of $226 million at December 31, 2003,
in the Consolidated Balance Sheets. In the Consolidated Statements of Cash
Flow for each of the three years in the period ended December 31, 2004,
total cash balances and total cash flows used in investing activities were
revised to reflect the reclassification of these instruments from cash and
cash equivalents to short-term investments.
C. Consolidation of Variable Interest Entities
The Company consolidates all voting interest entities in which it owns a
majority voting interest and all variable interest entities for which it is
the primary beneficiary in accordance with FASB Interpretation No. 46R,
"Consolidation of Variable Interest Entities - An Interpretation of ARB No.
51" (FIN No. 46R). The Company is the primary beneficiary of and
consolidates two limited partnerships that qualify for federal affordable
housing and historic tax credits under Section 42 of the Internal Revenue
Code (Code). As of December 31, 2004, the total assets of the two entities
were $37 million, the majority of which are collateral for the entities'
obligations and are included in other current assets and miscellaneous
other property and investments in the Consolidated Balance Sheets.
The Company is the primary beneficiary of a limited partnership that
invests in 17 low-income housing partnerships that qualify for federal and
state tax credits. The Company has requested but has not received all the
necessary information to determine the primary beneficiary of the limited
partnership's underlying 17 partnership investments, and has applied the
information scope exception in FIN No. 46R, paragraph 4(g) to the 17
partnerships. The Company has no direct exposure to loss from the 17
partnerships; the Company's only exposure to loss is from its investment of
less than $1 million in the consolidated limited partnership. The Company
will continue its efforts to obtain the necessary information to fully
apply FIN No. 46R to the 17 partnerships. The Company believes that if the
limited partnership is determined to be the primary beneficiary of the 17
partnerships, the effect of consolidating the 17 partnerships would not be
significant to the Company's Consolidated Balance Sheets.
The Company has variable interests in two power plants resulting from
long-term power purchase contracts. The Company has requested the necessary
information to determine if the counterparties are variable interest
entities or to identify the primary beneficiaries. Both entities declined
to provide the Company with the necessary financial information, and the
Company has applied the information scope exception in FIN No. 46R,
paragraph 4(g). The Company's only significant exposure to variability from
these contracts results from fluctuations in the market price of fuel used
by the two entities' plants to produce the power purchased by the Company.
The Company is able to recover these fuel costs under PEC's fuel clause.
Total purchases from these counterparties were approximately $58 million,
$53 million and $53 million in 2004, 2003 and 2002, respectively. The
Company will continue its efforts to obtain the necessary information to
fully apply FIN No. 46R to these contracts. The combined generation
capacity of the two entities' power plants is approximately 880 MW. The
Company believes that if it is determined to be the primary beneficiary of
these two entities, the effect of consolidating the entities would result
in increases to total assets, long-term debt and other liabilities, but
would have an insignificant or no impact on the Company's common stock
equity, net earnings or cash flows. However, because the Company has not
received any financial information from these two counterparties, the
impact cannot be determined at this time.
The Company also has interests in several other variable interest entities
for which the Company is not the primary beneficiary. These arrangements
include investments in approximately 28 limited partnerships, limited
liability corporations and venture capital funds and two building leases
with special-purpose entities. The aggregate maximum loss exposure at
December 31, 2004, that the Company could be required to record in its
income statement as a result of these arrangements totals approximately $38
million. The creditors of these variable interest entities do not have
recourse to the general credit of the Company in excess of the aggregate
maximum loss exposure.
89
D. Significant Accounting Policies
USE OF ESTIMATES AND ASSUMPTIONS
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
amounts of revenues and expenses reflected during the reporting period.
Actual results could differ from those estimates.
REVENUE RECOGNITION
The Company recognizes electric utility revenues as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Diversified business revenues are generally recognized
at the time products are shipped or as services are rendered. Leasing
activities are accounted for in accordance with SFAS No. 13, "Accounting
for Leases." Revenues related to design and construction of wireless
infrastructure are recognized upon completion of services for each
completed phase of design and construction. Revenues from the sale of oil
and gas production are recognized when title passes, net of royalties.
FUEL COST DEFERRALS
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by the electric utilities' regulators. These
clauses allow the utilities to recover fuel costs and portions of purchased
power costs through surcharges on customer rates. These deferred fuel costs
are recognized in revenues and fuel expenses as they are billable to
customers.
EXCISE TAXES
PEC and PEF collect from customers certain excise taxes levied by the state
or local government upon the customers. PEC and PEF account for excise
taxes on a gross basis. For the years ended December 31, 2004, 2003 and
2002, gross receipts tax, franchise taxes and other excise taxes of
approximately $240 million, $217 million and $212 million, respectively,
are included in utility revenues and taxes other than on income in the
Consolidated Statements of Income.
STOCK-BASED COMPENSATION
The Company measures compensation expense for stock options as the
difference between the market price of its common stock and the exercise
price of the option at the grant date. The exercise price at which options
are granted by the Company equals the market price at the grant date, and
accordingly, no compensation expense has been recognized for stock option
grants. For purposes of the pro forma disclosures required by SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure - An
Amendment of FASB Statement No. 123" (SFAS No. 148), the estimated fair
value of the Company's stock options is amortized to expense over the
options' vesting period. The following table illustrates the effect on net
income and earnings per share if the fair value method had been applied to
all outstanding and unvested awards in each period:
90
- ---------------------------------------------------------------------------------------------------------------
(in millions except per share data) 2004 2003 2002
- ---------------------------------------------------------------------------------------------------------------
Net income, as reported $ 759 $ 782 $ 528
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 10 11 8
- ---------------------------------------------------------------------------------------------------------------
Pro forma net income $ 749 $ 771 $ 520
- ---------------------------------------------------------------------------------------------------------------
Earnings per share
Basic - as reported $ 3.13 $ 3.30 $ 2.43
Basic - pro forma $ 3.09 $ 3.25 $ 2.40
Diluted - as reported $ 3.12 $ 3.28 $ 2.42
Diluted - pro forma $ 3.08 $ 3.24 $ 2.39
- ---------------------------------------------------------------------------------------------------------------
See Note 2 for a discussion of newly issued accounting guidance related to
stock-based compensation.
UTILITY PLANT
Utility plant in service is stated at historical cost less accumulated
depreciation. The Company capitalizes all construction-related direct labor
and material costs of units of property as well as indirect construction
costs. Certain costs that would otherwise not be capitalized under GAAP are
capitalized in accordance with regulatory treatment. The cost of renewals
and betterments is also capitalized. Maintenance and repairs of property
(including planned major maintenance activities), and replacements and
renewals of items determined to be less than units of property, are charged
to maintenance expense as incurred, with the exception of nuclear outages
at PEF. Pursuant to a regulatory order, PEF accrues for nuclear outage
costs in advance of scheduled outages, which occur every two years. The
cost of units of property replaced or retired, less salvage, is charged to
accumulated depreciation. Removal or disposal costs that do not represent
SFAS No. 143, "Accounting for Asset Retirement Obligations," (SFAS No. 143)
are charged to a regulatory liability.
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform system of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges.
ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2003, the Company adopted the guidance in SFAS No. 143
to account for legal obligations associated with the retirement of certain
tangible long-lived assets. The present value of retirement costs for which
the Company has a legal obligation are recorded as liabilities with an
equivalent amount added to the asset cost and depreciated over an
appropriate period. The liability is then accreted over time by applying an
interest method of allocation to the liability.
The adoption of this statement had no impact on the income of the regulated
entities, as the effects were offset by the establishment of a regulatory
asset and a regulatory liability pursuant to SFAS No. 71 (See Note 8A). The
North Carolina Utilities Commission (NCUC), the Public Service Commission
of South Carolina (SCPSC) and the Florida Public Service Commission (FPSC)
issued orders to authorize deferral of all prospective effects related to
SFAS No. 143 as a regulatory asset or liability (See Note 8A). Therefore,
SFAS No. 143 has no impact on the income of the regulated entities.
DEPRECIATION AND AMORTIZATION - UTILITY PLANT
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated salvage (See Note 6A). Pursuant to their rate-setting authority,
the NCUC, SCPSC and FPSC can also grant approval to accelerate or reduce
depreciation and amortization of utility assets (See Note 8).
Amortization of nuclear fuel costs is computed primarily on the
units-of-production method. In the Company's retail jurisdictions,
provisions for nuclear decommissioning costs are approved by the NCUC, the
SCPSC and the FPSC and are based on site-specific estimates that include
the costs for removal of all radioactive and other structures at the site.
In the wholesale jurisdictions, the provisions for nuclear decommissioning
costs are approved by the Federal Energy Regulatory Commission (FERC).
91
CASH AND CASH EQUIVALENTS
The Company considers cash and cash equivalents to include unrestricted
cash on hand, cash in banks and temporary investments purchased with a
maturity of three months or less.
INVENTORY
The Company accounts for inventory using the average-cost method.
Inventories are valued at the lower of average cost or market.
REGULATORY ASSETS AND LIABILITIES
The Company's regulated operations are subject to SFAS No. 71, which allows
a regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, the Company records assets and liabilities that result from
the regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the Consolidated
Balance Sheets as regulatory assets and regulatory liabilities (See Note
8A).
DIVERSIFIED BUSINESS PROPERTY
Diversified business property is stated at cost less accumulated
depreciation. If an impairment is recognized on an asset, the fair value
becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. For properties other than oil and gas properties, depreciation is
computed on a straight-line basis using the estimated useful lives
disclosed in Note 6B. Depletion of mineral rights is provided on the
units-of-production method based upon the estimates of recoverable amounts
of clean mineral.
The Company uses the full-cost method to account for its oil and gas
properties. Under the full-cost method, substantially all productive and
nonproductive costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves are capitalized. These
capitalized costs include the costs of all unproved properties and internal
costs directly related to acquisition and exploration activities. The
amortization base also includes the estimated future cost to develop proved
reserves. Except for costs of unproved properties and major development
projects in progress, all costs are amortized using the units-of-production
method on a country by country basis over the life of the Company's proved
reserves. Accordingly, all property acquisition, exploration, and
development costs of proved oil and gas properties, including the costs of
abandoned properties, dry holes, geophysical costs and annual lease rentals
are capitalized as incurred, including internal costs directly attributable
to such activities. Related interest expense incurred during property
development activities is capitalized as a cost of such activity. Net
capitalized costs of unproved property are reclassified as proved property
and well costs when related proved reserves are found. Costs to operate and
maintain wells and field equipment are expensed as incurred. In accordance
with Rule 4-10 of Regulation S-X, sales or other dispositions of oil and
gas properties are accounted for as adjustments to capitalized costs, with
no gain or loss recorded unless certain significance tests are met.
GOODWILL AND INTANGIBLE ASSETS
Goodwill is subject to at least an annual assessment for impairment by
applying a two-step fair-value-based test. This assessment could result in
periodic impairment charges. Intangible assets are being amortized based on
the economic benefit of their respective lives.
UNAMORTIZED DEBT PREMIUMS, DISCOUNTS AND EXPENSES
Long-term debt premiums, discounts and issuance expenses are amortized over
the terms of the debt issues. Any expenses or call premiums associated with
the reacquisition of debt obligations by the utilities are amortized over
the applicable life using the straight-line method consistent with
ratemaking treatment (See Note 8A).
92
INCOME TAXES
The Company and its affiliates file a consolidated federal income tax
return. Deferred income taxes have been provided for temporary differences.
These occur when there are differences between the book and tax carrying
amounts of assets and liabilities. Investment tax credits related to
regulated operations have been deferred and are being amortized over the
estimated service life of the related properties. Credits for the
production and sale of synthetic fuel are deferred as AMT credits to the
extent they cannot be or have not been utilized in the annual consolidated
federal income tax returns, and are included in income tax expense
(benefit) in the Consolidated Statements of Income.
DERIVATIVES
The Company accounts for derivative instruments in accordance with SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
No. 133), as amended by SFAS No. 138 and SFAS No. 149. SFAS No. 133, as
amended, establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. SFAS No. 133 requires that an entity
recognize all derivatives as assets or liabilities in the balance sheet and
measure those instruments at fair value, unless the derivatives meet the
SFAS No. 133 criteria for normal purchases or normal sales and are
designated as such. The Company generally designates derivative instruments
as normal purchases or normal sales whenever the SFAS No. 133 criteria are
met. If normal purchase or normal sale criteria are not met, the Company
will generally designate the derivative instruments as cash flow or fair
value hedges if the related SFAS No. 133 hedge criteria are met. During
2003, the FASB reconsidered an interpretation of SFAS No. 133. See Note 18
for the effect of the interpretation and additional information regarding
risk management activities and derivative transactions.
ENVIRONMENTAL
As discussed in Note 22, the Company accrues environmental remediation
liabilities when the criteria for SFAS No. 5, "Accounting for
Contingencies" (SFAS No. 5), have been met. Environmental expenditures that
relate to an existing condition caused by past operations and that have no
future economic benefits are expensed. Accruals for estimated losses from
environmental remediation obligations generally are recognized no later
than completion of the remedial feasibility study. Such accruals are
adjusted as additional information develops or circumstances change. Costs
of future expenditures for environmental remediation obligations are not
discounted to their present value. Recoveries of environmental remediation
costs from other parties are recognized when their receipt is deemed
probable. Environmental expenditures that have future economic benefits are
capitalized in accordance with the Company's asset capitalization policy.
IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS
As discussed in Note 10, the Company reviews the recoverability of
long-lived tangible and intangible assets whenever indicators exist.
Examples of these indicators include current period losses, combined with a
history of losses or a projection of continuing losses, or a significant
decrease in the market price of a long-lived asset group. If an indicator
exists for assets to be held and used, then the asset group is tested for
recoverability by comparing the carrying value to the sum of undiscounted
expected future cash flows directly attributable to the asset group. If the
asset group is not recoverable through undiscounted cash flows or the asset
group is to be disposed of, then an impairment loss is recognized for the
difference between the carrying value and the fair value of the asset
group. The accounting for impairment of assets is based on SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets."
The Company reviews its investments to evaluate whether or not a decline in
fair value below the carrying value is an other-than-temporary decline. The
Company considers various factors, such as the investee's cash position,
earnings and revenue outlook, liquidity and management's ability to raise
capital in determining whether the decline is other-than-temporary. If the
Company determines that an other-than-temporary decline exists in the value
of its investments, it is the Company's policy to write-down these
investments to fair value.
Under the full-cost method of accounting for oil and gas properties, total
capitalized costs are limited to a ceiling based on the present value of
discounted (at 10%) future net revenues using current prices, plus the
lower of cost or fair market value of unproved properties. The ceiling test
takes into consideration the prices of qualifying cash flow hedges as of
the balance sheet date. If the ceiling (discounted revenues) is not equal
to or greater than total capitalized costs, the Company is required to
write-down capitalized costs to this level. The Company performs this
ceiling test calculation every quarter. No write-downs were required in
2004, 2003 or 2002.
93
SUBSIDIARY STOCK TRANSACTIONS
Gains and losses realized as a result of common stock sales by the
Company's subsidiaries are recorded in the Consolidated Statements of
Income, except for any transactions that must be credited directly to
equity in accordance with the provisions of Staff Accounting Bulletin No.
51, "Accounting for Sales of Stock by a Subsidiary."
2. NEW ACCOUNTING STANDARDS
FASB STAFF POSITION 106-2, "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED
TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF
2003"
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (Medicare Act) was signed into law. In accordance
with guidance issued by the Financial Accounting Standards Board (FASB) in
FASB Staff Position 106-1, "Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug Improvement and Modernization Act of
2003," (FASB Staff Position 106-1) the Company elected to defer accounting
for the effects of the Medicare Act due to uncertainties regarding the
effects of the implementation of the Medicare Act and the accounting for
certain provisions of the Medicare Act. In May 2004, the FASB issued
definitive accounting guidance for the Medicare Act in FASB Staff Position
106-2, which was effective for the Company in the third quarter of 2004.
FASB Staff Position 106-2 results in the recognition of lower other
postretirement employment benefit (OPEB) costs to reflect prescription
drug-related federal subsidies to be received under the Medicare Act. As a
result of the Medicare Act, the Company's accumulated postretirement
benefit obligation as of January 1, 2004, was reduced by approximately $83
million, and the Company's 2004 net periodic cost was reduced by
approximately $13 million.
SFAS NO. 123 (REVISED 2004), "SHARE-BASED PAYMENT" (SFAS NO. 123R)
In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No.
123, "Accounting for Stock-Based Compensation," and supersedes Accounting
Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to
Employees." The key requirement of SFAS No. 123R is that the cost of
share-based awards to employees will be measured based on an award's fair
value at the grant date, with such cost to be amortized over the
appropriate service period. Previously, entities could elect to continue
accounting for such awards at their grant date intrinsic value under APB
Opinion No. 25, and the Company made that election. The intrinsic value
method resulted in the Company recording no compensation expense for stock
options granted to employees (See Note 11).
SFAS No. 123R will be effective for the Company on July 1, 2005. The
Company intends to implement the standard using the required modified
prospective method. Under that method, the Company will record compensation
expense under SFAS No. 123R for all awards it grants after July 1, 2005,
and it will record compensation expense (as previous awards continue to
vest) for the unvested portion of previously granted awards that remain
outstanding at July 1, 2005. In 2004, the Company made the decision to
cease granting stock options and intends to replace that compensation
program with other programs. Therefore, the amount of stock option expense
expected to be recorded in 2005 is below the amount that would have been
recorded if the stock option program had continued. The Company expects to
record approximately $3 million of pre-tax expense for stock options in
2005.
PROPOSED FASB INTERPRETATION OF SFAS NO. 109, "ACCOUNTING FOR INCOME TAXES"
In July 2004, the FASB stated that it plans to issue an exposure draft of a
proposed interpretation of SFAS No. 109, "Accounting for Income Taxes"
(SFAS No. 109), that would address the accounting for uncertain tax
positions. The FASB has indicated that the interpretation would require
that uncertain tax benefits be probable of being sustained in order to
record such benefits in the consolidated financial statements. The exposure
draft is expected to be issued in the first quarter of 2005. The Company
cannot predict what actions the FASB will take or how any such actions
might ultimately affect the Company's financial position or results of
operations, but such changes could have a material impact on the Company's
evaluation and recognition of Section 29 tax credits (See Note 23E).
94
3. HURRICANE RELATED COSTS
Hurricanes Charley, Frances, Ivan and Jeanne struck significant portions of
the Company's service territories during the third quarter of 2004,
significantly impacting PEF's territory. As of December 31, 2004,
restoration of the Company's systems from hurricane-related damage was
estimated at $398 million. PEC incurred restoration costs of $13 million,
of which $12 million was charged to operation and maintenance expense and
$1 million was charged to capital expenditures. PEF had estimated total
costs of $385 million, of which $47 million was charged to capital
expenditures, and $338 million was charged to the storm damage reserve
pursuant to a regulatory order.
In accordance with a regulatory order, PEF accrues $6 million annually to a
storm damage reserve and is allowed to defer losses in excess of the
accumulated reserve for major storms. Under the order, the storm reserve is
charged with operation and maintenance expenses related to storm
restoration and with capital expenditures related to storm restoration that
are in excess of expenditures assuming normal operating conditions. As of
December 31, 2004, $291 million of hurricane restoration costs in excess of
the previously recorded storm reserve of $47 million had been classified as
a regulatory asset recognizing the probable recoverability of these costs.
On November 2, 2004, PEF filed a petition with the FPSC to recover $252
million of storm costs plus interest from retail ratepayers over a two-year
period. Storm reserve costs of $13 million were attributable to wholesale
customers. The Company has received approval from the FERC to amortize
these costs consistent with recovery of such amounts in wholesale rates.
PEF continues to review the restoration cost invoices received. Given that
not all invoices have been received as of December 31, 2004, PEF will
update its petition with the FPSC upon receipt and audit of all actual
charges incurred. Hearings on PEF's petition for recovery of $252 million
of storm costs filed with the FPSC are scheduled to begin on March 30,
2005.
On November 17, 2004, the Citizens of the State of Florida, by and through
Harold McLean, Public Counsel, and the Florida Industrial Power Users Group
(FIPUG), (collectively, Joint Movants), filed a Motion to Dismiss PEF's
petition to recover the $252 million in storm costs. On November 24, 2004,
PEF responded in opposition to the motion, which was also the FPSC staff's
position in its recommendation to the Commission on December 21, 2004, that
it should deny the Motion to Dismiss. On January 4, 2005, the Commission
ruled in favor of PEF and denied Joint Movant's Motion to Dismiss.
PEF's January 2005 notice to the FPSC of its intent to file for an increase
in its base rates effective January 1, 2006, anticipates the need to
replenish the depleted storm reserve balance and adjust the annual $6
million accrual in light of recent storm history to restore the reserve to
an adequate level over a reasonable time period (See Note 8C).
PEC does not have an ongoing regulatory mechanism to recover storm costs;
therefore, hurricane restoration costs recorded in the third quarter of
2004 were charged to operations and maintenance expenses or capital
expenditures based on the nature of the work performed. In connection with
other storms, PEC has previously sought and received permission from the
NCUC and the SCPSC to defer storm expenses and amortize them over a
five-year period. PEC did not seek deferral of 2004 storm costs from the
NCUC (See Note 8B).
4. DIVESTITURES
A. Sale of Natural Gas Assets
In December 2004, the Company sold certain gas-producing properties and
related assets owned by Winchester Production Company, Ltd. (Winchester
Production), an indirectly wholly owned subsidiary of Progress Fuels
Corporation (Progress Fuels), which is included in the Fuels segment. Net
proceeds of approximately $251 million were used to reduce debt. Because
the sale significantly altered the ongoing relationship between capitalized
costs and remaining proved reserves, under the full-cost method of
accounting, the pre-tax gain of $56 million was recognized in earnings
rather than as a reduction of the basis of the Company's remaining oil and
gas properties. The pre-tax gain has been included in (gain)/loss on the
sale of assets in the Consolidated Statements of Income.
95
B. Divestiture of Synthetic Fuel Partnership Interests
In June 2004, the Company through its subsidiary, Progress Fuels, sold, in
two transactions, a combined 49.8% partnership interest in Colona Synfuel
Limited Partnership, LLLP, one of its synthetic fuel facilities.
Substantially all proceeds from the sales will be received over time, which
is typical of such sales in the industry. Gain from the sales will be
recognized on a cost recovery basis. The Company's book value of the
interests sold totaled approximately $5 million. The Company received total
gross proceeds of $10 million in 2004. Based on projected production and
tax credit levels, the Company anticipates receiving approximately $24
million in 2005, approximately $31 million in 2006, approximately $32
million in 2007, and approximately $8 million through the second quarter of
2008. In the event that the synthetic fuel tax credits from the Colona
facility are reduced, including an increase in the price of oil that could
limit or eliminate synthetic fuel tax credits, the amount of proceeds
realized from the sale could be significantly impacted.
C. Railcar Ltd., Divestiture
In December 2002, the Progress Energy Board of Directors adopted a
resolution approving the sale of Railcar Ltd., a subsidiary included in the
Rail Services segment. An estimated pre-tax impairment of $59 million on
assets held for sale was recognized in December 2002 to write-down the
assets to fair value less costs to sell. This impairment has been included
in impairment of long-lived assets in the Consolidated Statements of Income
(See Note 10A). In March 2003, the Company signed a letter of intent to
sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the
transaction closed in February 2004. Proceeds from the sale were
approximately $82 million before transaction costs and taxes of
approximately $13 million. In July 2004, the Company sold the remaining
assets classified as held for sale to a third-party for net proceeds of $6
million. The assets of Railcar Ltd. were grouped as assets held for sale
and were included in other current assets on the Consolidated Balance
Sheets at December 31, 2003, at approximately $75 million, which reflected
the Company's estimates of the fair value expected to be realized from the
sale of these assets less costs to sell.
D. Mesa Hydrocarbons, Inc., Divestiture
In October 2003, the Company sold certain gas-producing properties owned by
Mesa Hydrocarbons, LLC, a wholly owned subsidiary of Progress Fuels. Net
proceeds were approximately $97 million. Because the Company utilizes the
full-cost method of accounting for its oil and gas operations, the pre-tax
gain of approximately $18 million was applied to reduce the basis of the
Company's other U.S. oil and gas investments and will prospectively result
in a reduction of the amortization rate applied to those investments as
production occurs.
E. NCNG Divestiture
On September 30, 2003, the Company completed the sale of North Carolina
Natural Gas Corporation (NCNG) and the Company's equity investment in
Eastern North Carolina Natural Gas Company (ENCNG) to Piedmont Natural Gas
Company, Inc. Net proceeds from the sale of NCNG of approximately $443
million were used to reduce debt.
The consolidated financial statements have been restated for all periods
presented for the discontinued operations of NCNG. The net income of these
operations is reported as discontinued operations in the Consolidated
Statements of Income. Interest expense of $10 million and $16 million for
the years ended December 31, 2003 and 2002, respectively, has been
allocated to discontinued operations based on the net assets of NCNG,
assuming a uniform debt-to-equity ratio across the Company's operations.
The Company ceased recording depreciation effective October 1, 2002, upon
classification of the assets as discontinued operations. After-tax
depreciation expense recorded by NCNG for the year ended December 31, 2002,
was $9 million. Results of discontinued operations for years ended December
31 were as follows:
96
- ----------------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- ----------------------------------------------------------------------------------------------
Revenues $ - $ 284 $ 300
- ----------------------------------------------------------------------------------------------
Earnings before income taxes $ - $ 6 $ 9
Income tax expense - 2 4
- ----------------------------------------------------------------------------------------------
Net earnings from discontinued operations - 4 5
- ----------------------------------------------------------------------------------------------
Gain/(Loss) on disposal of discontinued operations,
including applicable income tax benefit / (expense) of
$6, $1 and $3, respectively 6 (12) (29)
- ----------------------------------------------------------------------------------------------
Earnings (loss) from discontinued operations $ 6 $ (8) $ (24)
- ----------------------------------------------------------------------------------------------
During 2004, the Company recorded an additional tax gain of approximately
$6 million due to final tax adjustments related to the divestiture of NCNG.
The sale of ENCNG resulted in net proceeds of $7 million and a pre-tax loss
of $2 million, which is included in other, net on the Consolidated
Statements of Income for the year ended December 31, 2003.
5. ACQUISITIONS AND BUSINESS COMBINATIONS
A. Progress Telecommunications Corporation
In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, Inc. (Caronet), both wholly owned subsidiaries of Progress Energy,
and EPIK Communications, Inc. (EPIK), a wholly owned subsidiary of Odyssey
Telecorp, Inc. (Odyssey), contributed substantially all of their assets and
transferred certain liabilities to Progress Telecom, LLC (PT LLC), a
subsidiary of PTC. Subsequently, the stock of Caronet was sold to an
affiliate of Odyssey for $2 million in cash and Caronet became a wholly
owned subsidiary of Odyssey. Following consummation of all the transactions
described above, PTC holds a 55% ownership interest in, and is the parent
of, PT LLC. Odyssey holds a combined 45% ownership interest in PT LLC
through EPIK and Caronet. The accounts of PT LLC have been included in the
Company's Consolidated Financial Statements since the transaction date.
The transaction was accounted for as a partial acquisition of EPIK through
the issuance of the stock of a consolidated subsidiary. The contributions
of PTC's and Caronet's net assets were recorded at their carrying values of
approximately $31 million. EPIK's contribution was recorded at its
estimated fair value of $22 million using the purchase method. No gain or
loss was recognized on the transaction. The EPIK purchase price was
initially allocated as follows: property and equipment - $27 million; other
current assets - $9 million; current liabilities - $21 million; and
goodwill - $7 million. During 2004, PT LLC developed a restructuring plan
to exit certain leasing arrangements of EPIK and finalized its valuation of
acquired assets and liabilities. Management considered a number of factors,
including valuations and appraisals, when making these determinations.
Based on the results of these activities, the preliminary purchase price
allocation for EPIK was revised as follows at December 31, 2004: property
and equipment - $36 million; other current assets - $7 million; intangible
assets - $1 million; current liabilities - $18 million; and exit costs - $4
million. The exit costs consist primarily of lease termination penalties
and noncancelable lease payments made after certain leased properties are
vacated. The pro forma results of operations reflecting the acquisition
would not be materially different than the reported results of operations
for 2003 or 2002.
B. Acquisition of Natural Gas Reserves
During 2003, Progress Fuels entered into several independent transactions
to acquire approximately 200 natural gas-producing wells with proven
reserves of approximately 190 billion cubic feet (Bcf) from Republic
Energy, Inc., and three other privately owned companies, all headquartered
in Texas. The total cash purchase price for the transactions was $168
million. The pro forma results of operations reflecting the acquisition
would not be materially different from the reported results of operations
for the years ended December 31, 2003 and 2002.
97
C. Wholesale Energy Contract Acquisition
In May 2003, PVI entered into a definitive agreement with Williams Energy
Marketing and Trading, a subsidiary of The Williams Companies, Inc., to
acquire a long-term full-requirements power supply agreement at fixed
prices with Jackson Electric Membership Corporation (Jackson), located in
Jefferson, Georgia. The agreement calls for a $188 million cash payment to
Williams Energy Marketing and Trading in exchange for assignment of the
Jackson supply agreement; the $188 million cash payment was recorded as an
intangible asset and is being amortized based on the economic benefit of
the contract (See Note 9). The power supply agreement terminates in 2015,
with a first refusal right to extend for five years. The agreement includes
the use of 640 megawatts (MW) of contracted Georgia System generation
comprised of nuclear, coal, gas and pumped-storage hydro resources. PVI
expects to supplement the acquired resources with open market purchases and
with its own intermediate and peaking assets in Georgia to serve Jackson's
forecasted 1,100 MW peak demand in 2005 growing to a forecasted 1,700 MW
demand by 2015.
D. Westchester Acquisition
In April 2002, Progress Fuels, a subsidiary of Progress Energy, acquired
100% of Westchester Gas Company (Westchester). During 2004 the name of the
company was changed to Winchester Energy Co. Ltd.. The acquisition included
approximately 215 natural gas-producing wells, 52 miles of intrastate gas
pipeline and 170 miles of gas-gathering systems located within a 25-mile
radius of Jonesville, Texas, on the Texas-Louisiana border.
The aggregate purchase price of approximately $153 million consisted of
cash consideration of approximately $22 million and the issuance of 2.5
million shares of Progress Energy common stock then valued at approximately
$129 million. The purchase price included approximately $2 million of
direct transaction costs. The final purchase price was allocated to oil and
gas properties, intangible assets, diversified business property, net
working capital and deferred tax liabilities for approximately $152
million, $9 million, $32 million, $5 million and $45 million, respectively.
The $9 million intangible assets relates to customer contracts (See Note
9). The acquisition has been accounted for using the purchase method of
accounting and, accordingly, the results of operations for Westchester have
been included in Progress Energy's Consolidated Financial Statements since
the date of acquisition. The pro forma results of operations reflecting the
acquisition would not be materially different from the reported results of
operations for the year ended December 31, 2002.
E. Generation Acquisition
In February 2002, PVI acquired 100% of two electric generating projects
located in Georgia from LG&E Energy Corp., a subsidiary of Powergen plc.
The two projects consist of 1) Walton County Power, LLC, in Monroe,
Georgia, a 460 MW natural gas-fired plant placed in service in June 2001
and 2) Washington County Power, LLC, in Washington County, Georgia, a 600
MW natural gas-fired plant placed in service in June 2003. The Walton and
Washington projects have been accounted for using the purchase method of
accounting and, accordingly, have been included in the Consolidated
Financial Statements since the acquisition date.
In the final allocation, the aggregate cash purchase price of approximately
$348 million was allocated to diversified business property, intangibles
and goodwill for $228 million, $56 million and $64 million, respectively
(See Note 9). Of the acquired intangible assets, $33 million was assigned
to tolling and power sale agreements with LG&E Energy Marketing, Inc., for
each project and $23 million was assigned to interconnection contracts.
Goodwill was assigned to the CCO segment and will be deductible for tax
purposes.
The pro forma results of operations reflecting the acquisition would not be
materially different from the reported results of operations for the year
ended December 31, 2002.
98
6. PROPERTY, PLANT AND EQUIPMENT
A. Utility Plant
The balances of electric utility plant in service at December 31 are listed
below, with a range of depreciable lives for each:
- -------------------------------------------------------------------------
(in millions) 2004 2003
- -------------------------------------------------------------------------
Production plant (7-33 years) $ 11,966 $ 12,044
Transmission plant (30-75 years) 2,282 2,167
Distribution plant (12-50 years) 6,749 6,432
General plant and other (8-75 years) 1,106 1,037
- -------------------------------------------------------------------------
Utility plant in service $ 22,103 $ 21,680
- -------------------------------------------------------------------------
Generally, electric utility plant at PEC and PEF, other than nuclear fuel,
is pledged as collateral for the first mortgage bonds of PEC and PEF,
respectively.
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income, and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The
composite AFUDC rate for PEC's electric utility plant was 7.2% in 2004,
4.0% in 2003 and 6.2% in 2002, respectively. The composite AFUDC rate for
PEF's electric utility plant was 7.8% in 2004, 2003 and 2002.
Depreciation provisions on utility plant, as a percent of average
depreciable property other than nuclear fuel, were 2.2%, 2.5% and 2.6% in
2004, 2003 and 2002, respectively. The depreciation provisions related to
utility plant were $463 million, $517 million and $488 million in 2004,
2003 and 2002, respectively. In addition to utility plant depreciation
provisions, depreciation and amortization expense also includes
decommissioning cost provisions, asset retirement obligation (ARO)
accretion, cost of removal provisions (See Note 6D), regulatory approved
expenses (See Note 8 and Note 22) and NC Clean Air Legislation amortization
(See Note 8B).
During 2004, PEC met the requirements of both the NCUC and the SCPSC for
the implementation of two depreciation studies that allowed the utility to
reduce the rates used to calculate depreciation expense. The annual
reduction in depreciation expense is approximately $82 million. The
reduction is due primarily to extended lives at each of PEC's nuclear
units. The new depreciation rates were effective January 1, 2004.
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE) and costs
associated with obligations to the DOE for the decommissioning and
decontamination of enrichment facilities, for the years ended December 31,
2004, 2003 and 2002 were $140 million, $143 million and $141 million,
respectively, and are included in fuel used for electric generation in the
Consolidated Statements of Income.
B. Diversified Business Property
The balances of diversified business property at December 31 are listed
below, with a range of depreciable lives for each:
99
- -------------------------------------------------------------------------------------------
(in millions) 2004 2003
- -------------------------------------------------------------------------------------------
Equipment (3-25 years) $ 383 $ 246
Nonregulated generation plant and equipment (3-40 years) 1,302 1,299
Land and mineral rights 107 93
Buildings and plants (5-40 years) 131 125
Oil and gas properties (units-of-production) 336 412
Telecommunications equipment (5-20 years) 80 63
Rail equipment (3-20 years) 29 125
Marine equipment (3-35 years) 87 83
Computers, office equipment and software (3-10 years) 36 36
Construction work in progress 26 13
Accumulated depreciation (507) (400)
- -------------------------------------------------------------------------------------------
Diversified business property, net $ 2,010 $ 2,095
- -------------------------------------------------------------------------------------------
The synthetic fuel facilities are being depreciated through 2007 when the
Section 29 tax credits will expire. The Company's nonregulated businesses
capitalize interest costs under SFAS No. 34, "Capitalization of Interest
Costs." During the years ended December 31, 2004, 2003 and 2002,
respectively, the Company capitalized $7 million, $20 million and $38
million, respectively, of its interest cost of $660 million, $655 million
and $679 million. Capitalized interest for 2004 is related to the expansion
of Fuels' gas operations. Capitalized interest in 2003 and 2002 is related
to the expansion of its nonregulated generation portfolio at PVI.
Capitalized interest is included in diversified business property, net on
the Consolidated Balance Sheets. Diversified business depreciation expense
was $148 million, $120 million and $85 million for December 31, 2004, 2003
and 2002, respectively.
C. Joint Ownership of Generating Facilities
PEC and PEF hold ownership interests in certain jointly owned generating
facilities. Each is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. Each
also pays its ownership share of additional construction costs, fuel
inventory purchases and operating expenses. PEC's and PEF's share of
expenses for the jointly owned facilities is included in the appropriate
expense category. The co-owner of Intercession City Unit P11 (P11) has
exclusive rights to the output of the unit during the months of June
through September. PEF has that right for the remainder of the year. PEC's
and PEF's ownership interests in the jointly owned generating facilities
are listed below with related information at December 31 ($ in millions):
- -----------------------------------------------------------------------------------------------------------------
2004 Company Construction
Ownership Plant Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Progress
- -----------------------------------------------------------------------------------------------------------------
PEC Mayo Plant 83.83% $ 516 $ 249 $ 1
PEC Harris Plant 83.83% 3,185 1,387 13
PEC Brunswick Plant 81.67% 1,624 888 28
PEC Roxboro Unit 4 87.06% 323 147 1
PEF Crystal River Unit 3 91.78% 889 443 9
PEF Intercession City Unit P11 66.67% 22 7 8
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
2003 Company Construction
Ownership Plant Accumulated Work in
Subsidiary Facility Interest Investment Depreciation Progress
- -----------------------------------------------------------------------------------------------------------------
PEC Mayo Plant 83.83% $ 464 $ 242 $ 50
PEC Harris Plant 83.83% 3,248 1,424 7
PEC Brunswick Plant 81.67% 1,611 885 21
PEC Roxboro Unit 4 87.06% 323 139 1
PEF Crystal River Unit 3 91.78% 875 442 46
PEF Intercession City Unit P11 66.67% 22 6 6
- -----------------------------------------------------------------------------------------------------------------
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Shearon Harris
Nuclear Plant (Harris Plant).
100
D. Asset Retirement Obligations
At December 31, 2004 and 2003, the asset retirement costs related to
nuclear decommissioning of irradiated plant, net of accumulated
depreciation, totaled $277 million and $354 million, respectively. Funds
set aside in the Company's nuclear decommissioning trust funds for the
nuclear decommissioning liability totaled $1.044 billion and $938 million
at December 31, 2004 and 2003, respectively. Net nuclear decommissioning
trust unrealized gains are included in regulatory liabilities (See Note
8A).
Decommissioning cost provisions, which are included in depreciation and
amortization expense, were $31 million in each of 2004, 2003 and 2002.
Management believes that decommissioning costs that have been and will be
recovered through rates by PEC and PEF will be sufficient to provide for
the costs of decommissioning. The Company's expenses recognized for the
disposal or removal of utility assets that are not SFAS No. 143 asset
removal obligations, which are included in depreciation and amortization
expense, were $160 million, $158 million and $149 million in 2004, 2003 and
2002, respectively.
The utilities recognize removal, nonirradiated decommissioning and
dismantlement costs in regulatory liabilities on the Consolidated Balance
Sheets (See Note 8A). At December 31, 2004, such costs consist of removal
costs of $1.606 billion, removal costs for nonirradiated areas at nuclear
facilities of $131 million and amounts previously collected for
dismantlement of fossil generation plants of $144 million. At December 31,
2003, such costs consist of removal costs of $1.846 billion, removal costs
for nonirradiated areas at nuclear facilities of $129 million and amounts
previously collected for dismantlement of fossil generation plants of $143
million. During 2004, PEC reduced its estimated removal costs to take into
account the estimates used in the depreciation studies implemented during
2004 (See Note 6A). This resulted in a downward revision in the PEC
estimated removal costs and equal increase in accumulated depreciation of
approximately $345 million.
PEC's most recent site-specific estimates of decommissioning costs were
developed in 2004, using 2004 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring after operating license expiration. These estimates, in 2004
dollars, are $294 million for Robinson Unit No. 2, $290 million for
Brunswick Unit No. 1, $313 million for Brunswick Unit No. 2 and $359
million for the Harris Plant. The estimates are subject to change based on
a variety of factors including, but not limited to, cost escalation,
changes in technology applicable to nuclear decommissioning and changes in
federal, state or local regulations. The cost estimates exclude the portion
attributable to North Carolina Eastern Municipal Power Agency (Power
Agency), which holds an undivided ownership interest in the Brunswick and
Harris nuclear generating facilities. NRC operating licenses held by PEC
currently expire in December 2014 and September 2016 for Brunswick Units 2
and 1, respectively. An application to extend these licenses 20 years was
submitted in October 2004. The NRC operating license held by PEC for the
Shearon Harris Nuclear Plant (Harris Plant) currently expires in October
2026. An application to extend this license 20 years is expected to be
submitted in the fourth quarter of 2006. On April 19, 2004, the NRC
announced that it has renewed the operating license for PEC's Robinson
Nuclear Plant (Robinson) for an additional 20 years through July 2030.
PEF's most recent site-specific estimate of decommissioning costs for the
Crystal River Nuclear Plant (CR3) was developed in 2000 based on prompt
dismantlement decommissioning. The estimate, in 2000 dollars, is $491
million and is subject to change based on the same factors as discussed
above for PEC's estimates. The cost estimate excludes the portion
attributable to other co-owners of CR3. The NRC operating license held by
PEF for Crystal River Unit No. 3 (CR3) currently expires in December 2016.
An application to extend this license 20 years is expected to be submitted
in the first quarter of 2009.
The Company has identified but not recognized AROs related to electric
transmission and distribution and telecommunications assets as the result
of easements over property not owned by the Company. These easements are
generally perpetual and require retirement action only upon abandonment or
cessation of use of the property for the specified purpose. The ARO is not
estimable for such easements, as the Company intends to utilize these
properties indefinitely. In the event the Company decides to abandon or
cease the use of a particular easement, an ARO would be recorded at that
time.
The Company's nonregulated AROs relate to coal mine operations, synthetic
fuel operations and gas production of Progress Fuels. The related asset
retirement costs, net of accumulated depreciation, totaled $10 million and
$5 million at December 31, 2004 and 2003, respectively.
101
The following table shows the changes to the asset retirement obligations.
Additions relate primarily to additional reclamation obligations at coal
mine operations of Progress Fuels. The deductions to regulated ARO related
to PEC re-measuring the nuclear decommissioning costs of irradiated plants
to take into account updated site-specific decommissioning cost studies,
which are required by the NCUC every five years.
- ------------------------------------------------------------------------------------------
(in millions) Regulated Nonregulated
- ------------------------------------------------------------------------------------------
Asset retirement obligations as of January 1, 2003 $ 1,183 $ 10
Additions - 11
Accretion expense 68 1
Deductions - (2)
- ------------------------------------------------------------------------------------------
Asset retirement obligations as of December 31, 2003 1,251 20
Additions - 6
Accretion expense 73 2
Deductions (63) (7)
- ------------------------------------------------------------------------------------------
Asset retirement obligations as of December 31, 2004 $ 1,261 $ 21
- ------------------------------------------------------------------------------------------
The cumulative effect of initial adoption of this statement related to
nonregulated operations was $1 million of income, which is included in
cumulative effect of change in accounting principles, net of tax on the
Consolidated Statements of Income for the year ended December 31, 2003. Pro
forma net income has not been presented for prior years because the pro
forma application of SFAS No. 143 to prior years would result in pro forma
net income not materially different from the actual amounts reported.
E. Insurance
PEC and PEF are members of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, each
company is insured for $500 million at each of its respective nuclear
plants. In addition to primary coverage, NEIL also provides
decontamination, premature decommissioning and excess property insurance
with limits of $2.0 billion on the Brunswick and Harris Plants, and $1.1
billion on the Robinson and Crystal River Unit No. 3 (CR3) Plants.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. Both PEC and PEF are insured under
NEIL, following a 12-week deductible period, for 52 weeks in the amount of
$3 million per week at the Brunswick and Harris Plants, $2.5 million per
week at the Robinson Plant and $4.5 million per week at the CR3 Plant. An
additional 110 weeks (71 weeks for CR3) of coverage is provided at 80% of
the above weekly amounts. For the current policy period, the companies are
subject to retrospective premium assessments of up to approximately $29.3
million with respect to the primary coverage, $32.4 million with respect to
the decontamination, decommissioning and excess property coverage, and
$20.2 million for the incremental replacement power costs coverage, in the
event covered losses at insured facilities exceed premiums, reserves,
reinsurance and other NEIL resources. Pursuant to regulations of the United
States Nuclear Regulatory Commission (NRC), each company's property damage
insurance policies provide that all proceeds from such insurance be
applied, first, to place the plant in a safe and stable condition after an
accident and, second, to decontaminate, before any proceeds can be used for
decommissioning, plant repair or restoration. Each company is responsible
to the extent losses may exceed limits of the coverage described above.
Both PEC and PEF are insured against public liability for a nuclear
incident up to $10.8 billion per occurrence. Under the current provisions
of the Price Anderson Act, which limits liability for accidents at nuclear
power plants, each company, as an owner of nuclear units, can be assessed
for a portion of any third-party liability claims arising from an accident
at any commercial nuclear power plant in the United States. In the event
that public liability claims from an insured nuclear incident exceed $300
million (currently available through commercial insurers), each company
would be subject to pro rata assessments of up to $101 million for each
reactor owned per occurrence. Payment of such assessments would be made
over time as necessary to limit the payment in any one year to no more than
$10 million per reactor owned. Congress could possibly approve revisions to
the Price Anderson Act during 2005 that could include increased limits and
assessments per reactor owned. The final outcome of this matter cannot be
predicted at this time.
102
Under the NEIL policies, if there were multiple terrorism losses occurring
within one year, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant.
If terrorism losses occurred beyond the one-year period, a new set of
limits and resources would apply. For nuclear liability claims arising out
of terrorist acts, the primary level available through commercial insurers
is now subject to an industry aggregate limit of $300 million. The second
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $300 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts.
PEC and PEF self-insure their transmission and distribution lines against
loss due to storm damage and other natural disasters. PEF accrues $6
million annually to a storm damage reserve pursuant to a regulatory order
and may defer losses in excess of the reserve (See Notes 3 and 8A).
7. CURRENT ASSETS
RECEIVABLES
At December 31, receivables were comprised of:
- ----------------------------------------------------------------------------
(in millions) 2004 2003
- ----------------------------------------------------------------------------
Trade accounts receivable $ 689 $ 705
Unbilled accounts receivable 271 293
Notes receivable 98 61
Other receivables 27 47
Unbilled other receivables 28 10
Allowance for doubtful accounts receivable (29) (32)
- ----------------------------------------------------------------------------
Total receivables $ 1,084 $ 1,084
- ----------------------------------------------------------------------------
Income tax receivables and interest income receivables are not included in
this classification. These amounts are in prepaids and other current assets
on the Consolidated Balance Sheet.
INVENTORY
At December 31, inventory was comprised of:
- ------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------
Fuel for production $ 235 $ 210
Inventory for sale 230 167
Materials and supplies 517 530
- ------------------------------------------------------------
Total inventory $ 982 $ 907
- ------------------------------------------------------------
8. REGULATORY MATTERS
A. Regulatory Assets and Liabilities
As regulated entities, the utilities are subject to the provisions of SFAS
No. 71. Accordingly, the utilities record certain assets and liabilities
resulting from the effects of the ratemaking process that would not be
recorded under GAAP for nonregulated entities. The utilities' ability to
continue to meet the criteria for application of SFAS No. 71 may be
affected in the future by competitive forces and restructuring in the
electric utility industry. In the event that SFAS No. 71 no longer applied
to a separable portion of the Company's operations, related regulatory
assets and liabilities would be eliminated unless an appropriate regulatory
recovery mechanism was provided. Additionally, these factors could result
in an impairment of utility plant assets as determined pursuant to SFAS No.
144.
103
At December 31, the balances of regulatory assets (liabilities) were as
follows:
- ---------------------------------------------------------------------------------------------------
(in millions) 2004 2003
- ---------------------------------------------------------------------------------------------------
Deferred fuel cost - current (Note 8B and 8C) $ 229 $ 270
- ---------------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 8B and 8C) 107 47
Deferred impact of ARO - PEC (Note 1D) 305 291
Income taxes recoverable through future rates (Note 15) 84 75
Loss on reacquired debt (Note 1D) 53 55
Deferred DOE enrichment facilities-related costs 16 24
Storm deferral (Notes 3 and 8B) 316 21
Postretirement benefits (Note 17) 74 9
Other 109 76
- ---------------------------------------------------------------------------------------------------
Total long-term regulatory assets 1,064 598
- ---------------------------------------------------------------------------------------------------
Deferred energy conservation cost - current (8) (7)
- ---------------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 6D) (1,881) (2,118)
Deferred impact of ARO (Note 1D) (221) (212)
Net nuclear decommissioning trust unrealized gains (Note 6D) (224) (204)
Postretirement benefits (Note 17B) (45) (211)
Storm reserve (Note 3) - (41)
Clean air compliance (Note 8B) (248) (74)
Other (35) (19)
- ---------------------------------------------------------------------------------------------------
Total long-term regulatory liabilities (2,654) (2,879)
- ---------------------------------------------------------------------------------------------------
Net regulatory assets (liabilities) $ (1,369) $ (2,018)
- ---------------------------------------------------------------------------------------------------
Except for portions of deferred fuel costs and deferred storm costs, all
regulatory assets earn a return or the cash has not yet been expended, in
which case the assets are offset by liabilities that do not incur a
carrying cost. The Company expects to fully recover these assets and refund
the liabilities through customer rates under current regulatory practice.
B. PEC Retail Rate Matters
As of December 31, 2004, PEC's North Carolina retail fuel costs were
underrecovered by $145 million. This amount is comprised of $117 million
eligible for recovery in 2005 and $28 million deferred from a 2001 order
from the NCUC that cannot be collected during 2005, and has therefore been
classified as a long-term asset. PEC intends to collect this amount by
October 31, 2007.
On October 15, 2004, the SCPSC approved PEC's request to leave fuel rates
unchanged. The deferred fuel balance at December 31, 2004, is $23 million.
This amount is eligible for recovery in PEC's 2005 South Carolina fuel
review.
PEC obtained SCPSC and NCUC approval of fuel factors in annual
fuel-adjustment proceedings. The NCUC approved an annual increase of $62
million, $20 million and $46 million by orders issued in September 2004,
2003 and 2002, respectively. The SCPSC approved PEC's petition each year
and the changes were insignificant.
PEC filed with the SCPSC seeking permission to defer expenses incurred from
the first quarter 2004 winter storm. The SCPSC approved PEC's request to
defer the costs and amortize them ratably over five years beginning in
January 2005. Approximately $9 million related to storm costs was deferred
in 2004.
In October 2003, PEC filed with the NCUC seeking permission to defer
expenses incurred from Hurricane Isabel and the February 2003 winter
storms. In December 2003, the NCUC approved PEC's request to defer the
costs associated with Hurricane Isabel and the February 2003 ice storm and
amortize them over a period of five years. PEC charged approximately $24
million in 2003 from Hurricane Isabel and from ice storms to the deferred
account. PEC recognized $5 million and $3 million of NC storm amortization
during 2004 and 2003, respectively.
104
The NCUC and SCPSC have approved proposals to accelerate cost recovery of
PEC's nuclear generating assets beginning January 1, 2000, and continuing
through 2009. The aggregate minimum and maximum amounts of cost recovery
are $530 million and $750 million, respectively. Accelerated cost recovery
of these assets resulted in no additional expense in 2004 and 2003 and
additional depreciation expense of approximately $53 million in 2002. Total
accelerated depreciation recorded through December 31, 2004, was $403
million.
The North Carolina Clean Smokestacks Act enacted in June 2002 (NC Clean
Air), requires state utilities to reduce emissions of nitrogen oxide (NOx)
and sulfur dioxide (SO2) from coal-fired plants. The NCUC has allowed the
utilities to amortize and recover the costs associated with meeting the new
emission standards over a seven-year period beginning January 1, 2003. The
legislation provides for significant flexibility in the amount of annual
amortization recorded, which allows the utilities to vary the amount
amortized within certain limits. This flexibility provides a utility with
the opportunity to consider the impacts of other factors on its regulatory
return on equity when setting the amortization amount for each year. PEC
recognized $174 million and $74 million of clean air amortization during
2004 and 2003, respectively. This legislation freezes PEC's base rates in
North Carolina for five years, subject to certain conditions (See Note 22).
In conjunction with the FPC merger, PEC reached a settlement with the
Public Staff of the NCUC in which it agreed to provide credits to its
nonreal time pricing customers in the amounts of $3 million in 2002, $5
million in 2003 and $6 million in both 2004 and 2005.
In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek
a base retail electric rate increase in North Carolina and South Carolina
through December 2004. The agreement not to seek a base retail electric
rate increase in South Carolina was extended to December 2005 in
conjunction with regulatory approval to form a holding company.
C. PEF Retail Rate Matters
On November 9, 2004, the FPSC approved PEF's underrecovered fuel costs of
$156 million for 2004, of which PEF plans to defer $79 million until 2006
to mitigate the impact on customers resulting from the need to also recover
hurricane-related costs. Therefore, $79 million of deferred fuel costs has
been classified as a long-term asset. As of December 31, 2004, PEF was
underrecovered in fuel costs by $168 million. The additional $12 million
over and above the $156 million approved by the FPSC will be included in
PEF's 2005 fuel filing.
On June 29, 2004, the FPSC approved a Stipulation and Settlement Agreement,
executed on April 29, 2004, by PEF, the Office of Public Counsel and the
Florida Industrial Power Users Group. The stipulation and settlement
resolved the issue pending before the FPSC regarding the costs PEF will be
allowed to recover through its Fuel and Purchased Power Cost Recovery
clause in 2004 and beyond for waterborne coal deliveries by the Company's
affiliated coal supplier, Progress Fuels Corporation. The settlement sets
fixed per ton prices based on point of origin for all waterborne coal
deliveries in 2004, and establishes a market-based pricing methodology for
determining recoverable waterborne coal transportation costs through a
competitive solicitation process or market price proxies in 2005 and
thereafter. The settlement reduces the amount that PEF will charge to the
Fuel and Purchased Power Cost Recovery clause for waterborne transportation
by approximately $11 million beginning in 2004.
On November 3, 2004, the FPSC approved PEF's petition for Determination of
Need for the construction of a fourth unit at PEF's Hines Energy Complex.
Hines Unit 4 is needed to maintain electric system reliability and
integrity and to continue to provide adequate electricity to its ratepayers
at a reasonable cost. Hines Unit 4 will be a combined cycle unit with a
generating capacity of 461 MW (summer rating). The estimated total
in-service cost of Hines Unit 4 is $286 million, and the unit is planned
for commercial operation in December 2007. If the actual cost is less than
the estimate, customers will receive the benefit of such cost underruns.
Any costs that exceed this estimate will not be recoverable absent
extraordinary circumstances as found by the FPSC in subsequent proceedings.
See Note 3 for information on PEF's petition for storm cost recovery.
105
PEF RATE CASE SETTLEMENT
The FPSC initiated a rate proceeding in 2001 regarding PEF's future base
rates. In March 2002, the parties in PEF's rate case entered into a
Stipulation and Settlement Agreement (the Agreement) related to retail rate
matters. The Agreement was approved by the FPSC in April 2002. The
Agreement is generally effective from May 2002 through December 2005,
provided, however, that if PEF's base rate earnings fall below a 10% return
on equity, PEF may petition the FPSC to amend its base rates.
The Agreement provides that PEF will reduce its retail revenues from the
sale of electricity by an annual amount of $125 million. The Agreement also
provides that PEF will operate under a Revenue Sharing Incentive Plan (the
Plan) through 2005, and thereafter until terminated by the FPSC, that
establishes annual revenue caps and sharing thresholds. The Plan provides
that retail base rate revenues between the sharing thresholds and the
retail base rate revenue caps will be divided into two shares - a 1/3 share
to be received by PEF's shareholders, and a 2/3 share to be refunded to
PEF's retail customers, provided, however, that for the year 2002 only, the
refund to customers was limited to 67.1% of the 2/3 customer share. The
retail base rate revenue sharing threshold amounts for 2004, 2003 and 2002
were $1.370 billion, $1.333 billion and $1.296 billion, respectively, and
will increase $37 million in 2005. The Plan also provides that all retail
base rate revenues above the retail base rate revenue caps established for
each year will be refunded to retail customers on an annual basis. For
2002, the refund to customers was limited to 67.1% of the retail base rate
revenues that exceeded the 2002 cap. The retail base revenue caps for 2004,
2003 and 2002 were $1.430 billion, $1.393 billion and $1.356 billion,
respectively, and will increase $37 million in 2005. Any amounts above the
retail base revenue caps will be refunded 100% to customers. At December
31, 2004, $9 million has been accrued and will be refunded to retail
customers by March 2005. The 2003 revenue sharing amount was $18 million,
and was refunded to customers by April 30, 2004. Approximately $5 million
was originally returned in March 2003 related to 2002 revenue sharing.
However, in February 2003, the parties to the Agreement filed a motion
seeking an order from the FPSC to enforce the Agreement. In this motion,
the parties disputed PEF's calculation of retail revenue subject to refund
and contended that the refund should be approximately $23 million. In July
2003, the FPSC ruled that PEF must provide an additional $18 million to its
retail customers related to the 2002 revenue sharing calculation. PEF
recorded this refund in the second quarter of 2003 as a charge against
electric operating revenue and refunded this amount by October 2003.
The Agreement also provides that beginning with the in-service date of
PEF's Hines Unit 2 and continuing through December 2005, PEF will be
allowed to recover through the fuel cost recovery clause a return on
average investment and depreciation expense for Hines Unit 2, to the extent
such costs do not exceed the Unit's cumulative fuel savings over the
recovery period. Hines Unit 2 is a 516 MW combined-cycle unit that was
placed in service in December 2003. In 2004, PEF recovered $36 million
through this clause related to Hines Unit 2.
In addition, PEF suspended retail accruals on its reserves for nuclear
decommissioning and fossil dismantlement through December 2005.
Additionally, for each calendar year during the term of the Agreement, PEF
will record a $63 million depreciation expense reduction and may, at its
option, record up to an equal annual amount as an offsetting accelerated
depreciation expense. No accelerated depreciation expense was recorded
during 2004 and 2003. In addition, PEF is authorized, at its discretion, to
accelerate the amortization of certain regulatory assets over the term of
the Agreement.
Under the terms of the Agreement, PEF agreed to continue the implementation
of its four-year Commitment to Excellence Reliability Plan and expected to
achieve a 20% improvement in its annual System Average Interruption
Duration Index by no later than 2004. If this improvement level was not
achieved for calendar years 2004 or 2005, PEF would have provided a refund
of $3 million for each year the level is not achieved to 10% of its total
retail customers served by its worst performing distribution feeder lines.
PEF achieved this improvement level in 2004.
In January 2005, in anticipation of the expiration of its Stipulation and
Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate
case, PEF notified the FPSC that it intends to request an increase in its
base rates, effective January 1, 2006. In its notice, PEF requested the
FPSC to approve calendar year 2006 as the projected test period for setting
new base rates. The request for increased base rates is based on the fact
that PEF has faced significant cost increases over the past decade and
expects its operational costs to continue to increase. These costs include
the costs associated with completion of the Hines 3 generation facility,
extraordinary hurricane damage costs including capital costs which are not
expected to be directly recoverable, the need to replenish the depleted
storm reserve and the expected infrastructure investment necessary to meet
high customer expectations, coupled with the demands placed on PEF as a
result of strong customer growth. On February 7, 2005, the FPSC
acknowledged receipt of PEF's notice and authorized minimum filing
requirements and testimony to be filed May 1, 2005.
106
D. Regional Transmission Organizations and Standard Market Design
In 2000, the Federal Energy Regulatory Commission (FERC) issued Order No.
2000 regarding regional transmission organizations (RTOs). This Order set
minimum characteristics and functions that RTOs must meet, including
independent transmission service. In July 2002, the FERC issued its Notice
of Proposed Rulemaking in Docket No. RM01-12-000, Remedying Undue
Discrimination through Open Access Transmission Service and Standard
Electricity Market Design (SMD NOPR). If adopted as proposed, the rules set
forth in the SMD NOPR would have materially altered the manner in which
transmission and generation services are provided and paid for. In April
2003, the FERC released a White Paper on the Wholesale Market Platform. The
White Paper provided an overview of what the FERC intended to include in a
final rule in the SMD NOPR docket. The White Paper retained the fundamental
and most protested aspects of SMD NOPR, including mandatory RTOs and the
FERC's assertion of jurisdiction over certain aspects of retail service.
The FERC has not yet issued a final rule on SMD NOPR. The Company cannot
predict the outcome of these matters or the effect that they may have on
the GridSouth and GridFlorida proceedings currently ongoing before the
FERC. By order issued December 22, 2004, the FERC terminated a portion of
the proceedings regarding GridSouth. The GridSouth Companies asked the FERC
for further clarification as to the portions of the GridSouth docket it
intended to address. On March 2, 2005, the FERC affirmed that it only
intended to close the mediation portion of the GridSouth docket. It is
unknown what impact the future proceedings will have on the Company's
earnings, revenues or prices.
The Florida Public Service Commission (FPSC) ruled in December 2001 that
the formation of GridFlorida by the three major investor-owned utilities in
Florida, including PEF, was prudent but ordered changes in the structure
and market design of the proposed organization. In September 2002, the FPSC
set a hearing for market design issues; this order was appealed to the
Florida Supreme Court by the consumer advocate of the state of Florida. In
June 2003, the Florida Supreme Court dismissed the appeal without
prejudice. In September 2003, the FERC held a Joint Technical Conference
with the FPSC to consider issues related to formation of an RTO for
peninsular Florida. In December 2003, the FPSC ordered further state
proceedings and established a collaborative workshop process to be
conducted during 2004. In June 2004, the workshop process was abated
pending completion of a cost-benefit study currently scheduled to be
presented at a FPSC workshop on May 25, 2005, with subsequent action by the
FPSC to be thereafter determined.
The Company has $33 million and $4 million invested in GridSouth and
GridFlorida, respectively, related to startup costs at December 31, 2004.
The Company expects to recover these startup costs in conjunction with the
GridSouth and GridFlorida original structures or in conjunction with any
alternate combined transmission structures that emerge.
E. FERC Market Power Mitigation
A FERC order issued in November 2001 on certain unaffiliated utilities'
triennial market-based wholesale power rate authorization updates required
certain mitigation actions that those utilities would need to take for
sales/purchases within their control areas and required those utilities to
post information on their Web sites regarding their power systems' status.
As a result of a request for rehearing filed by certain market
participants, FERC issued an order delaying the effective date of the
mitigation plan until after a planned technical conference on market power
determination. In December 2003, the FERC issued a staff paper discussing
alternatives and held a technical conference in January 2004. In April
2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market
power of applicants for wholesale market-based rates, and described
additional analyses and mitigation measures that could be presented if an
applicant does not pass one of these interim screens. In July 2004, the
FERC issued an order on rehearing affirming its conclusions in the April
order. In the second order, the FERC initiated a rulemaking to consider
whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based
rates should be modified in any way. PEF does not have market-based rate
authority for wholesale sales in peninsular Florida. Given the difficulty
PEC believes it would experience in passing one of the interim screens, on
August 12, 2004, PEC notified the FERC that it would revise its
Market-based Rate tariff to restrict it to sales outside PEC's control area
and file a new cost-based tariff for sales within PEC's control area that
incorporates the FERC's default cost-based rate methodologies for sales of
one year or less. PEC anticipates making this filing in the first quarter
of 2005. PEC does not anticipate that the current operations will be
materially impacted by this change. Although the Company cannot predict the
ultimate outcome of these changes, the Company does not anticipate that the
current operations of PEC or PEF would be impacted materially if they were
unable to sell power at market-based rates in their respective control
areas.
107
F. Energy Delivery Capitalization Practice
The Company has reviewed its capitalization policies for its Energy
Delivery business units in PEC and PEF. That review indicated that in the
areas of outage and emergency work not associated with major storms and
allocation of indirect costs, both PEC and PEF should revise the way that
they estimate the amount of capital costs associated with such work. The
Company has implemented such changes effective January 1, 2005, which
include more detailed classification of outage and emergency work and
result in more precise estimation and a process of retesting accounting
estimates on an annual basis. As a result of the changes in accounting
estimates for the outage and emergency work and indirect costs, a lesser
proportion of PEC's and PEF's costs will be capitalized on a prospective
basis. The Company estimates that the combined impact for both utilities in
2005 will be that approximately $55 million of costs that would have been
capitalized under the previous policies will be expensed. Pursuant to SFAS
No. 71, PEC and PEF have informed the state regulators having jurisdiction
over them of this change and that the new estimation process will be
implemented effective January 1, 2005. The Company has also requested a
method change from the IRS.
9. GOODWILL AND OTHER INTANGIBLE ASSETS
The Company performed the annual goodwill impairment test in accordance
with FASB Statement No. 142, Goodwill and Other Intangible Assets, for the
CCO segment in the first quarter of 2004, and the annual goodwill
impairment test for the PEC Electric and PEF segments in the second quarter
of 2004, each of which indicated no impairment.
The changes in the carrying amount of goodwill, by reportable segment, are
as follows:
- -------------------------------------------------------------------------------------------------------------
Corporate
(in millions) PEC Electric PEF CCO and Other Total
- -------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2003 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
Acquisitions - - - 7 7
- -------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2003 $ 1,922 $ 1,733 $ 64 $ 7 $ 3,726
Purchase accounting adjustment - - - (7) (7)
- -------------------------------------------------------------------------------------------------------------
Balance as of December 31, 2004 $ 1,922 $ 1,733 $ 64 $ - $ 3,719
- -------------------------------------------------------------------------------------------------------------
In December 2003, $7 million in goodwill was recorded based on a
preliminary purchase price allocation as part of the Progress
Telecommunications Corporation partial acquisition of EPIK and was reported
in the Other segment. As discussed in Note 5A, the Company revised the
preliminary EPIK purchase price allocation as of September 2004, and the $7
million of goodwill was reallocated to certain tangible assets acquired
based on the results of valuations and appraisals.
The gross carrying amount and accumulated amortization of the Company's
intangible assets at December 31 are as follows:
- ----------------------------------------------------------------------------------------------------------
2004 2003
---------------------------------- ------------------------------------
Gross Carrying Accumulated Gross Carrying Accumulated
(in millions) Amount Amortization Amount Amortization
- ----------------------------------------------------------------------------------------------------------
Synthetic fuel intangibles $ 134 $ (80) $ 140 $ (64)
Power agreements acquired 221 (39) 221 (20)
Other 119 (18) 93 (13)
- ----------------------------------------------------------------------------------------------------------
Total $ 474 $(137) $ 454 $ (97)
- ----------------------------------------------------------------------------------------------------------
In June 2004, the Company sold, in two transactions, a combined 49.8%
partnership interest in Colona Synfuel Limited Partnership, LLLP, one of
its synthetic fuel operations. Approximately $6 million in synthetic fuel
intangibles and $3 million in related accumulated amortization were
included in the basis of the partnership interest sold.
All of the Company's intangibles are subject to amortization. Synthetic
fuel intangibles represent intangibles for synthetic fuel technology. These
intangibles are being amortized on a straight-line basis until the
expiration of tax credits under Section 29 of the Internal Revenue Code
(Section 29) in December 2007 (See Note 23E). The intangibles related to
power agreements acquired are being amortized based on the economic
108
benefits of the contracts (See Notes 5C and 5D). Other intangibles are
primarily acquired customer contracts and permits that are amortized over
their respective lives. Of the increase in other intangible assets, $24
million resulted from the minimum pension liability adjustment at December
31, 2004 (See Note 17).
Amortization expense recorded on intangible assets for the years ended
December 31, 2004, 2003 and 2002 was, in millions, $42, $37 and $33,
respectively. The estimated annual amortization expense for intangible
assets for 2005 through 2009, in millions, is approximately $35, $36, $36,
$18 and $18, respectively.
10. IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS
The Company applies SFAS No. 144 for the accounting and reporting of
impairment or disposal of long-lived assets. In 2003 and 2002, the Company
recorded pre-tax long-lived asset and investment impairments and other
charges of approximately $38 million and $414 million, respectively.
A. Long-Lived Assets
Due to the reduction in coal production, the Company evaluated Kentucky May
coal mine's long-lived assets in 2003. Fair value was determined based on
discounted cash flows. As a result of this review, the Company recorded
asset impairments of $17 million on a pre-tax basis during the fourth
quarter of 2003.
An estimated impairment of assets held for sale of $59 million is included
in the 2002 amount, which relates to Railcar Ltd. (See Note 4C).
Due to the decline of the telecommunications industry and continued
operating losses, the Company initiated an independent valuation study
during 2002 to assess the recoverability of the long-lived assets of PTC
and Caronet. Based on this assessment, the Company recorded asset
impairments of $305 million on a pre-tax basis and other charges of $25
million on a pre-tax basis primarily related to inventory adjustments in
the third quarter of 2002. This write-down constitutes a significant
reduction in the book value of these long-lived assets.
The long-lived asset impairments include an impairment of property, plant
and equipment, construction work in process and intangible assets. The
impairment charge represents the difference between the fair value and
carrying amount of these long-lived assets. The fair value of these assets
was determined using a valuation study heavily weighted on the discounted
cash flow methodology, using market approaches as supporting information.
B. Investments
The Company continually reviews its investments to determine whether a
decline in fair value below the cost basis is other than temporary. In
2003, PEC's affordable housing investment (AHI) portfolio was reviewed and
deemed to be impaired based on various factors including continued
operating losses of the AHI portfolio and management performance issues
arising at certain properties within the AHI portfolio. As a result, PEC
recorded an impairment of $18 million on a pre-tax basis during the fourth
quarter of 2003. PEC also recorded an impairment of $3 million for a cost
investment.
In May 2002, Interpath Communication, Inc., merged with a third party. As a
result, the Company reviewed the Interpath investment for impairment and
wrote off the remaining amount of its cost-basis investment in Interpath,
recording a pre-tax impairment of $25 million in the third quarter of 2002.
In the fourth quarter of 2002, the Company sold its remaining interest in
Interpath for a nominal amount.
11. EQUITY
A. Common Stock
At December 31, 2004, the Company had approximately 63 million shares of
common stock authorized by the Board of Directors that remained unissued
and reserved, primarily to satisfy the requirements of the Company's stock
plans. In 2002, the Board of Directors authorized meeting the requirements
of the Progress Energy 401(k) Savings and Stock Ownership Plan and the
Investor Plus Stock Purchase Plan with original issue shares. During 2004,
2003 and 2002, respectively, the Company issued approximately 1 million, 8
million and 2 million shares under these plans for net proceeds of
approximately $62 million, $305 million and $86 million. The Company
continues to meet the requirements of the restricted stock plan with issued
and outstanding shares.
109
In November 2002, the Company issued 14.7 million shares of common stock
for net cash proceeds of approximately $600 million, which were primarily
used to retire commercial paper. In April 2002, the Company issued 2.5
million shares of common stock, valued at approximately $129 million, in
conjunction with the purchase of Westchester (See Note 5D).
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. At December 31, 2004,
there were no significant restrictions on the use of retained earnings.
B. Stock-Based Compensation
EMPLOYEE STOCK OWNERSHIP PLAN
The Company sponsors the Progress Energy 401(k) Savings and Stock Ownership
Plan (401(k)) for which substantially all full-time nonbargaining unit
employees and certain part-time nonbargaining unit employees within
participating subsidiaries are eligible. Participating subsidiaries within
the Company as of January 1, 2003, were PEC, PEF, PTC, Progress Fuels
(Corporate) and Progress Energy Service Company. Effective December 19,
2003, (the PT LLC/EPIK merger date), PTC no longer participates in the
401(k) plan. The 401(k), which has Company matching and incentive goal
features, encourages systematic savings by employees and provides a method
of acquiring Company common stock and other diverse investments. The
401(k), as amended in 1989, is an Employee Stock Ownership Plan (ESOP) that
can enter into acquisition loans to acquire Company common stock to satisfy
401(k) common share needs. Qualification as an ESOP did not change the
level of benefits received by employees under the 401(k). Common stock
acquired with the proceeds of an ESOP loan is held by the 401(k) Trustee in
a suspense account. The common stock is released from the suspense account
and made available for allocation to participants as the ESOP loan is
repaid. Such allocations are used to partially meet common stock needs
related to Company matching and incentive contributions and/or reinvested
dividends. All or a portion of the dividends paid on ESOP suspense shares
and on ESOP shares allocated to participants may be used to repay ESOP
acquisition loans. To the extent used to repay such loans, the dividends
are deductible for income tax purposes. Also, beginning in 2002, the
dividends paid on ESOP shares that are either paid directly to participants
or used to purchase additional shares, which are then allocated to
participants, are fully deductible for income tax purposes.
There were 3.5 million and 4.0 million ESOP suspense shares at December 31,
2004 and 2003, respectively, with a fair value of $156 million and $183
million, respectively. ESOP shares allocated to plan participants totaled
12.6 million and 13.1 million in December 31, 2004 and 2003, respectively.
The Company's matching and incentive goal compensation cost under the
401(k) is determined based on matching percentages and incentive goal
attainment as defined in the plan. Such compensation cost is allocated to
participants' accounts in the form of Company common stock, with the number
of shares determined by dividing compensation cost by the common stock
market value at the time of allocation. The Company currently meets common
stock share needs with open market purchases, with shares released from the
ESOP suspense account and with newly issued shares. Costs for incentive
goal compensation are accrued during the fiscal year and typically paid in
shares in the following year, while costs for the matching component are
typically met with shares in the same year incurred. Matching and incentive
costs, which were met and will be met with shares released from the
suspense account, totaled approximately $21 million, $20 million and $20
million for the years ended December 31, 2004, 2003 and 2002, respectively.
Total matching and incentive cost totaled approximately $32 million, $35
million and $30 million for the years ended December 31, 2004, 2003 and
2002, respectively. The Company has a long-term note receivable from the
401(k) Trustee related to the purchase of common stock from the Company in
1989. The balance of the note receivable from the 401(k) Trustee is
included in the determination of unearned ESOP common stock, which reduces
common stock equity. ESOP shares that have not been committed to be
released to participants' accounts are not considered outstanding for the
determination of earnings per common share. Interest income on the note
receivable and dividends on unallocated ESOP shares are not recognized for
financial statement purposes.
STOCK OPTION AGREEMENTS
Pursuant to the Company's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, amended and restated as of July 10, 2002, the Company may
grant options to purchase shares of common stock to directors, officers and
eligible employees for up to 5 million and 15 million shares, respectively.
Generally, options granted to employees vest one-third per year with 100%
vesting at the end of year three, while options granted to directors vest
100% at the end of one year. The options expire 10 years from the date of
grant. All option grants have an exercise price equal to the fair market
value of the Company's common stock on the grant date. The Company measures
compensation expense for stock options as the difference between the market
price of its common stock and the exercise price of the option at the grant
date. The exercise price at which options are granted by the Company equals
the market price at grant date and, accordingly, no compensation expense
has been recognized for any options granted during 2004, 2003 and 2002. The
110
Company will begin expensing stock options on July 1, 2005, based on SFAS
No. 123R (See Note 2). In 2004, however, the Company made the decision to
cease granting stock options and intends to replace that compensation
program with other programs. Therefore, the amount of stock option expense
expected to be recorded in 2005 is below the amount that would have been
recorded if the stock option program had continued.
The pro forma information presented in Note 1 regarding net income and
earnings per share is required by SFAS No. 148. Under this statement,
compensation cost is measured at the grant date based on the fair value of
the award and is recognized over the vesting period. The pro forma amounts
presented in Note 1 have been determined as if the Company had accounted
for its employee stock options under SFAS No. 123. The fair value for these
options was estimated at the date of grant using a Black-Scholes option
pricing model with the following weighted-average assumptions:
---------------------------------------------------------------------------------------------
2004 2003 2002
---------------------------------------------------------------------------------------------
Risk-free interest rate 4.22% 4.25% 4.14%
Dividend yield 5.19% 4.75% 5.20%
Volatility factor 20.30% 22.28% 24.98%
Weighted-average expected life of the options (in years) 10 10 10
---------------------------------------------------------------------------------------------
The option valuation model requires the input of highly subjective
assumptions, primarily stock price volatility, changes in which can
materially affect the fair value estimate.
The options outstanding at December 31, 2004, 2003 and 2002 had a
weighted-average remaining contractual life of 7.6, 8.7 and 9.3 years,
respectively, and had exercise prices that ranged from $40.41 to $51.85.
The tabular information for the option activity is as follows:
- ----------------------------------------------------------------------------------------------------------------------
2004 2003 2002
---------------------------------------------------------------------------
Weighted- Weighted- Weighted-
Number of Average Number of Average Number of Average
Options Exercise Options Exercise Options Exercise
(option quantities in millions) Price Price Price
- ----------------------------------------------------------------------------------------------------------------------
Options outstanding, January 1 8.0 $ 43.54 5.2 $ 42.84 2.3 $ 43.49
Granted - - 3.0 $ 44.70 2.9 $ 42.34
Forfeited (0.1) $ 43.76 (0.1) $ 43.64 - $ 43.71
Canceled (0.1) $ 43.67 (0.1) $ 43.62 - -
Exercised (0.4) $ 42.82 - $ 43.00 - -
Options outstanding, December 31 7.4 $ 43.57 8.0 $ 43.54 5.2 $ 42.84
Options exercisable, December 31
with a remaining contractual life of
7.6 years 4.6 $ 43.35 2.4 $ 43.09 0.8 $ 43.49
Weighted-average grant date fair value
of options granted during the year - $ 7.16 $ 6.83
- ----------------------------------------------------------------------------------------------------------------------
OTHER STOCK-BASED COMPENSATION PLANS
The Company has additional compensation plans for officers and key
employees of the Company that are stock-based in whole or in part. The two
primary active stock-based compensation programs are the Performance Share
Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of
which were established pursuant to the Company's 1997 Equity Incentive Plan
and were continued under the Company's 2002 Equity Incentive Plan, as
amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees of the Company are
granted performance shares on an annual basis that vest over a three-year
consecutive period. Each performance share has a value that is equal to,
and changes with, the value of a share of the Company's common stock, and
dividend equivalents are accrued on, and reinvested in, the performance
shares. The PSSP has two equally weighted performance measures, both of
which are based on the Company's results as compared to a peer group of
utilities. Compensation expense is recognized over the vesting period based
on the expected ultimate cash payout and is reduced by any forfeitures.
Effective January 1, 2005, new awards granted pursuant to the PSSP will be
payable in Company common stock rather than in cash.
111
The RSA program allows the Company to grant shares of restricted common
stock to officers and key employees of the Company. The restricted shares
generally vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period, with
corresponding increases in common stock equity. The weighted-average price
of restricted shares at the grant date was $46.95, $39.53 and $44.27 in
2004, 2003 and 2002, respectively. Compensation expense is reduced by any
forfeitures. Restricted shares are not included as shares outstanding in
the basic earnings per share calculation until the shares are no longer
forfeitable. Changes in restricted stock shares outstanding were:
- --------------------------------------------------------------
2004 2003 2002
- --------------------------------------------------------------
Beginning balance 944,883 950,180 674,511
Granted 154,500 180,200 365,920
Vested (367,107) (151,677) (75,200)
Forfeited (87,100) (33,820) (15,051)
- --------------------------------------------------------------
Ending balance 645,176 944,883 950,180
- --------------------------------------------------------------
The total amount expensed for other stock-based compensation plans was $10
million, $27 million and $17 million in 2004, 2003 and 2002, respectively.
C. Earnings Per Common Share
Basic earnings per common share is based on the weighted-average number of
common shares outstanding. Diluted earnings per share includes the effect
of the nonvested portion of restricted stock awards and the effect of stock
options outstanding.
A reconciliation of the weighted-average number of common shares
outstanding for basic and dilutive purposes is as follows:
- ---------------------------------------------------------------------------
(in millions) 2004 2003 2002
- ---------------------------------------------------------------------------
Weighted-average common shares - basic 242.2 237.2 217.2
Restricted stock awards .8 1.0 .8
Stock options .1 - .2
- ---------------------------------------------------------------------------
Weighted-average shares - fully diluted 243.1 238.2 218.2
- ---------------------------------------------------------------------------
There are no adjustments to net income or to income from continuing
operations between the calculations of basic and fully diluted earnings per
common share. ESOP shares that have not been committed to be released to
participants' accounts are not considered outstanding for the determination
of earnings per common share. The weighted-average of these shares totaled
3.6 million, 4.1 million and 4.8 million for the years ended December 31,
2004, 2003 and 2002, respectively. There were 3.0 million, 5.3 million and
92 thousand stock options outstanding at December 31, 2004, 2003 and 2002,
respectively, which were not included in the weighted-average number of
shares for computing the fully diluted earnings per share because they were
antidilutive.
D. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows:
- -----------------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------------
Loss on cash flow hedges $ (28) $ (36)
Minimum pension liability adjustments (142) (16)
Foreign currency translation and other 6 2
- -----------------------------------------------------------------------------
Total accumulated other comprehensive loss $ (164) $ (50)
- -----------------------------------------------------------------------------
112
12. PREFERRED STOCK OF SUBSIDIARIES - NOT SUBJECT TO MANDATORY REDEMPTION
All of the Company's preferred stock was issued by its subsidiaries and was
not subject to mandatory redemption. Preferred stock outstanding at
December 31, 2004 and 2003 consisted of the following:
- ---------------------------------------------------------------------------------------------------------------
(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
- ---------------------------------------------------------------------------------------------------------------
13. DEBT AND CREDIT FACILITIES
A. Debt and Credit Facilities
At December 31, the Company's long-term debt consisted of the following
(maturities and weighted-average interest rates at December 31, 2004):
113
- -----------------------------------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------------------------------
Progress Energy, Inc.
Senior unsecured notes, maturing 2006-2031 6.90% $ 4,300 $ 4,800
Draws on revolving credit agreement, expiring 2009 3.19% 160 -
Unamortized fair value hedge gain, net 12 19
Unamortized premium and discount, net (23) (27)
- -----------------------------------------------------------------------------------------------
4,449 4,792
- -----------------------------------------------------------------------------------------------
Progress Energy Carolinas, Inc.
First mortgage bonds, maturing 2005-2033 6.33% 1,600 1,900
Pollution control obligations, maturing 2017-2024 1.98% 669 708
Unsecured notes, maturing 2012 6.50% 500 500
Medium-term notes, maturing 2008 6.65% 300 300
Unamortized premium and discount, net (19) (22)
- -----------------------------------------------------------------------------------------------
3,050 3,386
- -----------------------------------------------------------------------------------------------
Progress Energy Florida, Inc.
First mortgage bonds, maturing 2008-2033 5.60% 1,330 1,330
Pollution control obligations, maturing 2018-2027 1.67% 241 241
Medium-term notes, maturing 2005-2028 6.76% 337 379
Draws on revolving credit agreement, expiring 2006 2.95% 55 -
Unamortized premium and discount, net (3) (3)
- -----------------------------------------------------------------------------------------------
1,960 1,947
- -----------------------------------------------------------------------------------------------
Florida Progress Funding Corporation (See Note 19)
Debt to affiliated trust, maturing 2039 7.10% 309 309
Unamortized premium and discount, net (39) (39)
- -----------------------------------------------------------------------------------------------
270 270
- -----------------------------------------------------------------------------------------------
Progress Capital Holdings, Inc.
Medium-term notes, maturing 2006-2008 6.84% 140 165
Miscellaneous notes 1 1
- -----------------------------------------------------------------------------------------------
141 166
- -----------------------------------------------------------------------------------------------
Progress Genco Ventures, LLC
Variable rate project financing, maturing 2007 - 241
- -----------------------------------------------------------------------------------------------
Current portion of long-term debt (349) (868)
- -----------------------------------------------------------------------------------------------
Total long-term debt $ 9,521 $ 9,934
- -----------------------------------------------------------------------------------------------
At December 31, 2004, the Company had committed lines of credit used to
support its commercial paper borrowings. The Progress Energy five-year
credit facility and the PEF three-year credit facility are included in
long-term debt. All other credit facilities are included in short-term
obligations. At December 31, 2004, the Company had $260 million outstanding
under its credit facilities classified as short-term obligations at a
weighted-average interest rate of 3.18%. No amount was outstanding under
the Company's committed lines of credit at December 31, 2003. The Company
is required to pay minimal annual commitment fees to maintain its credit
facilities.
The following table summarizes the Company's credit facilities:
--------------------------------------------------------------------------------------------------------------
(in millions)
Company Description Total Outstanding Available
--------------------------------------------------------------------------------------------------------------
Progress Energy, Inc. 5-Year (expiring 8/5/09) $ 1,130 $ 160 $ 970
Progress Energy Carolinas, Inc. 364-Day (expiring 7/27/05) 165 90 75
Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 - 285
Progress Energy Florida, Inc. 364-Day (expiring 3/29/05) 200 170 30
Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 55 145
Less: amounts reserved(a) (574)
--------------------------------------------------------------------------------------------------------------
Total credit facilities $ 1,980 $ 475 $ 931
--------------------------------------------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding or
backing letters of credit, they are not available for additional
borrowings.
114
At December 31, 2004 and 2003, the Company had $424 million and $4 million,
respectively, of outstanding commercial paper and other short-term debt
classified as short-term obligations. The weighted-average interest rates
of such short-term obligations at December 31, 2004 and 2003 were 2.77% and
2.25%, respectively. At December 31, 2004, the Company has reserved $150
million of its lines of credit for backing of letters of credit.
Both Progress Energy and PEF have an uncommitted bank bid facility
authorizing them to borrow and reborrow, and have loans outstanding at any
time, up to $300 million and $100 million, respectively. These bank bid
facilities were not drawn at December 31, 2004.
On January 31, 2005, Progress Energy, Inc., entered into a new $600 million
revolving credit agreement, which expires December 30, 2005. This facility
was added to provide additional liquidity during 2005 due in part to storm
restoration costs incurred in Florida during 2004. The credit agreement
includes a defined maximum total debt to total capital ratio of 68% and a
minimum interest coverage ratio of 2.5 to 1. The credit agreement also
contains various cross-default and other acceleration provisions. On
February 4, 2005, $300 million was drawn under the new facility to reduce
commercial paper and bank loans outstanding.
The combined aggregate maturities of long-term debt for 2005 through 2009
are approximately $349 million, $963 million, $674 million, $827 million
and $560 million, respectively.
B. Covenants and Default Provisions
FINANCIAL COVENANTS
Progress Energy's, PEC's and PEF's credit lines contain various terms and
conditions that could affect the Company's ability to borrow under these
facilities. These include maximum debt to total capital ratios, interest
coverage tests, material adverse change clauses and cross-default
provisions.
All of the credit facilities include a defined maximum total debt to total
capital ratio. At December 31, 2004, the maximum and calculated ratios for
the companies, pursuant to the terms of the agreements, are as follows:
- -------------------------------------------------------------------------
Company Maximum Ratio Actual Ratio (a)
- -------------------------------------------------------------------------
Progress Energy, Inc. 65% 60.7%
Progress Energy Carolinas, Inc. 65% 52.3%
Progress Energy Florida, Inc. 65% 50.8%
- -------------------------------------------------------------------------
(a) Indebtedness as defined by the bank agreements includes certain
letters of credit and guarantees that are not recorded on the
Consolidated Balance Sheets.
Progress Energy's 364-day credit facility and both PEF's 364-day and
three-year credit facilities have a financial covenant for interest
coverage. The covenants require Progress Energy's and PEF's earnings before
interest, taxes, and depreciation and amortization to interest expense
ratio to be at least 2.5 to 1 and 3 to 1, respectively. For the year ended
December 31, 2004, the ratios were 4.00 to 1 and 7.93 to 1 for the Company
and PEF, respectively.
In March 2005, Progress Energy, Inc.'s five-year credit facility was
amended to increase the maximum total debt to total capital ratio from 65%
to 68% in anticipation of the potential impacts of proposed accounting
rules for uncertain tax positions. See Notes 2 and 23E.
MATERIAL ADVERSE CHANGE CLAUSE
The credit facilities of Progress Energy, PEC, and PEF include a provision
under which lenders could refuse to advance funds in the event of a
material adverse change (MAC) in the borrower's financial condition.
Pursuant to the terms of Progress Energy's five-year credit facility, even
in the event of a MAC, Progress Energy may continue to borrow funds so long
as the proceeds are used to repay maturing commercial paper balances.
CROSS-DEFAULT PROVISIONS
Each of these credit agreements contains cross-default provisions for
defaults of indebtedness in excess of $10 million. Under these provisions,
if the applicable borrower or certain subsidiaries of the borrower fail to
pay various debt obligations in excess of $10 million, the lenders could
accelerate payment of any outstanding borrowing and terminate their
commitments to the credit facility. Progress Energy's cross-default
provision applies only to Progress Energy and its significant subsidiaries
(i.e., PEC, Florida Progress, PEF, Progress Capital Holdings, Inc. (PCH)
and Progress Fuels).
115
Additionally, certain of Progress Energy's long-term debt indentures
contain cross-default provisions for defaults of indebtedness in excess of
$25 million; these provisions apply only to other obligations of Progress
Energy, primarily commercial paper issued by the holding company, not its
subsidiaries. In the event that these indenture cross-default provisions
are triggered, the debt holders could accelerate payment of approximately
$4.3 billion in long-term debt. Certain agreements underlying the Company's
indebtedness also limit its ability to incur additional liens or engage in
certain types of sale and leaseback transactions.
OTHER RESTRICTIONS
Neither Progress Energy's Articles of Incorporation nor any of its debt
obligations contain any restrictions on the payment of dividends. Certain
documents restrict the payment of dividends by Progress Energy's
subsidiaries as outlined below.
PEC's mortgage indenture provides that, as long as any first mortgage bonds
are outstanding, cash dividends and distributions on its common stock and
purchases of its common stock are restricted to aggregate net income
available for PEC since December 31, 1948, plus $3 million, less the amount
of all preferred stock dividends and distributions, and all common stock
purchases, since December 31, 1948. At December 31, 2004, none of PEC's
retained earnings was restricted.
In addition, PEC's Articles of Incorporation provide that cash dividends on
common stock shall be limited to 75% of net income available for dividends
if common stock equity falls below 25% of total capitalization, and to 50%
if common stock equity falls below 20%. At December 31, 2004, PEC's common
stock equity was approximately 52.2% of total capitalization.
PEF's mortgage indenture provides that it will not pay any cash dividends
upon its common stock, or make any other distribution to the stockholders,
except a payment or distribution out of net income of PEF subsequent to
December 31, 1943. At December 31, 2004, none of PEF's retained earnings
was restricted.
In addition, PEF's Articles of Incorporation provide that no cash dividends
or distributions on common stock shall be paid, if the aggregate amount
thereof since April 30, 1944, including the amount then proposed to be
expended, plus all other charges to retained earnings since April 30, 1944,
exceed (a) all credits to retained earnings since April 30, 1944, plus (b)
all amounts credited to capital surplus after April 30, 1944, arising from
the donation to PEF of cash or securities or transfers of amounts from
retained earnings to capital surplus.
PEF's Articles of Incorporation also provide that cash dividends on common
stock shall be limited to 75% of net income available for dividends if
common stock equity falls below 25% of total capitalization, and to 50% if
common stock equity falls below 20%. On December 31, 2004, PEF's common
stock equity was approximately 54.4% of total capitalization.
C. Collateralized Obligations
PEC's and PEF's first mortgage bonds are collateralized by their respective
mortgage indentures. Each mortgage constitutes a first lien on
substantially all of the fixed properties of the respective company,
subject to certain permitted encumbrances and exceptions. Each mortgage
also constitutes a lien on subsequently acquired property. At December 31,
2004, PEC and PEF had a total of approximately $3.84 billion of first
mortgage bonds outstanding, including those related to pollution control
obligations. Each mortgage allows the issuance of additional mortgage bonds
upon the satisfaction of certain conditions.
D. Progress Genco Ventures, LLC (Genco) Bank Facility
In December 2004, Genco repaid its bank facility and recorded a $9 million
pre-tax loss ($6 million after-tax) in other, net on the extinguishment. At
that time, the related $195 million notional amount of interest rate
collars in place to hedge floating interest rate exposure on the bank
facility was terminated and pre-tax deferred losses of $6 million ($4
million after-tax) were reclassified into earnings in other, net due to the
discontinuance of the hedges. The facility was obtained to be used
exclusively for expansion of its nonregulated generation portfolio.
Borrowings under this facility were secured by the assets in the generation
portfolio. The facility was for up to $260 million, of which $241 million
had been drawn at December 31, 2003. Borrowings under the facility were
restricted for the operations, construction, repayments and other related
charges of the credit facility for the development projects. Cash held and
116
restricted to operations was $24 million at December 31, 2003, and was
included in other current assets. Cash held and restricted for long-term
purposes was $9 million at December 31, 2003, respectively, and was
included in other assets and deferred debits on the Consolidated Balance
Sheets.
E. Guarantees of Subsidiary Debt
See Note 19 on related party transactions for a discussion of obligations
guaranteed or secured by affiliates.
F. Hedging Activities
Progress Energy uses interest rate derivatives to adjust the fixed and
variable rate components of its debt portfolio and to hedge cash flow risk
related to commercial paper and to fixed rate debt to be issued in the
future. See discussion of risk management activities and derivative
transactions at Note 18.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents and short-term
obligations approximate fair value due to the short maturities of these
instruments. At December 31, 2004, and 2003, investments in company-owned
life insurance and other benefit plan assets, with carrying amounts of
approximately $220 million and $210 million, respectively, are included in
miscellaneous other property and investments in the Consolidated Balance
Sheets and approximate fair value due to the short maturity of the
instruments. Other instruments, including short-term investments, are
presented at fair value in accordance with GAAP. The carrying amount of the
Company's long-term debt, including current maturities, was $9.870 billion
and $10.802 billion at December 31, 2004 and 2003, respectively. The
estimated fair value of this debt, as obtained from quoted market prices
for the same or similar issues, was $10.843 billion and $11.917 billion at
December 31, 2004 and 2003, respectively.
External trust funds have been established to fund certain costs of nuclear
decommissioning (See Note 6D). These nuclear decommissioning trust funds
are invested in stocks, bonds and cash equivalents. Nuclear decommissioning
trust funds are presented on the Consolidated Balance Sheets at amounts
that approximate fair value. Fair value is obtained from quoted market
prices for the same or similar investments.
15. INCOME TAXES
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between book and tax carrying amounts of
assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties. To the extent that the
establishment of deferred income taxes under SFAS No. 109, "Accounting for
Income Taxes," (SFAS No. 109) is different from the recovery of taxes by
PEC and PEF through the ratemaking process, the differences are deferred
pursuant to SFAS No. 71. A regulatory asset or liability has been
recognized for the impact of tax expenses or benefits that are recovered or
refunded in different periods by the utilities pursuant to rate orders.
117
Accumulated deferred income tax assets (liabilities) at December 31 are:
- -----------------------------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------------------------
Current deferred tax asset
Unbilled revenue $ 35 $ 18
Other 86 69
- -----------------------------------------------------------------------------------------
Total current deferred tax asset 121 87
- -----------------------------------------------------------------------------------------
Noncurrent deferred tax asset (liability)
Investments 73 8
Supplemental executive retirement plans 31 30
Other post-employment benefits (OPEB) 126 119
Other pension plans (15) (97)
Goodwill 34 46
Accumulated depreciation and property cost differences (1,374) (1,436)
Deferred costs (13) 26
Deferred storm costs (113) -
Deferred fuel (55) 31
Federal income tax credit carry forward 779 683
State net operating loss carry forward 47 42
Valuation allowance (47) (42)
Miscellaneous other temporary differences, net 43 (16)
- -----------------------------------------------------------------------------------------
Total noncurrent deferred tax liabilities (484) (606)
- -----------------------------------------------------------------------------------------
Less amount included in other assets and deferred debits 10 9
- -----------------------------------------------------------------------------------------
Net noncurrent deferred tax liabilities $ (494) $ (615)
- -----------------------------------------------------------------------------------------
Total deferred income tax liabilities were $2,797 million and $2,662
million at December 31, 2004 and 2003, respectively. Total deferred income
tax assets were $2,434 million and $2,143 million at December 31, 2004 and
2003, respectively. Total noncurrent income tax liabilities on the
Consolidated Balance Sheets at December 31, 2004 and 2003 include $105
million and $86 million, respectively, related to probable tax liabilities
on which the Company accrues interest that would be payable with the
related tax amount in future years.
The federal income tax credit carry forward at December 31, 2004, consists
of $749 million of alternative minimum tax credit with an indefinite carry
forward period and $30 million of general business credit with a carry
forward period that will begin to expire in 2020.
As of December 31, 2004, the Company had a state net operating loss carry
forward of $79 million, which will begin to expire in 2007.
The Company established additional valuation allowances of $5 million
during 2004 and 2003 and $12 million during 2002, due to the uncertainty of
realizing certain future state tax benefits. The Company believes it is
more likely than not that the results of future operations will generate
sufficient taxable income to allow for the utilization of the remaining
deferred tax assets. Progress Energy decreased its 2004 beginning of the
year valuation allowance by $8 million for a change in circumstances
related to net operating losses.
The Company establishes accruals for certain tax contingencies when,
despite the belief that the Company's tax return positions are fully
supported, the Company believes that certain positions may be challenged
and that it is probable the Company's positions may not be fully sustained.
The Company is under continuous examination by the Internal Revenue Service
and other tax authorities and accounts for potential losses of tax benefits
in accordance with SFAS No. 5. At December 31, 2004 and 2003, respectively,
the Company had recorded $60 million and $56 million of tax contingency
reserves, excluding accrued interest and penalties, which are included in
other current liabilities on the Consolidated Balance Sheets. Considering
all tax contingency reserves, the Company does not expect the resolution of
these matters to have a material impact on its financial position or result
of operations. All tax contingency reserves relate to capitalization and
basis issues and do not relate to any potential disallowances of tax
credits from synthetic fuel production (See Note 23E).
118
Reconciliations of the Company's effective income tax rate to the statutory
federal income tax rate are:
- ------------------------------------------------------------------------------------
2004 2003 2002
- ------------------------------------------------------------------------------------
Effective income tax rate 13.5% (15.8)% (40.0)%
State income taxes, net of federal benefit (6.9) (3.3) (8.2)
AFUDC amortization (0.5) (1.4) (5.2)
Federal tax credits 25.6 50.4 78.0
Investment tax credit amortization 1.6 2.3 4.7
ESOP dividend deduction 1.8 2.1 3.8
Other differences, net (0.1) 0.7 1.9
- ------------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
- ------------------------------------------------------------------------------------
Income tax expense (benefit) applicable to continuing operations is
comprised of:
- ------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- ------------------------------------------------------------------------------------
Current - federal $ 127 $ 127 $ 195
state 76 54 67
Deferred - federal (84) (255) (379)
state 10 (21) (23)
Investment tax credit (14) (16) (18)
- ------------------------------------------------------------------------------------
Total income tax expense (benefit) $ 115 $ (111) $ (158)
- ------------------------------------------------------------------------------------
The company has recognized tax benefits from state net operating loss carry
forwards in the amount of $7 million during 2004 and $3 million during 2003
and 2002.
The Company, through its subsidiaries, is a majority owner in five entities
and a minority owner in one entity that owns facilities that produce
synthetic fuel as defined under the Internal Revenue Code (Code). The
production and sale of the synthetic fuel from these facilities qualifies
for tax credits under Section 29 if certain requirements are satisfied (See
Note 23E).
16. CONTINGENT VALUE OBLIGATIONS
In connection with the acquisition of FPC during 2000, the Company issued
98.6 million contingent value obligations (CVOs). Each CVO represents the
right to receive contingent payments based on the performance of four
synthetic fuel facilities purchased by subsidiaries of FPC in October 1999.
The payments, if any, would be based on the net after-tax cash flows the
facilities generate. The CVO liability is adjusted to reflect market price
fluctuations. The unrealized loss/gain recognized due to these market
fluctuations is recorded in other, net on the consolidated statements of
income (See Note 21). The liability, included in other liabilities and
deferred credits, at December 31, 2004 and 2003, was $13 million and $23
million, respectively.
17. BENEFIT PLANS
A. Postretirement Benefits
The Company and some of its subsidiaries have a noncontributory defined
benefit retirement (pension) plan for substantially all full-time
employees. The Company also has supplementary defined benefit pension plans
that provide benefits to higher-level employees. In addition to pension
benefits, the Company and some of its subsidiaries provide contributory
other postretirement benefits (OPEB), including certain health care and
life insurance benefits, for retired employees who meet specified criteria.
The Company uses a measurement date of December 31 for its pension and OPEB
plans.
119
The components of net periodic benefit cost for the years ended December 31
are:
- ----------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
--------------------------------- -----------------------------
(in millions) 2004 2003 2002 2004 2003 2002
- ----------------------------------------------------------------------------------------------------------------------
Service cost $ 54 $ 52 $ 45 $ 12 $ 15 $ 13
Interest cost 110 108 106 31 33 32
Expected return on plan assets (155) (144) (161) (5) (4) (5)
Amortization of actuarial (gain) loss 21 25 2 4 5 1
Other amortization, net - - - 1 4 4
- ----------------------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit) $ 30 $ 41 $ (8) $ 43 $ 53 $ 45
Additional cost / (benefit) recognition (Note 17B) (16) (18) (7) 2 2 2
- ----------------------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit) recognized $ 14 $ 23 $ (15) $ 45 $ 55 $ 47
- ----------------------------------------------------------------------------------------------------------------------
The net periodic cost for other postretirement benefits decreased during
2004 due to the implementation of FASB Staff Position 106-2 (See Note 2).
In addition to the net periodic cost and benefit reflected above, in 2003
the Company recorded curtailment and settlement effects related to the
disposition of NCNG, which are reflected in income/(loss) from discontinued
operations in the Consolidated Statements of Income. These effects included
a pension-related loss of $13 million and an OPEB-related gain of $1
million.
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the projected benefit
obligation or the market-related value of assets are amortized over the
average remaining service period of active participants.
To determine the market-related value of assets, the Company uses a
five-year averaging method for a portion of its pension assets and fair
value for the remaining portion. The Company has historically used the
five- year averaging method. When the Company acquired Florida Progress in
2000, it retained the Florida Progress historical use of fair value to
determine market-related value for Florida Progress pension assets.
Reconciliations of the changes in the plans' benefit obligations and the
plans' funded status are:
- --------------------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
-------------------------- -----------------------
(in millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------
Projected benefit obligation at January 1 $ 1,772 $ 1,694 $ 472 $ 514
Service cost 54 52 12 15
Interest cost 110 108 31 33
Disposition of NCNG - (39) - (13)
Benefit payments (98) (94) (23) (24)
Plan amendment 21 - - -
Actuarial loss (gain) 102 51 46 (53)
- --------------------------------------------------------------------------------------------------------
Obligation at December 31 1,961 1,772 538 472
Fair value of plan assets at December 31 1,774 1,631 70 65
- --------------------------------------------------------------------------------------------------------
Funded status (187) (141) (468) (407)
Unrecognized transition obligation - - 10 25
Unrecognized prior service cost 24 4 6 7
Unrecognized net actuarial loss 530 505 94 40
Minimum pension liability adjustment (470) (23) - -
- --------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net $ (103) $ 345 $ (358) $ (335)
(Note 17B)
- --------------------------------------------------------------------------------------------------------
The 2003 OPEB obligation information above has been restated due to the
implementation of FASB Staff Position 106-2 (See Note 2).
120
The net accrued pension cost of $103 million at December 31, 2004, is
recognized in the Consolidated Balance Sheets as prepaid pension cost of
$42 million and accrued benefit cost of $145 million, which is included in
accrued pension and other benefits. The net prepaid pension cost of $345
million at December 31, 2003, is recognized in the Consolidated Balance
Sheets as prepaid pension cost of $462 million and accrued benefit cost of
$117 million, which is included in accrued pension and other benefits. The
defined benefit pension plans with accumulated benefit obligations in
excess of plan assets had projected benefit obligations totaling $1.72
billion and $125 million at December 31, 2004 and 2003, respectively. Those
plans had accumulated benefit obligations totaling $1.71 billion and $117
million at December 31, 2004 and 2003, respectively, $1.57 billion of plan
assets at December 31, 2004, and no plan assets at December 31, 2003. The
total accumulated benefit obligation for pension plans was $1.90 billion
and $1.72 billion at December 31, 2004 and 2003, respectively. The accrued
OPEB cost is included in accrued pension and other benefits in the
Consolidated Balance Sheets.
A minimum pension liability adjustment of $470 million was recorded at
December 31, 2004. This adjustment resulted in a charge of $24 million to
intangible assets, a $150 million charge to a pension-related regulatory
liability (See Note 17B), a $67 million charge to a regulatory asset
pursuant to a recent FPSC order and a pre-tax charge of $229 million to
accumulated other comprehensive loss, a component of common stock equity. A
minimum pension liability adjustment of $23 million, related to the
supplementary defined benefit pension plans, was recorded at December 31,
2003. This adjustment is offset by a corresponding pre-tax amount in
accumulated other comprehensive loss.
Reconciliations of the fair value of plan assets are:
- ---------------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
----------------------------- ---------------------
(in millions) 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------
Fair value of plan assets January 1 $ 1,631 $ 1,364 $ 65 $ 52
Actual return on plan assets 211 391 8 12
Disposition of NCNG - (35) - -
Benefit payments (98) (94) (23) (24)
Employer contributions 30 5 20 25
- ---------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 1,774 $ 1,631 $ 70 $ 65
- ---------------------------------------------------------------------------------------------------
In the table above, substantially all employer contributions represent
benefit payments made directly from Company assets except for the 2004
pension amount. The remaining benefits payments were made directly from
plan assets. In 2004, the Company made a required contribution of
approximately $24 million directly to pension plan assets. The OPEB benefit
payments represent the net Company cost after participant contributions.
Participant contributions represent approximately 20% of gross benefit
payments.
The asset allocation for the Company's plans at the end of 2004 and 2003
and the target allocation for the plans, by asset category, are as follows:
- -------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
---------------------------------------------------------------------------------
Target Percentage of Plan Target Percentage of Plan
Allocations Assets at Year End Allocations Assets at Year End
------------- -------------------- -------------- ------------------------
Asset Category 2005 2004 2003 2005 2004 2003
- -------------------------------------------------------------------------------------------------------------
Equity - domestic 48% 47% 49% 34% 34% 35%
Equity - international 15% 21% 22% 11% 15% 16%
Debt - domestic 12% 9% 11% 37% 35% 37%
Debt - international 10% 11% 11% 7% 8% 7%
Other 15% 12% 7% 11% 8% 5%
- -------------------------------------------------------------------------------------------------------------
Total 100% 100% 100% 100% 100% 100%
- -------------------------------------------------------------------------------------------------------------
The Company sets target allocations among asset classes to provide broad
diversification to protect against large investment losses and excessive
volatility, while recognizing the importance of offsetting the impacts of
benefit cost escalation. In addition, the Company employs external
investment managers who have complementary investment philosophies and
approaches. Tactical shifts (plus or minus 5%) in asset allocation from the
target allocations are made based on the near-term view of the risk and
return tradeoffs of the asset classes.
121
In 2005, the Company expects to make no required contributions directly to
pension plan assets and $1 million of discretionary contributions directly
to the OPEB plan assets. The expected benefit payments for the pension
benefit plan for 2005 through 2009 and in total for 2010-2014, in millions,
are approximately $113, $110, $115, $124, $131 and $794, respectively. The
expected benefit payments for the OPEB plan for 2005 through 2009 and in
total for 2010-2014, in millions, are approximately $32, $34, $37, $39, $41
and $230, respectively. The expected benefit payments include benefit
payments directly from plan assets and benefit payments directly from
Company assets. The benefit payment amounts reflect the net cost to the
Company after any participant contributions. The Company expects to begin
receiving prescription drug-related federal subsidies in 2006 (See Note 2),
and the expected subsidies for 2006 through 2009 and in total for
2010-2014, in millions, are approximately $3, $3, $3, $4 and $24,
respectively. The expected benefit payments above do not reflect the
potential effects of a 2005 voluntary enhanced retirement program (See Note
24).
The following weighted-average actuarial assumptions were used in the
calculation of the year-end obligation:
- ---------------------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
---------------------- ------------------------
(in millions) 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------
Discount rate 5.90% 6.30% 5.9% 6.30%
Rate of increase in future compensation
Bargaining 3.50% 3.50% - -
Supplementary plans 5.25% 5.00% - -
Initial medical cost trend rate for pre-Medicare
benefits - - 7.25% 7.25%
Initial medical cost trend rate for post-Medicare
benefits - - 7.25% 7.25%
Ultimate medical cost trend rate - - 5.00% 5.25%
Year ultimate medical cost trend rate is achieved - - 2008 2009
- ---------------------------------------------------------------------------------------------------------
The Company's primary defined benefit retirement plan for nonbargaining
employees is a "cash balance" pension plan as defined in EITF Issue No.
03-4. Therefore, effective December 31, 2003, the Company began to use the
traditional unit credit method for purposes of measuring the benefit
obligation of this plan. Under the traditional unit credit method, no
assumptions are included about future changes in compensation, and the
accumulated benefit obligation and projected benefit obligation are the
same.
The following weighted-average actuarial assumptions were used in the
calculation of the net periodic cost:
- -------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
----------------------------- ------------------------------
(in millions) 2004 2003 2002 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50%
Rate of increase in future compensation
Bargaining 3.50% 3.50% 3.50% - - -
Nonbargaining - 4.00% 4.00% - - -
Supplementary plans 5.00% 4.00% 4.00% - - -
Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 8.50% 8.45% 8.20%
- -------------------------------------------------------------------------------------------------------------------
The expected long-term rates of return on plan assets were determined by
considering long-term historical returns for the plans and long-term
projected returns based on the plans' target asset allocation. For all
pension plan assets and a substantial portion of OPEB plans assets, those
benchmarks support an expected long-term rate of return between 9.0% and
9.5%. The Company has chosen to use an expected long-term rate of 9.25%.
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2004 would increase by $1 million, and
the OPEB obligation at December 31, 2004, would increase by $30 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for
2004 would decrease by $1 million, and the OPEB obligation at December 31,
2004, would decrease by $26 million.
122
B. FPC Acquisition
During 2000, the Company completed the acquisition of FPC. FPC's pension
and OPEB liabilities, assets and net periodic costs are reflected in the
above information as appropriate. Certain of FPC's nonbargaining unit
benefit plans were merged with those of the Company effective January 1,
2002.
PEF continues to recover qualified plan pension costs and OPEB costs in
rates as if the acquisition had not occurred. Accordingly, a portion of the
accrued OPEB cost reflected in the table above has a corresponding
regulatory asset at December 31, 2004, and 2003 (See Note 8A). In addition,
a portion of the prepaid pension cost reflected in the table above has a
corresponding regulatory liability (See Note 8A). Pursuant to its rate
treatment, PEF recognized additional periodic pension credits and
additional periodic OPEB costs, as indicated in the net periodic cost
information above.
18. RISK MANAGEMENT ACTIVITIES AND DERIVATIVES TRANSACTIONS
Under its risk management policy, the Company may use a variety of
instruments, including swaps, options and forward contracts, to manage
exposure to fluctuations in commodity prices and interest rates. Such
instruments contain credit risk if the counterparty fails to perform under
the contract. The Company minimizes such risk by performing credit reviews
using, among other things, publicly available credit ratings of such
counterparties. Potential nonperformance by counterparties is not expected
to have a material effect on the consolidated financial position or
consolidated results of operations of the Company.
A. Commodity Derivatives
GENERAL
Most of the Company's commodity contracts are not derivatives pursuant to
SFAS No. 133 or qualify as normal purchases or sales pursuant to SFAS No.
133. Therefore, such contracts are not recorded at fair value.
During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related
to the pricing of contracts that include broad market indices (e.g., CPI).
In particular, that guidance discussed whether the pricing in a contract
that contains broad market indices could qualify as a normal purchase or
sale (the normal purchase or sale term is a defined accounting term, and
may not, in all cases, indicate whether the contract would be "normal" from
an operating entity viewpoint). The FASB issued final superseding guidance
(DIG Issue C20) on this issue effective October 1, 2003, for the Company.
DIG Issue C20 specifies new pricing-related criteria for qualifying as a
normal purchase or sale, and it required a special transition adjustment as
of October 1, 2003.
PEC determined that it had one existing "normal" contract that was affected
by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
a pre-tax fair value loss transition adjustment of $38 million ($23 million
after-tax) in the fourth quarter of 2003, which was reported as a
cumulative effect of a change in accounting principle. The subject contract
meets the DIG Issue C20 criteria for normal purchase or sale and,
therefore, was designated as a normal purchase as of October 1, 2003. The
original liability of $38 million associated with the fair value loss is
being amortized to earnings over the term of the related contract. At
December 31, 2004 and 2003, the remaining liability was $26 million and $35
million, respectively.
ECONOMIC DERIVATIVES
Derivative products, primarily electricity and natural gas contracts, are
entered into for economic hedging purposes. While management believes the
economic hedges mitigate exposures to fluctuations in commodity prices,
these instruments are not designated as hedges for accounting purposes and
are monitored consistent with trading positions. The Company manages open
positions with strict policies that limit its exposure to market risk and
require daily reporting to management of potential financial exposures.
Gains and losses from such contracts were not material to results of
operations during 2004, 2003 or 2002, and the Company did not have material
outstanding positions in such contracts at December 31, 2004 and 2003.
In 2004, PEF entered into derivative instruments related to its exposure to
price fluctuations on fuel oil purchases. At December 31, 2004, the fair
values of these instruments were a $2 million long-term derivative asset
position included in other assets and deferred debits and a $5 million
short-term derivative liability position included in other current
liabilities. These instruments receive regulatory accounting treatment.
Gains are recorded in regulatory liabilities and losses are recorded in
regulatory assets.
123
CASH FLOW HEDGES
Progress Energy's subsidiaries designate a portion of commodity derivative
instruments as cash flow hedges under SFAS No. 133. The objective for
holding these instruments is to hedge exposure to market risk associated
with fluctuations in the price of natural gas for the Company's forecasted
purchases and sales. At December 31, 2004, the maximum period over which
the Company is hedging exposures to the price variability of natural gas is
10 years.
The total fair value of commodity cash flow hedges at December 31, 2004 and
2003 was as follows:
- -----------------------------------------------
(millions of dollars) 2004 2003
- -----------------------------------------------
Fair value of assets $ - $ -
Fair value of liabilities (15) (12)
- -----------------------------------------------
Fair value, net $ (15) $ (12)
- -----------------------------------------------
The ineffective portion of commodity cash flow hedges was not material to
the Company's results of operations for 2004, 2003 or 2002. At December 31,
2004, there were $9 million of after-tax deferred losses in accumulated
other comprehensive income (OCI), of which $5 million is expected to be
reclassified to earnings during the next 12 months as the hedged
transactions occur. Gains and losses are recorded net in operating
revenues. As part of the divestiture of Winchester Production Company,
Ltd., assets in 2004, $7 million of after-tax deferred losses were
reclassified into earnings due to discontinuance of the related cash flow
hedges and recorded against the gain on sale. Due to the volatility of the
commodities markets, the value in OCI is subject to change prior to its
reclassification into earnings.
B. Interest Rate Derivatives - Fair Value or Cash Flow Hedges
The Company uses cash flow hedging strategies to hedge variable interest
rates on long-term and short-term debt and to hedge interest rates with
regard to future fixed-rate debt issuances. Gains and losses are recorded
in OCI and amounts reclassified to earnings are included in net interest
charges as the hedged transactions occur. The Company uses fair value
hedging strategies to manage its exposure to fixed interest rates on
long-term debt. For interest rate fair value hedges, the change in the fair
value of the hedging derivative is recorded in net interest charges and is
offset by the change in the fair value of the hedged item.
The fair values of open position interest rate hedges at December 31, 2004
and 2003 were as follows:
- -------------------------------------------------------
(in millions) 2004 2003
- -------------------------------------------------------
Interest rate cash flow hedges $ (2) $ (6)
Interest rate fair value hedges $ 3 $ (4)
- -------------------------------------------------------
CASH FLOW HEDGES
The following table presents selected information related to the Company's
interest rate cash flow hedges included in accumulated OCI at December 31,
2004:
- -----------------------------------------------------------------------------
Accumulated Other Comprehensive
Income/(Loss), net of tax(a) Portion Expected to be
Reclassified to Earnings during
(millions of dollars) the Next 12 Months(b)
- -----------------------------------------------------------------------------
$ (19) $ (4)
- -----------------------------------------------------------------------------
(a) Includes amounts related to terminated hedges.
(b) Actual amounts that will be reclassified to earnings may vary from the
expected amounts presented above as a result of changes in interest
rates.
124
As of December 31, 2004, PEC had $110 million notional amount of pay-fixed
forward swaps to hedge its exposure to interest rates with regard to future
issuances of debt (pre-issue hedges) and $21 million notional amount of
pay-fixed forward starting swaps to hedge its exposure to interest rates
with regard to an upcoming railcar lease. On February 4, 2005, PEC entered
another $50 million notional amount of its pre-issue hedges. All the swaps
have a computational period of 10 years. PEC held no interest rate cash
flow hedges at December 31, 2003. The ineffective portion of interest rate
cash flow hedges was not material to the Company's results of operations
for 2004 and 2003.
In December 2004, Progress Ventures, Inc. (PVI), a wholly owned subsidiary
of Progress Energy, terminated $195 million notional amount of interest
rate collars in place to hedge floating interest rate exposure associated
with variable-rate long-term debt. The related debt was also extinguished
in December 2004 (See Note 13). Pre-tax deferred losses of $6 million ($4
million after-tax) were reclassified into earnings in other, net due to
discontinuance of these cash flow hedges.
At December 31, 2004 and 2003, Progress Energy, Inc., held interest rate
cash flow hedges, with a total notional amount of $200 million and $400
million, respectively, related to projected outstanding balances of
commercial paper. The fair value of the hedges at December 31, 2004, was
not material to the Company's financial condition and at December 31, 2003,
was $5 million. The hedges held at December 31, 2003, were terminated
during the year. Amounts in accumulated other comprehensive income related
to these terminated hedges will be reclassified to earnings as the hedged
interest payments occur.
FAIR VALUE HEDGES
As of December 31, 2004 and 2003, Progress Energy had $150 million notional
amount and $850 million notional amount, respectively, of fixed rate debt
swapped to floating rate debt by executing interest rate derivative
agreements. These agreements expire on various dates through March 2011.
During 2004, Progress Energy entered into $350 million notional amount and
terminated $1.05 billion notional amount of interest rate swap agreements.
At December 31, 2004 and 2003, the Company had $9 million and $23 million,
respectively, of basis adjustments in long-term debt related to terminated
interest rate fair value hedges, which are being amortized over periods
ending in 2006 through 2011 coinciding with the maturities of the related
debt instruments.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
19. RELATED PARTY TRANSACTIONS
As a part of normal business, Progress Energy and certain subsidiaries
enter into various agreements providing financial or performance assurances
to third parties. These agreements are entered into primarily to support or
enhance the creditworthiness otherwise attributed to a subsidiary on a
stand-alone basis, thereby facilitating the extension of sufficient credit
to accomplish the subsidiaries' intended commercial purposes. As of
December 31, 2004, Progress Energy and its subsidiaries' guarantees
include: $270 million supporting commodity transactions, $181 million to
support nuclear decommissioning, $536 million related to power supply
agreements and $182 million for guarantees supporting other agreements of
subsidiaries. Progress Energy also purchased $92 million of surety bonds
and authorized the issuance of standby letters of credit by financial
institutions of $50 million. Florida Progress also fully guarantees the
medium term notes outstanding for Progress Capital, a wholly owned
subsidiary of Florida Progress (See Note 13). At December 31, 2004,
management does not believe conditions are likely for significant
performance under these agreements. To the extent liabilities are incurred
as a result of the activities covered by the guarantees, such liabilities
are included in the Balance Sheets.
Progress Fuels sells coal to PEF for an insignificant profit. These
intercompany revenues and expenses are eliminated in consolidation;
however, in accordance with SFAS No. 71 profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable
and the future recovery of sales price through the ratemaking process is
probable. Sales, net of insignificant profits, of $331 million, $346
million and $329 million for the years ended December 31, 2004, 2003 and
2002, respectively, are included in fuel used in electric generation on the
Consolidated Statements of Income.
Florida Progress Funding Corporation (Funding Corp.) $309 million 7.10%
Junior Subordinated Deferrable Interest Notes (Subordinated Notes) are due
to FPC Capital I (the Trust). The Trust was established for the sole
purpose of issuing $300 million Preferred Securities and using the proceeds
thereof to purchase from Funding Corp. its Subordinated Notes due 2039. The
Company has fully and unconditionally guaranteed the obligations of Funding
Corp. under the Subordinated Notes (the Notes Guarantee). In addition, the
Company has guaranteed the payment of all distributions related to the $300
million Preferred Securities required to be made by the Trust, but only to
the extent that the Trust has funds available for such distributions
125
(Preferred Securities Guarantee). The Preferred Securities Guarantee,
considered together with the Notes Guarantee, constitutes a full and
unconditional guarantee by the Company of the Trust's obligations under the
Preferred Securities. The Subordinated Notes and the Notes Guarantee are
the sole assets of the Trust. The Subordinated Notes may be redeemed at the
option of Funding Corp. at par value plus accrued interest through the
redemption date. The proceeds of any redemption of the Subordinated Notes
will be used by the Trust to redeem proportional amounts of the Preferred
Securities and common securities in accordance with their terms. Upon
liquidation or dissolution of Funding Corp., holders of the Preferred
Securities would be entitled to the liquidation preference of $25 per share
plus all accrued and unpaid dividends thereon to the date of payment. The
yearly interest expense is $21 million and is reflected in the Consolidated
Statements of Income.
The Company sold NCNG to Piedmont Natural Gas Company, Inc. on September
30, 2003 (See Note 4E). Prior to disposition, NCNG sold natural gas to
affiliates. During the years ended December 31, 2003 and 2002, sales of
natural gas to affiliates amounted to $11 million and $20 million,
respectively. These revenues are included in discontinued operations on the
Consolidated Statements of Income.
20. FINANCIAL INFORMATION BY BUSINESS SEGMENT
The Company currently provides services through the following business
segments: PEC Electric, PEF, Fuels, CCO and Rail Services. Prior to 2004,
other nonregulated business activities were reported separately in the
Other segment. These reportable segment changes reflect the current
reporting structure. For comparative purposes, the results have been
restated to align with the current presentation.
PEC Electric and PEF are primarily engaged in the generation, transmission,
distribution and sale of electric energy in portions of North Carolina,
South Carolina and Florida. These electric operations are subject to the
rules and regulations of the FERC, the NCUC, the SCPSC and the FPSC. These
electric operations also distribute and sell electricity to other
utilities, primarily on the east coast of the United States.
Fuels operations, which are located throughout the United States, are
involved in natural gas drilling and production, coal terminal services,
coal mining, synthetic fuel production and fuel transportation and
delivery.
CCO's operations, which are located in the southeastern United States,
include nonregulated electric generation operations and marketing
activities.
Rail Services' operations include railcar repair, rail parts reconditioning
and sales, railcar leasing and sales and scrap metal recycling. These
activities include maintenance and reconditioning of salvageable scrap
components of railcars, locomotive repair and right-of-way maintenance.
Rail Services' operations are located in the United States, Canada and
Mexico.
In addition to these reportable operating segments, the Company has
Corporate and other activities that include holding company and service
company operations as well as other nonregulated business areas. These
nonregulated business areas include telecommunications and energy service
operations and other nonregulated subsidiaries that do not separately meet
the disclosure requirements of SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information." Included in the 2004 losses is a
$43 million pre-tax ($29 million after-tax) settlement agreement that SRS
reached with the San Francisco United School District related to civil
proceedings. Included in the 2002 losses are asset impairments and certain
other after-tax charges related to the telecommunications operations of
$225 million. The operations of NCNG were reclassified to discontinued
operations and therefore are not included in the results from continuing
operations during the periods reported. The profit or loss of the
identified segments plus the loss of Corporate and Other represents the
Company's total income from continuing operations.
Products and services are sold between the various reportable segments. All
intersegment transactions are at cost except for transactions between Fuels
and PEF, which are at rates set by the FPSC. In accordance with SFAS No.
71, profits on intercompany sales between PEF and Fuels are not eliminated
if the sales price is reasonable and the future recovery of sales price
through the ratemaking process is probable. The profits for all three years
presented were not significant.
126
- -------------------------------------------------------------------------------------------------------------------
PEC Rail Corporate
(in millions) Electric PEF Fuels CCO Services and Other Eliminations Totals
- -------------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2004
Revenues
Unaffiliated $ 3,628 $ 3,525 $ 1,179 $ 240 $ 1,130 $ 70 $ - $ 9,772
Intersegment - - 331 - 1 441 (773) -
- -------------------------------------------------------------------------------------------------------------------
Total revenues 3,628 3,525 1,510 240 1,131 511 (773) 9,772
- -------------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 570 281 93 58 21 45 - 1,068
Total interest charges,
net 192 114 22 17 27 361 (86) 647
Gain on sale of assets - - 54 - - 3 - 57
Income tax expense
(benefit) (a) 237 174 (230) (1) 15 (80) - 115
Segment profit (loss) 464 333 180 (4) 16 (236) - 753
Total assets 10,590 7,924 986 1,709 596 17,741 (13,553) 25,993
Capital and investment
expenditures 519 480 157 25 40 14 - 1,235
- -------------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2003
Revenues
Unaffiliated $ 3,589 $ 3,152 $ 928 $ 170 $ 846 $ 56 $ - $ 8,741
Intersegment - - 346 - 1 446 (793) -
- -------------------------------------------------------------------------------------------------------------------
Total revenues 3,589 3,152 1,274 170 847 502 (793) 8,741
- -------------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 562 307 80 42 20 29 - 1,040
Total interest charges, 197 91 23 4 29 356 (72) 628
net
Impairment of long-lived
assets and investments 11 - 17 - - 10 - 38
Income tax expense 238 147 (415) 8 2 (46) (45) (111)
(benefit) (a)
Segment profit (loss) 515 295 235 20 (1) (253) - 811
Total assets 10,748 7,280 1,142 1,747 586 17,955 (13,365) 26,093
Capital and investment
expenditures 445 526 309 338 103 35 - 1,756
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
Year ended
December 31, 2002
Revenues
Unaffiliated $ 3,539 $ 3,062 $ 607 $ 92 $ 714 $ 77 $ - $ 8,091
Intersegment - - 329 - 5 418 (752) -
- -------------------------------------------------------------------------------------------------------------------
Total revenues 3,539 3,062 936 92 719 495 (752) 8,091
- -------------------------------------------------------------------------------------------------------------------
Depreciation and
amortization 524 295 47 20 20 32 - 938
Total interest charges, 212 106 24 (12) 33 351 (81) 633
net
Impairment of long-
lived assets and - - - - 59 330 - 389
investments
Income tax expense 237 163 (373) 16 (16) (191) 6 (158)
(benefit) (a)
Segment profit (loss) 513 323 176 27 (42) (445) - 552
Total assets 10,139 6,678 934 1,452 529 15,872 (11,886) 23,718
Capital and investment
expenditures 619 550 170 682 8 73 - 2,102
- -------------------------------------------------------------------------------------------------------------------
(a) Amounts include income tax benefit reallocation from holding company
to profitable subsidiaries according to an SEC order.
127
Geographic Data
-----------------------------------------------------------------------------
(in millions) U.S. Canada Mexico Consolidated
-----------------------------------------------------------------------------
2004
Consolidated revenues $ 9,644 $ 112 $ 16 $ 9,772
-----------------------------------------------------------------------------
2003
Consolidated revenues $ 8,624 $ 103 $ 14 $ 8,741
-----------------------------------------------------------------------------
2002
Consolidated revenues $ 7,984 $ 93 $ 14 $ 8,091
-----------------------------------------------------------------------------
21. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, impairment of
investments and other income and expense items as discussed below. The
components of other, net as shown on the Consolidated Statements of Income
for the years ended December 31 are as follows:
- ---------------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- ---------------------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income $ 32 $ 27 $ 33
DIG Issue C20 amortization (Note 18A) 9 2 -
Contingent value obligation unrealized gain (Note 16) 9 - 28
Investment gains - 5 -
AFUDC equity 11 14 8
Gain on sale of property and partnership investment 12 25 12
Other 34 17 42
- -------------------------------------------------------------------------------------------
Total other income $ 107 $ 90 $ 123
- -------------------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses $ 20 $ 20 $ 29
Donations 10 12 19
Investment losses 6 - -
Contingent value obligation unrealized loss (Note 16) - 9 -
Loss from equity investments 6 40 21
Loss on debt extinguishment and interest rate collars
(Note 13D) 15 - -
Other 42 25 27
- -------------------------------------------------------------------------------------------
Total other expense $ 99 $ 106 $ 96
- -------------------------------------------------------------------------------------------
Other, net $ 8 $ (16) $ 27
- -------------------------------------------------------------------------------------------
Nonregulated energy and delivery services include power protection services
and mass market programs (surge protection, appliance services and area
light sales) and delivery, transmission and substation work for other
utilities.
22. ENVIRONMENTAL MATTERS
The Company is subject to federal, state and local regulations addressing
hazardous and solid waste management, air and water quality and other
environmental matters.
HAZARDOUS AND SOLID WASTE MANAGEMENT
The provisions of the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended (CERCLA), authorize the EPA to
require the cleanup of hazardous waste sites. This statute imposes
retroactive joint and several liabilities. Some states, including North and
South Carolina, have similar types of legislation. The Company and its
subsidiaries are periodically notified by regulators including the EPA and
various state agencies of their involvement or potential involvement in
sites that may require investigation and/or remediation. There are
presently several sites with respect to which the Company has been notified
by the EPA, the State of North Carolina or the State of Florida of its
potential liability, as described below in greater detail. The Company also
is currently in the process of assessing potential costs and exposures at
other sites. For all sites, as assessments are developed and analyzed, the
Company will accrue costs for the sites to the extent the costs are
probable and can be reasonably estimated. A discussion of sites by legal
entity follows.
128
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. PEC and PEF are each potentially responsible parties (PRPs) at
several manufactured gas plant (MGP) sites.
PEC, PEF and Progress Fuels Corporation have filed claims with the
Company's general liability insurance carriers to recover costs arising
from actual or potential environmental liabilities. Some claims have been
settled and others are still pending. While the Company cannot predict the
outcome of these matters, the outcome is not expected to have a material
effect on the consolidated financial position or results of operations.
PEC
There are nine former MGP sites and a number of other sites associated with
PEC that have required or are anticipated to require investigation and/or
remediation costs.
During the fourth quarter of 2004, the EPA advised PEC that it had been
identified as a PRP at the Ward Transformer site located in Raleigh, North
Carolina. The EPA offered PEC and 34 other PRPs the opportunity to
negotiate cleanup of the site and reimbursement of less than $2 million to
the EPA for EPA's past expenditures in addressing conditions at the site.
Although a loss is considered probable, an agreement among PRPs has not
been reached; consequently, it is not possible at this time to reasonably
estimate the total amount of PEC's obligation for remediation of the Ward
Transformer site.
At December 31, 2004 and 2003, PEC's accruals for probable and estimable
costs related to various environmental sites, which are included in other
liabilities and deferred credits and are expected to be paid out over many
years, were:
- -----------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------
Insurance fund $ 7 $ 9
Transferred from NCNG at time of sale 2 2
- -----------------------------------------------------------------
Total accrual for environmental sites $ 9 $ 11
- -----------------------------------------------------------------
PEC received insurance proceeds to address costs associated with
environmental liabilities related to its involvement with some sites. All
eligible expenses related to these are charged against a specific fund
containing these proceeds. PEC spent approximately $2 million related to
environmental remediation in 2004. PEC is unable to provide an estimate of
the reasonably possible total remediation costs beyond what is currently
accrued because investigations have not been completed at all sites.
This accrual has been recorded on an undiscounted basis. PEC measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
The process often involves assessing and developing cost-sharing
arrangements with other PRPs. PEC will accrue costs for the sites to the
extent its liability is probable and the costs can be reasonably estimated.
Because the extent of environmental impact, allocation among PRPs for all
sites, remediation alternatives (which could involve either minimal or
significant efforts), and concurrence of the regulatory authorities have
not yet reached the stage where a reasonable estimate of the remediation
costs can be made, PEC cannot determine the total costs that may be
incurred in connection with the remediation of all sites at this time. It
is anticipated that sufficient information will become available for
several sites during 2005 to allow a reasonable estimate of PEC's
obligation for those sites to be made.
PEF
At December 31, 2004 and 2003, PEF's accruals for probable and estimable
costs related to various environmental sites, which are included in other
liabilities and deferred credits and are expected to be paid out over many
years, were:
- ------------------------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------------------------
Remediation of distribution and substation transformers $ 27 $ 12
MGP and other sites 18 6
- ------------------------------------------------------------------------------
Total accrual for environmental sites $ 45 $ 18
- ------------------------------------------------------------------------------
129
PEF has received approval from the FPSC for recovery of costs associated
with the remediation of distribution and substation transformers through
the Environmental Cost Recovery Clause (ECRC). Under agreements with the
Florida Department of Environmental Protection (FDEP), PEF is in the
process of examining distribution transformer sites and substation sites
for potential equipment integrity issues that could result in the need for
mineral oil impacted soil remediation. Through 2004 PEF has reviewed a
number of distribution transformer sites and substation sites. PEF expects
to have completed its review of distribution transformer sites by the end
of 2007 and has completed the review of substation sites in 2004. Should
further sites be identified, PEF believes that any estimated costs would
also be recovered through the ECRC clause. In 2004, PEF accrued an
additional $19 million due to identification of additional sites requiring
remediation, and spent approximately $4 million related to the remediation
of transformers. PEF has recorded a regulatory asset for the probable
recovery of these costs through the ECRC.
The amounts for MGP and other sites, in the table above, relate to two
former MGP sites and other sites associated with PEF that have required or
are anticipated to require investigation and/or remediation. In 2004, PEF
received approximately $12 million in insurance claim settlement proceeds
and recorded a related accrual for associated environmental expenses. The
proceeds are restricted for use in addressing costs associated with
environmental liabilities. Expenditures for the year were less than $1
million.
These accruals have been recorded on an undiscounted basis. PEF measures
its liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
This process often includes assessing and developing cost-sharing
arrangements with other PRPs. Because the extent of environmental impact,
allocation among PRPs for all sites, remediation alternatives (which could
involve either minimal or significant efforts), and concurrence of the
regulatory authorities have not yet advanced to the stage where a
reasonable estimate of the remediation costs can be made, at this time PEF
is unable to provide an estimate of its obligation to remediate these sites
beyond what is currently accrued. As more activity occurs at these sites,
PEF will assess the need to adjust the accruals. It is anticipated that
sufficient information will become available in 2005 to make a reasonable
estimate of PEF's obligation for one of the MGP sites.
The Florida Legislature passed risk-based corrective action (RBCA, known as
Global RBCA) legislation in the 2003 regular session. Risk-based corrective
action generally means that the corrective action prescribed for
contaminated sites can correlate to the level of human health risk imposed
by the contamination at the property. The Global RBCA law expands the use
of the risk-based corrective action to all contaminated sites in the state
that are not currently in one of the state's waste cleanup programs. The
FDEP developed the rules required by the RBCA statute, holding meetings
with interested stakeholders and hosting public workshops. The rules have
the potential for making future cleanups in Florida more costly to
complete. The Global RBCA rule was adopted at the February 2, 2005,
Environmental Review Commission hearing. The effective date of the Global
RBCA rule is expected to be announced in April 2005. The Company and PEF
are in the process of assessing the impact of this matter.
FLORIDA PROGRESS CORPORATION
In 2001, FPC established a $10 million accrual to address indemnities and
retained an environmental liability associated with the sale of its Inland
Marine Transportation business. In 2003, the accrual was reduced to $4
million based on a change in estimate. During 2004, expenditures related to
this liability were not material to the Company's financial condition. As
of December 31, 2004, the remaining accrual balance was approximately $3
million. FPC measures its liability for these exposures based on estimable
and probable remediation scenarios.
Certain historical sites are being addressed voluntarily by FPC. An
immaterial accrual has been established to address investigation expenses
related to these sites. At this time, the Company cannot determine the
total costs that may be incurred in connection with these sites.
RAIL
Rail Services is voluntarily addressing certain historical waste sites. At
this time, the Company cannot determine the total costs that may be
incurred in connection with these sites.
130
AIR QUALITY
Congress is considering legislation that would require reductions in air
emissions of NOx, SO2, carbon dioxide and mercury. Some of these proposals
establish nationwide caps and emission rates over an extended period of
time. This national multi-pollutant approach to air pollution control could
involve significant capital costs that could be material to the Company's
consolidated financial position or results of operations. Control equipment
that will be installed on North Carolina fossil generating facilities as
part of the NC Clean Air legislation discussed below may address some of
the issues outlined above. However, the Company cannot predict the outcome
of this matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether changes
at those facilities were subject to New Source Review requirements or New
Source Performance Standards under the Clean Air Act. The Company was asked
to provide information to the EPA as part of this initiative and cooperated
in supplying the requested information. The EPA initiated civil enforcement
actions against other unaffiliated utilities as part of this initiative.
Some of these actions resulted in settlement agreements calling for
expenditures by these unaffiliated utilities, in excess of $1.0 billion.
These settlement agreements have generally called for expenditures to be
made over extended time periods, and some of the companies may seek
recovery of the related cost through rate adjustments or similar
mechanisms. The Company cannot predict the outcome of this matter.
In 2003, the EPA published a final rule addressing routine equipment
replacement under the New Source Review program. The rule defines routine
equipment replacement and the types of activities that are not subject to
New Source Review requirements or New Source Performance Standards under
the Clean Air Act. The rule was challenged in the Federal Appeals Court and
its implementation stayed. In July 2004, the EPA announced it will
reconsider certain issues arising from the final routine equipment
replacement rule. The comment period closed on August 30, 2004. The Company
cannot predict the outcome of this matter.
In 1998, the EPA published a final rule under Section 110 of the Clean Air
Act addressing the regional transport of ozone (NOx SIP Call). Total
capital expenditures to meet the requirements of the NOx SIP Call Rule in
North and South Carolina could reach approximately $370 million. To date,
the Company has spent approximately $282 million related to these projected
amounts. Increased operation and maintenance costs relating to the NOx SIP
Call are not expected to be material to the Company's results of
operations. Further controls are anticipated as electricity demand
increases. Parties unrelated to the Company have undertaken efforts to have
Georgia excluded from the rule and its requirements. Georgia has not yet
submitted a state implementation plan to comply with the Section 110 NOx
SIP Call. The Company cannot predict the outcome of this matter in Georgia.
In 1997, the EPA issued final regulations establishing a new 8-hour ozone
standard. In April 2004, the EPA identified areas that do not meet the
standard. The states with identified areas, including North and South
Carolina, are proceeding with the implementation of the federal 8-hour
ozone standard. Both states promulgated final regulations, which will
require PEC to install NOx controls under the states' programs to comply
with the 8-hour standard. The costs of those controls are included in the
$370 million cost estimate above. However, further technical analysis and
rulemaking may result in requirements for additional controls at some
units. The Company cannot predict the outcome of this matter.
In June 2002, the NC Clean Air legislation was enacted in North Carolina
requiring the state's electric utilities to reduce the emissions of NOx and
SO2 from coal-fired power plants. Progress Energy projects that its capital
costs to meet these emission targets will total approximately $895 million
by the end of 2013. PEC has expended approximately $108 million of these
capital costs through December 31, 2004. PEC currently has approximately
5,100 MW of coal-fired generation capacity in North Carolina that is
affected by this Act. The law requires the emissions reductions to be
completed in phases by 2013, and applies to each utility's total system
rather than setting requirements for individual power plants. The law also
freezes the utilities' base rates for five years unless there are
extraordinary events beyond the control of the utilities or unless the
utilities persistently earn a return substantially in excess of the rate of
return established and found reasonable by the NCUC in the utilities' last
general rate case. The law requires PEC to amortize $569 million,
representing 70% of the original cost estimate of $813 million, during the
five-year rate freeze period. PEC recognized amortization of $174 million
and $74 million for the years ended December 31, 2004, and 2003,
respectively, and has recognized $248 million in cumulative amortization
through December 31, 2004. The remaining amortization requirement of $321
million will be recorded over the three-year period ending December 31,
2007. The law permits PEC the flexibility to vary the amortization schedule
for recording of the compliance costs from none up to $174 million per
year. The NCUC will hold a hearing prior to December 31, 2007, to determine
cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC
entered into an agreement with the State of North Carolina to transfer to
the State certain NOx and SO2 emissions allowances that result from
compliance with the collective NOx and SO2 emissions limitations set out in
the law. The law also requires the State to undertake a study of mercury
and carbon dioxide emissions in North Carolina. Operation and maintenance
costs will increase due to the additional personnel, materials and general
maintenance associated with the equipment. Operation and maintenance
expenses are recoverable through base rates, rather than as part of this
program. Progress Energy cannot predict the future regulatory
interpretation, implementation or impact of this law.
131
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
concluded that mercury is not a risk to the average person in America and
expressed uncertainty about whether reductions in mercury emissions from
coal-fired power plants would reduce human exposure. Nevertheless, the EPA
determined in 2000 that regulation of mercury emissions from coal-fired
power plants was appropriate. In 2003, the EPA proposed alternative control
plans that would limit mercury emissions from coal-fired power plants. The
final rule was released on March 15, 2005. The EPA's rule establishes a
mercury cap and trade program for coal-fired power plants that requires
limits to be met in two phases, in 2010 and 2018. The Company is reviewing
the final rule. Installation of additional air quality controls is likely
to be needed to meet the mercury rule's requirements. Compliance plans and
the cost to comply with the rule will be determined once the Company
completes its review.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
agency estimates the proposal will reduce national nickel emissions to
approximately 103 tons. As proposed, the rule may require the Company to
install additional pollution controls on its residual oil-fired units,
resulting in significant capital expenditures. PEC does not have units
impacted by this proposal; PEF has eight units that are affected, and they
currently do not have pollution controls in place that would meet the
proposed requirements of the nickel rule. The EPA expects to finalize the
nickel rule in March 2005. Compliance costs will be determined following
promulgation of the rule.
In December 2003, the EPA released its proposed Interstate Air Quality
Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The
final rule was released on March 10, 2005. The EPA's rule requires 28
states and the District of Columbia, including North Carolina, South
Carolina, Georgia and Florida, to reduce NOx and SO2 emissions in order to
attain preset state NOx and SO2 emissions levels. The Company is reviewing
the final rule. Installation of additional air quality controls is likely
to be needed to meet the CAIR requirements. Compliance plans and the cost
to comply with the rule will be determined once the Company completes its
review. The air quality controls already installed for compliance with the
NOx SIP Call and currently planned by the Company to comply with the NC
Clean Air legislation will reduce the costs required to meet the CAIR
requirements for the Company's North Carolina units.
In March 2004, the North Carolina Attorney General filed a petition with
the EPA under Section 126 of the Clean Air Act, asking the federal
government to force coal-fired power plants in 13 other states, including
South Carolina, to reduce their NOx and SO2 emissions. The state of North
Carolina contends these out-of-state emissions interfere with North
Carolina's ability to meet national air quality standards for ozone and
particulate matter. The EPA has agreed to make a determination on the
petition by August 1, 2005. The Company cannot predict the outcome of this
matter.
WATER QUALITY
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams may be
generated at the affected facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and treatment requirements imposed on PEC and PEF
in the immediate and extended future.
After many years of litigation and settlement negotiations, the EPA adopted
regulations in February 2004 to implement Section 316(b) of the Clean Water
Act. These regulations became effective September 7, 2004. The purpose of
these regulations is to minimize adverse environmental impacts caused by
cooling water intake structures and intake systems. Over the next several
years these regulations will impact the larger base load generation
facilities and may require the facilities to mitigate the effects to
aquatic organisms by constructing intake modifications or undertaking other
restorative activities. The Company currently estimates that from 2005
through 2009 the range of its expenditures to meet the Section 316(b)
requirements of the Clean Water Act will be $85 million to $115 million.
The range includes $20 million to $30 million at PEC and $65 million to $85
million at PEF.
132
OTHER ENVIRONMENTAL MATTERS
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. In 2004, Russia ratified the Protocol, and the treaty
went into effect on February 16, 2005. The United States has not adopted
the Kyoto Protocol, and the Bush administration has stated it favors
voluntary programs. A number of carbon dioxide emissions control proposals
have been advanced in Congress. Reductions in carbon dioxide emissions to
the levels specified by the Kyoto Protocol and some legislative proposals
could be materially adverse to the Company's consolidated financial
position or results of operations if associated costs of control or
limitation cannot be recovered from customers. The Company favors the
voluntary program approach recommended by the administration and
continually evaluates options for the reduction, avoidance and
sequestration of greenhouse gases. However, the Company cannot predict the
outcome of this matter.
Progress Energy has announced its plan to issue a report on the Company's
activities associated with current and future environmental requirements.
The report will include a discussion of the environmental requirements that
the Company currently faces and expects to face in the future, as well as
an assessment of potential mandatory constraints on carbon dioxide
emissions. The report will be issued by March 31, 2006.
23. COMMITMENTS AND CONTINGENCIES
A. Purchase Obligations
At December 31, 2004, the following table reflects Progress Energy's
contractual cash obligations and other commercial commitments in the
respective periods in which they are due:
- ------------------------------------------------------------------------------------------------------
(in millions) 2005 2006 2007 2008 2009 Thereafter
- ------------------------------------------------------------------------------------------------------
Fuel $ 2,219 $ 1,473 $ 663 $ 229 $ 252 $ 1,270
Purchased power 473 473 479 449 416 4,614
Construction obligations 51 - - - - -
Other purchase obligations 100 70 64 41 39 268
- ------------------------------------------------------------------------------------------------------
Total $ 2,843 $ 2,016 $ 1,206 $ 719 $ 707 $ 6,152
- ------------------------------------------------------------------------------------------------------
FUEL AND PURCHASED POWER
FPC, PEC and Fuels have entered into various long-term contracts for coal,
oil and gas. Payments under these commitments were $2,097 million, $1,719
million and $1,414 million for 2004, 2003 and 2002, respectively.
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between PEC and the North Carolina Eastern Municipal Power Agency (Power
Agency), PEC is obligated to purchase a percentage of Power Agency's
ownership capacity of, and energy from, the Harris Plant. In 1993, PEC and
Power Agency entered into an agreement to restructure portions of their
contracts covering power supplies and interests in jointly owned units.
Under the terms of the 1993 agreement, PEC increased the amount of capacity
and energy purchased from Power Agency's ownership interest in the Harris
Plant, and the buyback period was extended six years through 2007. The
estimated minimum annual payments for these purchases, which reflect
capacity and energy costs, total approximately $38 million. These
contractual purchases totaled $39 million, $36 million and $36 million for
2004, 2003 and 2002, respectively. In 1987, the NCUC ordered PEC to reflect
the recovery of the capacity portion of these costs on a levelized basis
over the original 15-year buyback period, thereby deferring for future
recovery the difference between such costs and amounts collected through
rates. In 1988, the SCPSC ordered similar treatment, but with a 10-year
levelization period. At December 31, 2004, all previously deferred costs
have been expensed.
PEC has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 MW of
capacity through 2009 with estimated minimum annual payments of
approximately $43 million, representing capital-related capacity costs.
Estimated annual payments for energy and capacity costs are approximately
$72 million through 2009. Total purchases (including energy and
transmission use charges) under the Rockport agreement amounted to $63
million, $66 million and $59 million for 2004, 2003 and 2002, respectively.
133
PEC executed two long-term agreements for the purchase of power from Broad
River LLC's Broad River facility. One agreement provides for the purchase
of approximately 500 MW of capacity through 2021 with an original minimum
annual payment of approximately $16 million, primarily representing
capital-related capacity costs. The second agreement provided for the
additional purchase of approximately 300 MW of capacity through 2022 with
an original minimum annual payment of approximately $16 million
representing capital-related capacity costs. Total purchases for both
capacity and energy under the Broad River agreements amounted to $42
million, $37 million and $38 million in 2004, 2003 and 2002 respectively.
PEF has long-term contracts for approximately 489 MW of purchased power
with other utilities, including a contract with The Southern Company for
approximately 414 MW of purchased power annually through 2015. Total
purchases, for both energy and capacity, under these agreements amounted to
$129 million, $124 million and $109 million for 2004, 2003 and 2002,
respectively. Total capacity payments were $56 million, $55 million and $50
million for 2004, 2003 and 2002, respectively. Minimum purchases under
these contracts, representing capital-related capacity costs, at December
31, 2004 are $60 million, $63 million, $65 million, $66 million and $67
million for 2005 through 2009, respectively, and $244 million thereafter.
Both PEC and PEF have ongoing purchased power contracts with certain
cogenerators (qualifying facilities) with expiration dates ranging from
2005 to 2025. These purchased power contracts generally provide for
capacity and energy payments. Energy payments for the PEF contracts are
based on actual power taken under these contracts. Capacity payments are
subject to the qualifying facilities (QFs) meeting certain contract
performance obligations. PEF's total capacity purchases under these
contracts amounted to $248 million, $244 million and $235 million for 2004,
2003 and 2002, respectively. Minimum expected future capacity payments
under these contracts at December 31, 2004, are $271 million, $279 million,
$289 million, $298 million and $263 million for 2005 through 2009,
respectively, and $3.8 billion thereafter. PEC has various
pay-for-performance contracts with QFs for approximately 400 MW of capacity
expiring at various times through 2009. Payments for both capacity and
energy are contingent upon the QFs' ability to generate. Payments made
under these contracts were $91 million in 2004, $113 million in 2003 and
$145 million in 2002.
On December 2, 2004, PEF entered into precedent and related agreements with
Southern Natural Gas Company (SNG), Florida Gas Transmission Company (FGT),
and BG LNG Services, LLC for the supply of natural gas and associated firm
pipeline transportation to augment PEF's gas supply needs for the period
from May 1, 2007, to April 30, 2027. The total cost to PEF associated with
the agreements is approximately $3.3 billion. The transactions are subject
to several conditions precedent, which include obtaining the Florida Public
Service Commission's approval of the agreements, the completion and
commencement of operation of the necessary related expansions to SNG's and
FGT's respective natural gas pipeline systems, and other standard closing
conditions. Due to the conditions in the agreements, the estimated costs
associated with these agreements are not included in the contractual cash
obligations table above.
CONSTRUCTION OBLIGATIONS
The Company has purchase obligations related to various capital
construction projects. Total payments under these contracts were $102
million, $158 million and $143 million for 2004, 2003 and 2002,
respectively.
OTHER PURCHASE OBLIGATIONS
The Company has entered into various other contractual obligations
primarily related to service contracts for operational services entered
into by PESC, a PVI parts and services contract, and a PEF service
agreement related to the Hines Complex. Payments under these agreements
were $69 million, $31 million and $420 million for 2004, 2003 and 2002,
respectively.
On December 31, 2002, PEC and PVI entered into a contractual commitment to
purchase at least $13 million and $4 million, respectively, of capital
parts by December 31, 2010. During 2004 and 2003, no capital parts have
been purchased under this contract.
B. Other Commitments
The Company has certain future commitments related to four synthetic fuel
facilities purchased that provide for contingent payments (royalties). The
related agreements and their amendments require the payment of minimum
annual royalties of approximately $7 million for each plant through 2007.
The Company recorded a liability (included in other liabilities and
deferred credits on the Consolidated Balance Sheets) and a deferred asset
(included in other assets and deferred debits in the Consolidated Balance
Sheets), each of approximately $73 million and $94 million at December 31,
2004 and 2003, respectively, representing the minimum amounts due through
2007, discounted at 6.05%. At December 31, 2004 and 2003, the portions of
the asset and liability recorded that were classified as current were
134
approximately $26 million. The deferred asset will be amortized to expense
each year as synthetic fuel sales are made. The maximum amounts payable
under these agreements remain unchanged. Actual amounts paid under these
agreements were none in 2004, $2 million in 2003 and $51 million in 2002.
Future expected minimum royalty payments are approximately $26 million for
2005 through 2007. The Company has the right in the related agreements and
their amendments that allow the Company to escrow those payments if certain
conditions in the agreements are met. The Company has exercised that right
and retained 2004 and 2003 royalty payments of approximately $42 million
and $48 million, respectively, pending the establishment of the necessary
escrow accounts. Once established, those funds will be placed into escrow.
During 2004 Progress Energy made the first installment of $10 million for a
contract dispute. The installments for 2005 and 2006, respectively, are $16
million and $17 million (See Note 20).
C. Leases
The Company leases office buildings, computer equipment, vehicles, railcars
and other property and equipment with various terms and expiration dates.
Some rental payments for transportation equipment include minimum rentals
plus contingent rentals based on mileage. These contingent rentals are not
significant. Rent expense under operating leases totaled $65 million, $60
million and $71 million for 2004, 2003 and 2002, respectively. Purchased
power expense under agreements classified as operating leases were
approximately $24 million in 2004 and $5 million in 2003.
Assets recorded under capital leases at December 31 consist of:
- -------------------------------------------------------------------
(in millions) 2004 2003
- -------------------------------------------------------------------
Buildings $ 30 $ 30
Equipment and other 2 3
Less: Accumulated amortization (11) (10)
- -------------------------------------------------------------------
$ 21 $ 23
- -------------------------------------------------------------------
Minimum annual payments, excluding executory costs such as property taxes,
insurance and maintenance, under long-term noncancelable leases at December
31, 2004, are:
- -----------------------------------------------------------------------------------------
(in millions) Capital Leases Operating Leases
- -----------------------------------------------------------------------------------------
2005 $ 4 $ 66
2006 4 55
2007 4 58
2008 4 58
2009 3 54
Thereafter 31 307
- -----------------------------------------------------------------------------------------
$ 50 $ 598
-------------------
Less amount representing imputed interest (21)
- ----------------------------------------------------------------------
Present value of net minimum lease payments
under capital leases $ 29
- -----------------------------------------------------------------------------------------
In 2003, the Company entered into a new operating lease for a building, for
which minimum annual rental payments are included in the table above. The
lease terms provide for no rental payments during the last 15 years of the
lease, during which period $53 million of rental expense will be recorded
in the Consolidated Statements of Income.
The Company, excluding PEC and PEF, is also a lessor of land, buildings and
other types of properties it owns under operating leases with various terms
and expiration dates. The leased buildings are depreciated under the same
terms as other buildings included in diversified business property. Minimum
rentals receivable under noncancelable leases for 2005 through 2009 are
approximately $32 million, $22 million, $14 million, $9 million and $6
million, respectively, with $17 million receivable thereafter. Rents
received under these operating leases totaled $63 million, $46 million and
$53 million for 2004, 2003 and 2002, respectively.
PEC is the lessor of electric poles, streetlights and other facilities.
Minimum rentals under noncancelable leases are $9 million for 2005 and none
thereafter. Rents received totaled $32 million, $31 million and $28 million
for 2004, 2003 and 2002, respectively.
135
PEF is the lessor of electric poles, streetlights and other facilities.
Rents received are based on a fixed minimum rental where price varies by
type of equipment and totaled $63 million, $56 million and $52 million for
2004, 2003 and 2002, respectively. Minimum rentals receivable (excluding
streetlights) under noncancelable leases for 2005 is $5 million, for 2006
through 2009 $1 million, and $8 million thereafter. Streetlight rentals
were $40 million, $38 million and $34 million for 2004, 2003 and 2002
respectively. Future streetlight rentals would approximate 2004 revenues.
D. Guarantees
To facilitate commercial transactions of the Company's subsidiaries,
Progress Energy and certain wholly owned subsidiaries enter into agreements
providing future financial or performance assurances to third parties (See
Note 19).
At December 31, 2004, the Company had issued guarantees on behalf of third
parties with an estimated maximum exposure of approximately $10 million.
These guarantees support synthetic fuel operations. At December 31, 2004,
management does not believe conditions are likely for significant
performance under these agreements.
In connection with the sale of partnership interests in Colona (See Note
4B), Progress Fuels indemnified the buyers against any claims related to
Colona resulting from violations of any environmental laws. Although the
terms of the agreement provide for no limitation to the maximum potential
future payments under the indemnification, the Company has estimated that
the maximum total of such payments would not be material.
E. Claims and Uncertainties
OTHER CONTINGENCIES
1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to
PEF and PEC entered into contracts with the U.S. Department of Energy (DOE)
under which the DOE agreed to begin taking spent nuclear fuel by no later
than January 31, 1998. All similarly situated utilities were required to
sign the same standard contract.
DOE failed to begin taking spent nuclear fuel by January 31, 1998. In
January 2004, PEC and PEF filed a complaint in the United States Court of
Federal Claims against the DOE, claiming that the DOE breached the Standard
Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF
from various Progress Energy facilities on or before January 31, 1998.
Damages due to DOE's breach will likely exceed $100 million. Approximately
60 cases involving the Government's actions in connection with spent
nuclear fuel are currently pending in the Court of Federal Claims.
DOE and the PEC/PEF parties have agreed to a stay of the lawsuit, including
discovery. The parties agreed to, and the trial court entered, a stay of
proceedings, in order to allow for possible efficiencies due to the
resolution of legal and factual issues in previously filed cases in which
similar claims are being pursued by other plaintiffs. These issues may
include, among others, so-called "rate issues," or the minimum mandatory
schedule for the acceptance of SNF and high level waste (HLW) by which the
Government was contractually obligated to accept contract holders' SNF
and/or HLW, and issues regarding recovery of damages under a partial breach
of contract theory that will be alleged to occur in the future. These
issues have been or are expected to be presented in the trials that are
currently scheduled to occur during 2005. Resolution of these issues in
other cases could facilitate agreements by the parties in the PEC/PEF
lawsuit, or at a minimum, inform the Court of decisions reached by other
courts if they remain contested and require resolution in this case. The
trial court has continued this stay until June 24, 2005.
With certain modifications and additional approval by the NRC, including
the installation of onsite dry storage facilities at Robinson and
Brunswick, PEC's spent nuclear fuel storage facilities will be sufficient
to provide storage space for spent fuel generated on PEC's system through
the expiration of the operating licenses for all of PEC's nuclear
generating units.
With certain modifications and additional approval by the NRC, including
the installation of onsite dry storage facilities at PEF's nuclear unit,
Crystal River Unit No. 3 (CR3), PEF's spent nuclear fuel storage facilities
will be sufficient to provide storage space for spent fuel generated on
PEF's system through the expiration of the operating license for CR3.
136
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. In January 2003, the State of Nevada,
Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court
of Appeals for the District of Columbia Circuit for review of the
Congressional override resolution. These same parties also challenged EPA's
radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected
the challenge to the constitutionality of the resolution approving Yucca
Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance
period in the radiation protection standard. EPA is currently reworking the
standard but has not stated when the work will be complete. DOE originally
planned to submit a license application to the NRC to construct the Yucca
Mountain facility by the end of 2004. However, in November 2004, DOE
announced it would not submit the license application until mid-2005 or
later. Also in November 2004, Congressional negotiators approved $577
million for fiscal year 2005 for the Yucca Mountain project, approximately
$300 million less than requested by DOE but approximately the same as
approved in 2004. The DOE continues to state it plans to begin operation of
the repository at Yucca Mountain in 2010. PEC and PEF cannot predict the
outcome of this matter.
2. In 2001, PEC entered into a contract to purchase coal from Dynegy
Marketing and Trade (DMT). After DMT experienced financial difficulties,
including credit ratings downgrades by certain credit reporting agencies,
PEC requested credit enhancements in accordance with the terms of the coal
purchase agreement in July 2002. When DMT did not offer credit
enhancements, as required by a provision in the contract, PEC terminated
the contract in July 2002.
PEC initiated a lawsuit seeking a declaratory judgment that the termination
was lawful. DMT counterclaimed, stating the termination was a breach of
contract and an unfair and deceptive trade practice. On March 23, 2004, the
United States District Court for the Eastern District of North Carolina
ruled that PEC was liable for breach of contract, but ruled against DMT on
its unfair and deceptive trade practices claim. On April 6, 2004, the Court
entered a judgment against PEC in the amount of approximately $10 million.
The Court did not rule on DMT's request under the contract for pending
legal costs.
On May 4, 2004, PEC authorized its outside counsel to file a notice of
appeal of the April 6, 2004, judgment, and on May 7, 2004, the notice of
appeal was filed with the United States Court of Appeals for the Fourth
Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the
ground that PEC's notice of appeal should have been filed on or before May
6, 2004. On June 16, 2004, PEC filed a motion with the trial court
requesting an extension of the deadline for the filing of the notice of
appeal. By order dated September 10, 2004, the trial court denied the
extension request. On September 15, 2004, PEC filed a notice of appeal of
the September 10, 2004, order, and by order dated September 29, 2004, the
appellate court consolidated the first and second appeals. DMT's motion to
dismiss the first appeal remains pending.
The consolidated appeal has been fully briefed, and the court of appeals
has indicated that it will hear arguments, which tentatively have been
scheduled for the week of May 23, 2005.
In the first quarter of 2004, PEC recorded a liability for the judgment of
approximately $10 million and a regulatory asset for the probable recovery
through its fuel adjustment clause. The Company cannot predict the outcome
of this matter.
3. On February 1, 2002, the Company filed a complaint with the Surface
Transportation Board (STB) challenging the rates charged by Norfolk
Southern Railway Company (Norfolk Southern) for coal transportation to
certain generating plants. In a decision dated December 23, 2003, the STB
found that the rates were unreasonable, awarded reparations and prescribed
maximum rates. Both parties petitioned the STB for reconsideration of the
December 23, 2003 decision. On October 20, 2004, the STB reconsidered its
December 23, 2003 decision and concluded that the rates charged by Norfolk
Southern were not unreasonable. Because the Company paid the maximum rates
prescribed by the STB in its December 23, 2003 decision for several months
during 2004, which were less than the rates ultimately found to be
reasonable, the STB ordered the Company to pay to Norfolk Southern the
difference between the rate levels plus interest.
The Company subsequently filed a petition with the STB to phase in the new
rates over a period of time, and filed a notice of appeal with the U.S.
Court of Appeals for the D.C. Circuit. Pursuant to an order issued by the
STB on January 6, 2005, the phasing proceeding will proceed on a schedule
that appears likely to produce an STB decision before the end of 2005. On
January 12, 2005, the STB filed a Motion to Dismiss the Company's appeal on
the grounds that its October 20, 2004, order is not "final" until the
Company's phasing application has been decided.
137
As of December 31, 2004, the Company has accrued a liability of $42
million, of which $23 million represents reparations previously remitted to
PEC by Norfolk Southern that are now subject to refund. Of the remaining
$19 million, $17 million has been recorded as deferred fuel cost on the
Consolidated Balance Sheet, while the remaining $2 million attributable to
wholesale customers has been charged to fuel used in electric generation on
the Consolidated Statements of Income.
The Company cannot predict the outcome of this matter.
4. The Company, through its subsidiaries, is a majority owner in five
entities and a minority owner in one entity that owns facilities that
produce synthetic fuel as defined under the Internal Revenue Code (Code).
The production and sale of the synthetic fuel from these facilities qualify
for tax credits under Section 29 if certain requirements are satisfied,
including a requirement that the synthetic fuel differs significantly in
chemical composition from the coal used to produce such synthetic fuel and
that the fuel was produced from a facility that was placed in service
before July 1, 1998. The amount of Section 29 credits that the Company is
allowed to claim in any calendar year is limited by the amount of the
Company's regular federal income tax liability. Synthetic fuel tax credit
amounts allowed but not utilized are carried forward indefinitely as
deferred alternative minimum tax credits. All entities have received PLRs
from the IRS with respect to their synthetic fuel operations. However,
these PLRs do not address the placed-in-service date determination. The
PLRs do not limit the production on which synthetic fuel credits may be
claimed. Total Section 29 credits generated to date (including those
generated by FPC prior to its acquisition by the Company) are approximately
$1.5 billion, of which $713 million has been used to offset regular federal
income tax liability and $745 million is being carried forward as deferred
alternative minimum tax credits. Also, $7 million has not been recognized
due to the decrease in tax liability resulting from expenses incurred for
the 2004 hurricane damage. The current Section 29 tax credit program
expires at the end of 2007.
IMPACT OF HURRICANES
For the year ended December 31, 2004, the Company's synthetic fuel
facilities sold 8.3 million tons of synthetic fuel and the Company recorded
$215 million of Section 29 tax credits. The amount of synthetic fuel sold
and tax credits recorded in 2004 was impacted by hurricane costs that
reduced the Company's projected 2004 regular tax liability.
For the nine months ended September 30, 2004, the Company's synthetic fuel
facilities sold 7.7 million tons of synthetic fuel, which generated an
estimated $204 million of Section 29 tax credits. Due to the anticipated
decrease in the Company's tax liability as a result of expenses incurred
for the 2004 hurricane damage, the Company estimated that it would be able
to use in 2004, or carry forward to future years, only $125 million of
these Section 29 tax credits at September 30, 2004. As a result, the
Company recorded a charge of $79 million related to Section 29 tax credits
at September 30, 2004.
On November 2, 2004, PEF filed a petition with the FPSC to recover $252
million of storm costs plus interest from customers over a two-year period.
Based on a reasonable expectation at December 31, 2004, that the FPSC will
grant the requested recovery of the storm costs, the Company's loss from
the casualty is less than originally anticipated. As of December 31, 2004,
the Company estimates that it will be able to use in 2004, or carry forward
to future years, $215 million of these Section 29 tax credits. Therefore,
the Company recorded tax credits of $90 million for the quarter ended
December 31, 2004, which the Company now anticipates can be used. For the
year ended December 31, 2004, the Company's synthetic fuel facilities sold
8.3 million tons of synthetic fuel, which generated an estimated $222
million of Section 29 tax credits. As of December 31, 2004, the Company
anticipates that approximately $7 million of tax credits related to
synthetic fuel sold during the year could not be used and have not been
recognized.
The Company believes its right to recover storm costs is well established;
however, the Company cannot predict the timing or outcome of this matter.
If the FPSC should deny PEF's petition for the recovery of storm costs in
2005, there could be a material impact on the amount of 2005 synthetic
fuels production and results of operations.
IRS PROCEEDINGS
In September 2002, all of Progress Energy's majority-owned synthetic fuel
entities were accepted into the IRS's Pre-Filing Agreement (PFA) program.
The PFA program allows taxpayers to voluntarily accelerate the IRS exam
process in order to seek resolution of specific issues.
138
In February 2004, subsidiaries of the Company finalized execution of the
Colona Closing Agreement with the IRS concerning their Colona synthetic
fuel facilities. The Colona Closing Agreement provided that the Colona
facilities were placed in service before July 1, 1998, which is one of the
qualification requirements for tax credits under Section 29. The Colona
Closing Agreement further provides that the fuel produced by the Colona
facilities in 2001 is a "qualified fuel" for purposes of the Section 29 tax
credits. This action concluded the PFA program with respect to Colona.
In July 2004, Progress Energy was notified that the IRS field auditors
anticipated taking an adverse position regarding the placed-in-service date
of the Company's four Earthco synthetic fuel facilities. Due to the
auditors' position, the IRS decided to exercise its right to withdraw from
the PFA program with Progress Energy. With the IRS's withdrawal from the
PFA program, the review of Progress Energy's Earthco facilities is back on
the normal procedural audit path of the Company's tax returns. Through
December 31, 2004, the Company, on a consolidated basis, has used or
carried forward approximately $1.0 billion of tax credits generated by
Earthco facilities. If these credits were disallowed, the Company's
one-time exposure for cash tax payments would be $294 million (excluding
interest), and earnings and equity would be reduced by approximately $1.0
billion, excluding interest. Progress Energy's amended $1.13 billion credit
facility includes a covenant that limits the maximum debt-to-total capital
ratio to 68%. This ratio includes other forms of indebtedness such as
guarantees issued by PGN, letters of credit and capital leases. As of
December 31, 2004, the Company's debt-to-total capital ratio was 60.7%
based on the credit agreement definition for this ratio. The impact on this
ratio of reversing approximately $1.0 billion of tax credits and paying
$294 million for taxes would be to increase the ratio to 65.7%.
On October 29, 2004, Progress Energy received the IRS field auditors'
report concluding that the Earthco facilities had not been placed in
service before July 1, 1998, and that the tax credits generated by those
facilities should be disallowed. The Company disagrees with the field audit
team's factual findings and believes that the Earthco facilities were
placed in service before July 1, 1998. The Company also believes that the
report applies an inappropriate legal standard concerning what constitutes
"placed in service." The Company intends to contest the field auditors'
findings and their proposed disallowance of the tax credits.
Because of the disagreement between the Company and the field auditors as
to the proper legal standard to apply, the Company believes that it is
appropriate and helpful to have this issue reviewed by the National Office
of the IRS, just as the National Office reviewed the issues involving
chemical change. Therefore, the Company is asking the National Office to
clarify the legal standard and has initiated this process with the National
Office. The Company believes that the appeals process, including
proceedings before the National Office, could take up to two years to
complete; however, it cannot control the actual timing of resolution and
cannot predict the outcome of this matter.
In management's opinion, the Company is complying with all the necessary
requirements to be allowed such credits under Section 29, and, although it
cannot provide certainty, it believes that it will prevail in these
matters. Accordingly, while the Company adjusted its synthetic fuel
production for 2004 in response to the effects of expenses incurred due to
the hurricane damage and its impact on 2004 tax liability, it has no
current plans to alter its synthetic fuel production schedule for future
years as a result of the IRS field auditors' report. However, should the
Company fail to prevail in these matters, there could be material liability
for previously taken Section 29 tax credits, with a material adverse impact
on earnings and cash flows.
PROPOSED ACCOUNTING RULES FOR UNCERTAIN TAX POSITIONS
In July 2004, the FASB stated that it plans to issue an exposure draft of a
proposed interpretation of SFAS No. 109, "Accounting for Income Taxes,"
(SFAS No. 109) that would address the accounting for uncertain tax
positions. The FASB has indicated that the interpretation would require
that uncertain tax benefits be probable of being sustained in order to
record such benefits in the financial statements. The exposure draft is
expected to be issued in the first quarter of 2005. The Company cannot
predict what actions the FASB will take or how any such actions might
ultimately affect the Company's financial position or results of
operations, but such changes could have a material impact on the Company's
evaluation and recognition of Section 29 tax credits.
139
PERMANENT SUBCOMMITTEE
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29. The investigation is examining the
utilization of the credits, the nature of the technologies and fuels
created, the use of the synthetic fuel and other aspects of Section 29 and
is not specific to the Company's synthetic fuel operations. Progress Energy
is providing information in connection with this investigation. The Company
cannot predict the outcome of this matter.
SALE OF PARTNERSHIP INTEREST
In June 2004, the Company, through its subsidiary, Progress Fuels, sold, in
two transactions, a combined 49.8% partnership interest in Colona Synfuel
Limited Partnership, LLLP, one of its synthetic fuel facilities.
Substantially all proceeds from the sales will be received over time, which
is typical of such sales in the industry. Gain from the sales will be
recognized on a cost recovery basis. The Company's book value of the
interests sold totaled approximately $5 million. The company received total
gross proceeds of $10 million in 2004. Based on projected production and
tax credit levels, the Company anticipates receiving approximately $24
million in 2005, approximately $31 million in 2006, approximately $32
million in 2007 and approximately $8 million through the second quarter of
2008. In the event that the synthetic fuel tax credits from the Colona
facility are reduced, including an increase in the price of oil that could
limit or eliminate synthetic fuel tax credits, the amount of proceeds
realized from the sale could be significantly impacted.
IMPACT OF CRUDE OIL PRICES
Although the Internal Revenue Code Section 29 tax credit program is
expected to continue through 2007, recent unprecedented and unanticipated
increases in the price of oil could limit the amount of those credits or
eliminate them altogether for one or more of the years following 2004. This
possibility is due to a provision of Section 29 that provides that if the
average wellhead price per barrel for unregulated domestic crude oil for
the year (the "Annual Average Price") exceeds a certain threshold value
(the "Threshold Price"), the amount of Section 29 tax credits are reduced
for that year. Also, if the Annual Average Price increases high enough (the
"Phase Out Price"), the Section 29 tax credits are eliminated for that
year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out
Price was $62.94 per barrel. The Threshold Price and the Phase Out Price
are adjusted annually for inflation.
If the Annual Average Price falls between the Threshold Price and the Phase
Out Price for a year, the amount by which Section 29 tax credits are
reduced will depend on where the Average Annual Price falls in that
continuum. For example, for 2003, if the Annual Average Price had been
$56.54 per barrel, there would have been a 50% reduction in the amount of
Section 29 tax credits for that year.
The Secretary of the Treasury calculates the Annual Average Price based on
the Domestic Crude Oil First Purchases Prices published by the Energy
Information Agency (EIA). Because the EIA publishes its information on a
three-month lag, the Secretary of the Treasury finalizes its calculations
three months after the year in question ends. Thus, the Annual Average
Price for calendar year 2003 was published in April 2004.
Although the official notice for 2004 is not expected to be published until
April 2005, the Company does not believe that the Annual Average Price for
2004 will reach the Threshold Price for 2004. Consequently, the Company
does not expect the amount of its 2004 Section 29 tax credits to be
adversely affected by oil prices.
The Company cannot predict with any certainty the Annual Average Price for
2005 or beyond. Therefore, it cannot predict whether the price of oil will
have a material effect on its synthetic fuel business after 2004. However,
if during 2005 through 2007, oil prices remain at historically high levels
or increase, the Company's synthetic fuel business may be adversely
affected for those years, and, depending on the magnitude of such increases
in oil prices, the adverse affect for those years could be material and
could have an impact on the Company's synthetic fuel results of operations
and production plans.
5. The Company and its subsidiaries are involved in various litigation
matters in the ordinary course of business, some of which involve
substantial amounts. Where appropriate, accruals and disclosures have been
made in accordance with SFAS No. 5, "Accounting for Contingencies," to
provide for such matters. In the opinion of management, the final
disposition of pending litigation would not have a material adverse effect
on the Company's consolidated results of operations or financial position.
140
24. SUBSEQUENT EVENTS
Sale of Progress Rail
On February 18, 2005, the Company announced it has entered into a
definitive agreement to sell Progress Rail to One Equity Partners LLC, a
private equity firm unit of J.P. Morgan Chase & Co. Gross cash proceeds
from the transaction will be $405 million, subject to working capital
adjustments. The sale is expected to close by mid-2005, and is subject to
various closing conditions customary to such transactions. Proceeds from
the sale are expected to be used to reduce debt. The Company expects to
report Progress Rail as a discontinued operation in the first quarter of
2005. The carrying amounts for the assets and liabilities of the
discontinued operations disposal group included in the Consolidated Balance
Sheets as of December 31, are as follows:
- ------------------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------------------
Total current assets $ 378 $ 373
Total property, plant & equipment (net) 173 151
Total other assets 40 77
Total current liabilities 156 114
Total long-term liabilities 3 3
Total capitalization 432 484
- ------------------------------------------------------------------------
Cost Management Initiative
On February 28, 2005, as part of a previously announced cost management
initiative, the executive officers of the Company approved a workforce
restructuring. The restructuring will result in a reduction of
approximately 450 positions and is expected to be completed in September
2005. The cost management initiative is designed to permanently reduce by
$75-100 million the projected growth in the Company's annual operation and
maintenance expenses by the end of 2007. In addition to the workforce
restructuring, the cost management initiative includes a voluntary enhanced
retirement program.
In connection with the cost management initiative, the Company expects to
incur one-time pre-tax charges of approximately $130 million. Approximately
$30 million of that amount relates to payments for severance benefits, and
will be recognized in the first quarter of 2005 and paid over time. The
remaining approximately $100 million will be recognized in the second
quarter of 2005 and relates primarily to postretirement benefits that will
be paid over time to those eligible employees who elect to participate in
the voluntary enhanced retirement program. Approximately 3,500 of the
Company's 15,700 employees are eligible to participate in the voluntary
enhanced retirement program. The total cost management initiative charges
could change significantly depending upon how many eligible employees elect
early retirement under the voluntary enhanced retirement program and the
salary, service years and age of such employees.
141
25. CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
- ----------------------------------------------------------------------------------------------------------------------
(in millions except per share data) First Second Third Quarter Fourth Quarter
Quarter Quarter
- ----------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues $ 2,245 $ 2,408 $ 2,761 $ 2,358
Operating income 296 305 584 291
Income from continuing operations
before cumulative effect of changes
in accounting principles 108 153 303 189
Net income 108 154 303 194
Common stock data:
Basic earnings per common share
Income from continuing operations
before cumulative effect of changes
in accounting principles 0.45 0.63 1.25 0.78
Net income 0.45 0.63 1.25 0.80
Diluted earnings per common share
Income from continuing operations
before cumulative effect of changes
in accounting principles 0.45 0.63 1.24 0.78
Net income 0.45 0.63 1.24 0.80
Dividends declared per common share 0.575 0.575 0.575 0.590
Market price per share - High 47.95 47.50 44.32 46.10
Low 43.02 40.09 40.76 40.47
- -------------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 2,187 $ 2,050 $ 2,457 $ 2,047
Operating income 357 274 478 248
Income from continuing operations
before cumulative effect of changes
in accounting principles 207 154 337 113
Net income 219 157 318 88
Common stock data:
Basic earnings per common share
Income from continuing operations
before cumulative effect of changes
in accounting principles 0.89 0.65 1.41 0.47
Net income 0.94 0.66 1.33 0.37
Diluted earnings per common share
Income from continuing operations
before cumulative effect of changes
in accounting principles 0.89 0.65 1.39 0.47
Net income 0.94 0.66 1.31 0.37
Dividends declared per common share 0.560 0.560 0.560 0.575
Market price per share - High 46.10 48.00 45.15 46.00
- Low 37.45 38.99 39.60 41.60
- -------------------------------------------------------------------------------------------------------------------
In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
Fourth quarter 2004 includes a $31 million after-tax gain on sale of
natural gas assets (See Note 4A) and the recording of $90 million of
Section 29 tax credit (See Note 23E). Third quarter 2004 includes the
reversal of $79 million of Section 29 tax credits (See Note 23E). Second
quarter 2004 includes the settlement of civil proceeding related to SRS of
$43 million ($29 million after-tax) (See Note 20). Fourth quarter 2003
includes impairment charges related to Kentucky May and certain Affordable
Housing investments of $38 million ($24 million after-tax) (See Note 10).
Fourth quarter 2003 includes the impact of a cumulative effect for DIG
Issue 20 of $38 million ($23 million after-tax) (See Note 18).
142
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:
We have audited the accompanying consolidated balance sheets of Carolina Power &
Light Company d/b/a Progress Energy Carolinas, Inc., and its subsidiaries (PEC)
at December 31, 2004 and 2003, and the related consolidated statements of
income, retained earnings, comprehensive income, and cash flows for each of the
three years in the period ended December 31, 2004. These financial statements
are the responsibility of the PEC's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. PEC is not required to have, nor
were we engaged to perform, an audit of its internal control over financial
reporting. An audit includes consideration of internal control over financial
reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the
effectiveness of PEC's internal control over financial reporting. Accordingly,
we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of PEC December 31, 2004 and 2003, and
the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2004, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Notes 1D and 13A to the consolidated financial statements, in
2003, PEC adopted Statement of Financial Accounting Standards No. 143 and
Derivative Implementation Group Issue C20.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2005
143
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of INCOME
- -----------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -----------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 3,628 $ 3,589 $ 3,539
Diversified business 1 11 15
- -----------------------------------------------------------------------------------------------------------
Total Operating Revenues 3,629 3,600 3,554
- -----------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel used in electric generation 836 825 752
Purchased power 301 296 347
Operation and maintenance 871 782 802
Depreciation and amortization 570 562 524
Taxes other than on income 173 162 158
Diversified business 1 4 15
Impairment of diversified business long-lived assets - - 101
- -----------------------------------------------------------------------------------------------------------
Total Operating Expenses 2,752 2,631 2,699
- -----------------------------------------------------------------------------------------------------------
Operating Income 877 969 855
- -----------------------------------------------------------------------------------------------------------
Other Income (Expense)
Interest income 4 6 7
Impairment of investments - (21) (25)
Other, net 11 (11) 13
- -----------------------------------------------------------------------------------------------------------
Total Other Income (Expense) 15 (26) (5)
- -----------------------------------------------------------------------------------------------------------
Interest Charges
Interest charges 195 198 217
Allowance for borrowed funds used during construction (3) (1) (5)
- -----------------------------------------------------------------------------------------------------------
Total Interest Charges, Net 192 197 212
- -----------------------------------------------------------------------------------------------------------
Income before Income Tax and Cumulative Effect of Change in
Accounting Principles 700 746 638
Income Tax Expense 239 241 207
- -----------------------------------------------------------------------------------------------------------
Income before Cumulative Effect of Change in Accounting 461 505 431
Principles
Cumulative Effect of Change in Accounting Principles, Net of Tax - (23) -
- -----------------------------------------------------------------------------------------------------------
Net Income 461 482 431
Preferred Stock Dividend Requirement 3 3 3
- -----------------------------------------------------------------------------------------------------------
Earnings for Common Stock $ 458 $ 479 $ 428
- -----------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
144
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------------------
(in millions)
December 31 2004 2003
- ---------------------------------------------------------------------------------------------------
ASSETS
Utility Plant
Utility plant in service $ 13,521 $ 13,331
Accumulated depreciation (5,806) (5,307)
- ---------------------------------------------------------------------------------------------------
Utility plant in service, net 7,715 8,024
Held for future use 5 5
Construction work in progress 379 267
Nuclear fuel, net of amortization 186 159
- ---------------------------------------------------------------------------------------------------
Total Utility Plant, Net 8,285 8,455
- ---------------------------------------------------------------------------------------------------
Current Assets
Cash and cash equivalents 18 12
Short-term investments 82 226
Receivables 397 410
Receivables from affiliated companies 20 27
Inventory 390 387
Deferred fuel cost 140 66
Income taxes receivable 59 37
Prepayments and other current assets 76 63
- ---------------------------------------------------------------------------------------------------
Total Current Assets 1,182 1,228
- ---------------------------------------------------------------------------------------------------
Deferred Debits and Other Assets
Regulatory assets 473 463
Nuclear decommissioning trust funds 581 505
Miscellaneous other property and investments 158 169
Other assets and deferred debits 108 118
- ---------------------------------------------------------------------------------------------------
Total Deferred Debits and Other Assets 1,320 1,255
- ---------------------------------------------------------------------------------------------------
Total Assets $ 10,787 $ 10,938
- ---------------------------------------------------------------------------------------------------
CAPITALIZATION AND LIABILITIES
Common Stock Equity
Common stock without par value, authorized 200 million shares,
160 million shares issued and outstanding at December 31 $ 1,975 $ 1,953
Unearned ESOP common stock (76) (89)
Accumulated other comprehensive loss (114) (7)
Retained earnings 1,287 1,380
- ---------------------------------------------------------------------------------------------------
Total Common Stock Equity 3,072 3,237
Preferred Stock - Not Subject to Mandatory Redemption 59 59
Long-Term Debt, Net 2,750 3,086
- ---------------------------------------------------------------------------------------------------
Total Capitalization 5,881 6,382
- ---------------------------------------------------------------------------------------------------
Current Liabilities
Current portion of long-term debt 300 300
Accounts payable 254 188
Payables to affiliated companies 83 136
Notes payable to affiliated companies 116 25
Interest accrued 77 80
Short-term obligations 221 4
Customer deposits 45 40
Other current liabilities 179 133
- ---------------------------------------------------------------------------------------------------
Total Current Liabilities 1,275 906
- ---------------------------------------------------------------------------------------------------
Deferred Credits and Other Liabilities
Noncurrent income tax liabilities 991 1,057
Accumulated deferred investment tax credits 140 148
Regulatory liabilities 1,052 1,149
Asset retirement obligations 924 932
Accrued pension and other benefits 383 207
Other liabilities and deferred credits 141 157
- ---------------------------------------------------------------------------------------------------
Total Deferred Credits and Other Liabilities 3,631 3,650
- ---------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 17 and 18)
- ---------------------------------------------------------------------------------------------------
Total Capitalization and Liabilities $ 10,787 $ 10,938
- ---------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
145
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of CASH FLOWS
- -------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Operating Activities
Net income $ 461 $ 482 $ 431
Adjustments to reconcile net income to net cash provided by operating
activities:
Impairment of long-lived assets and investments - 21 126
Depreciation and amortization 658 660 631
Cumulative effect of change in accounting principles - 23 -
Deferred income taxes (19) (69) (82)
Investment tax credit (7) (10) (12)
Deferred fuel credit (56) 33 (15)
Cash provided (used) by changes in operating assets and liabilities:
Receivables (4) 10 (13)
Receivables from affiliated companies 7 20 (8)
Inventory (18) (21) 5
Prepayments and other current assets 13 21 (15)
Accounts payable 35 (56) 39
Accounts payable to affiliated companies (53) 24 (19)
Other current liabilities 9 57 (2)
Other 50 38 32
- -------------------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 1,076 1,233 1,098
- -------------------------------------------------------------------------------------------------------------------
Investing Activities
Gross property additions (519) (445) (619)
Proceeds from sale of subsidiaries and other investments 25 28 244
Diversified business property additions and acquisitions - (1) (12)
Nuclear fuel additions (101) (66) (81)
Net contributions to nuclear decommissioning trust (31) (31) (31)
Purchases of short-term investments (2,108) (2,813) (2,962)
Proceeds from sales of short-term investments 2,252 2,587 2,962
Other investing activities (3) (1) (17)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (485) (742) (516)
- -------------------------------------------------------------------------------------------------------------------
Financing Activities
Proceeds from issuance of long-term debt - 588 542
Net increase (decrease) in short-term obligations 217 (437) 177
Net change in intercompany notes 91 74 (97)
Retirement of long-term debt (339) (276) (807)
Dividends paid to parent (551) (443) (397)
Dividends paid on preferred stock (3) (3) (3)
- -------------------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (585) (497) (585)
- -------------------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 6 (6) (3)
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Year 12 18 21
- -------------------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Year $ 18 $ 12 $ 18
- -------------------------------------------------------------------------------------------------------------------
Supplemental Disclosures of Cash Flow Information
Cash paid during the year - interest (net of amount capitalized) $ 185 $ 180 $ 203
income taxes (net of refunds) $ 286 $ 296 $ 319
- -------------------------------------------------------------------------------------------------------------------
See Notes to Consolidated Financial Statements.
146
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of RETAINED EARNINGS
- ----------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ----------------------------------------------------------------------------------------
Retained Earnings at Beginning of Year $ 1,380 $ 1,344 $ 1,313
Net income 461 482 431
Preferred stock dividends at stated rates (3) (3) (3)
Common stock dividends (551) (443) (397)
- ----------------------------------------------------------------------------------------
Retained Earnings at End of Year $ 1,287 $ 1,380 $ 1,344
- ----------------------------------------------------------------------------------------
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
CONSOLIDATED STATEMENTS of COMPREHENSIVE INCOME
- ------------------------------------------------------------------------------------------------------------------------
(in millions)
Years ended December 31 2004 2003 2002
- ------------------------------------------------------------------------------------------------------------------------
Net Income $ 461 $ 482 $ 431
Other Comprehensive Income
Changes in net unrealized losses on cash flow hedges (net of tax
(expense) benefit of $1, ($1) and $9, respectively) (1) 3 (14)
Reclassification adjustment for amounts included in net income
(net of tax benefit of $0, $0 and $8, respectively) - 1 11
Minimum pension liability adjustment (net of tax (expense)
benefit of $68, ($47) and $47, respectively) (106) 72 (73)
- ------------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income $ (107) $ 76 $ (76)
- ------------------------------------------------------------------------------------------------------------------------
Comprehensive Income $ 354 $ 558 $ 355
- ------------------------------------------------------------------------------------------------------------------------
147
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. Organization
Carolina Power & Light Company (CP&L) is a public service corporation
primarily engaged in the generation, transmission, distribution and sale of
electricity in portions of North Carolina and South Carolina. Effective
January 1, 2003, CP&L began doing business under the assumed name Progress
Energy Carolinas, Inc. (PEC). The legal name has not changed and there was
no restructuring of any kind related to the name change. Through its wholly
owned subsidiaries, PEC is involved in several nonregulated business
activities, the most significant of which was Caronet, Inc. (Caronet), its
telecommunications operation. PEC is a wholly owned subsidiary of Progress
Energy, Inc. (the Company or Progress Energy). The Company is a registered
holding company under the Public Utility Holding Company Act of 1935
(PUHCA). Both the Company and its subsidiaries are subject to the
regulatory provisions of PUHCA.
In December 2003, Progress Telecommunications Corporation (PTC) and
Caronet, both indirectly wholly owned subsidiaries of Progress Energy, and
EPIK Communications, Inc. (EPIK), a wholly owned subsidiary of Odyssey
Telecorp, Inc. (Odyssey), contributed substantially all of their assets and
transferred certain liabilities to Progress Telecom, LLC (PT LLC), a
subsidiary of PTC. Subsequently, the stock of Caronet was sold to an
affiliate of Odyssey for $2 million in cash, and Caronet became an indirect
wholly owned subsidiary of Odyssey. No gain or loss was recognized on this
transaction.
B. Basis of Presentation
The consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America
(GAAP) and include the activities of PEC and its majority-owned
subsidiaries. Significant intercompany balances and transactions have been
eliminated in consolidation except as permitted by Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," which provides that profits on intercompany sales to
regulated affiliates are not eliminated if the sales price is reasonable
and the future recovery of the sales price through the ratemaking process
is probable.
The consolidated financial statements of PEC and its subsidiaries include
the majority owned and controlled subsidiaries. Noncontrolling interests in
the subsidiaries are included in other liabilities and deferred credits in
the Consolidated Balance Sheets. Income or losses from these interests are
included in other income in the Consolidated Statements of Income. The
results of operations for minority interest are reported on a net of tax
basis if the underlying subsidiary is structured as a taxable entity.
Unconsolidated investments in companies over which PEC does not have
control, but has the ability to exercise influence over operating and
financial policies (generally 20% - 50% ownership), are accounted for under
the equity method of accounting. These investments are primarily in limited
liability corporations and limited liability partnerships, and the earnings
from these investments are recorded on a pre-tax basis (See Note 16). These
equity method investments are included in miscellaneous other property and
investments in the Consolidated Balance Sheets. At December 31, 2004 and
2003, PEC has equity method investments of approximately $15 million and
$24 million, respectively.
Certain investments in debt and equity securities that have readily
determinable market values, and for which PEC does not have control, are
accounted for as available-for-sale securities at fair value in accordance
with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities." These investments include investments held in trust funds,
pursuant to United States Nuclear Regulatory Commission (NRC) requirements,
to fund certain costs of decommissioning nuclear plants. The fair value of
these trust funds was $581 million and $505 million at December 31, 2004
and 2003, respectively. PEC also actively invests available cash balances
in various financial instruments, such as tax-exempt debt securities that
have stated maturities of 20 years or more. These instruments provide for a
high degree of liquidity through arrangements with banks that provide daily
and weekly liquidity and 7, 28 and 35 day auctions which allow for the
redemption of the investment at its face amount plus earned income. As PEC
intends to sell these instruments generally within 30 days from the balance
sheet date, they are classified as current assets. At December 31, 2004 and
2003, the fair value of these investments was $82 million and $226 million,
respectively. Other investments in debt and equity securities are included
in miscellaneous other property and investments in the Consolidated Balance
Sheets. At December 31, 2004 and 2003, the fair value of these other
investments was $3 million and $2 million, respectively.
Other investments are stated principally at cost. These cost method
investments are included in miscellaneous other property and investments in
the Consolidated Balance Sheets. At December 31, 2004 and 2003, PEC has
approximately $1 million and $1 million, respectively, of cost method
investments.
148
Certain amounts for 2003 and 2002 have been reclassified to conform to the
2004 presentation. Reclassifications include the reclassification of
instruments used in PEC's cash management program from cash and cash
equivalents to short-term investments of $226 million at December 31, 2003
in the Consolidated Balance Sheets. In the Consolidated Statements of Cash
Flow for each of the three years in the period ended December 31, 2004,
total cash balances and total cash flows used in investing activities were
revised to reflect the reclassification of these instruments from cash and
cash equivalents to short-term investments.
C. Consolidation of Variable Interest Entities
PEC consolidates all voting interest entities in which it owns a majority
voting interest and all variable interest entities for which it is the
primary beneficiary in accordance with FASB Interpretation No. 46R,
"Consolidation of Variable Interest Entities - An Interpretation of ARB No.
51" (FIN No. 46R). PEC is the primary beneficiary of and consolidates two
limited partnerships that qualify for federal affordable housing and
historic tax credits under Section 42 of the Internal Revenue Code. As of
December 31, 2004, the total assets of the two entities were $37 million,
the majority of which are collateral for the entities' obligations and are
included in other current assets and miscellaneous other property and
investments in the Consolidated Balance Sheet.
PEC is the primary beneficiary of a limited partnership that invests in 17
low-income housing partnerships that qualify for federal and state tax
credits. PEC has requested but has not received all the necessary
information to determine the primary beneficiary of the limited
partnership's underlying 17 partnership investments, and has applied the
information scope exception in FIN No. 46R, paragraph 4(g) to the 17
partnerships. PEC has no direct exposure to loss from the 17 partnerships;
PEC's only exposure to loss is from its investment of less than $1 million
in the consolidated limited partnership. PEC will continue its efforts to
obtain the necessary information to fully apply FIN No. 46R to the 17
partnerships. PEC believes that if the limited partnership is determined to
be the primary beneficiary of the 17 partnerships, the effect of
consolidating the 17 partnerships would not be significant to PEC's
Consolidated Balance Sheets.
PEC has variable interests in two power plants resulting from long-term
power purchase contracts. PEC has requested the necessary information to
determine if the counterparties are variable interest entities or to
identify the primary beneficiaries. Both entities declined to provide PEC
with the necessary financial information, and PEC has applied the
information scope exception in FIN No. 46R, paragraph 4(g). PEC's only
significant exposure to variability from these contracts results from
fluctuations in the market price of fuel used by the two entities' plants
to produce the power purchased by PEC. PEC is able to recover these fuel
costs under its fuel clause. Total purchases from these counterparties were
approximately $58 million, $53 million and $53 million in 2004, 2003 and
2002, respectively. PEC will continue its efforts to obtain the necessary
information to fully apply FIN No. 46R to these contracts. The combined
generation capacity of the two entities' power plants is approximately 880
MW. PEC believes that if it is determined to be the primary beneficiary of
these two entities, the effect of consolidating the entities would result
in increases to total assets, long-term debt and other liabilities, but
would have an insignificant or no impact on PEC's common stock equity, net
earnings or cash flows. However, because PEC has not received any financial
information from these two counterparties, the impact cannot be determined
at this time.
PEC also has interests in several other variable interest entities for
which PEC is not the primary beneficiary. These arrangements include
investments in approximately 22 limited partnerships, limited liability
corporations and venture capital funds and two building leases with
special-purpose entities. The aggregate maximum loss exposure at December
31, 2004, that PEC could be required to record in its income statement as a
result of these arrangements totals approximately $23 million. The
creditors of these variable interest entities do not have recourse to the
general credit of PEC in excess of the aggregate maximum loss exposure.
149
D. Significant Accounting Policies
USE OF ESTIMATES AND ASSUMPTIONS
In preparing consolidated financial statements that conform with GAAP,
management must make estimates and assumptions that affect the reported
amounts of assets and liabilities, disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
amounts of revenues and expenses reflected during the reporting period.
Actual results could differ from those estimates.
REVENUE RECOGNITION
PEC recognizes electric utility revenue as service is rendered to
customers. Operating revenues include unbilled electric utility revenues
earned when service has been delivered but not billed by the end of the
accounting period. Revenues related to Caronet for the design and
construction of wireless infrastructure were recognized upon completion of
services for each completed phase of design and construction.
FUEL COST DEFERRALS
Fuel expense includes fuel costs or recoveries that are deferred through
fuel clauses established by PEC's regulators. These clauses allow PEC to
recover fuel costs and portions of purchased power costs through surcharges
on customer rates. These deferred fuel costs are recognized in revenues and
fuel expenses as they are billable to customers.
EXCISE TAXES
PEC collects from customers certain excise taxes levied by the state or
local government upon the customer. PEC accounts for excise taxes on a
gross basis. For the years ended December 31, 2004, 2003 and 2002, gross
receipts tax and other excise taxes of approximately $89 million, $81
million and $80 million, respectively, are included in electric revenue and
taxes other than on income on the Consolidated Statements of Income.
INCOME TAXES
Progress Energy and its affiliates file a consolidated federal income tax
return. The consolidated income tax of Progress Energy is allocated to PEC
in accordance with the Intercompany Income Tax Allocation Agreement (Tax
Agreement). The Tax Agreement provides an allocation that recognizes
positive and negative corporate taxable income. The Tax Agreement provides
for an equitable method of apportioning the carryover of uncompensated tax
benefits. Progress Energy tax benefits not related to acquisition interest
expense are allocated to profitable subsidiaries, beginning in 2002, in
accordance with a PUHCA order. Except for the allocation of this Progress
Energy tax benefit, income taxes are provided as if PEC filed a separate
return.
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between the book and tax carrying amounts
of assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties (See Note 11).
STOCK-BASED COMPENSATION
PEC participates in the stock option programs offered by Progress Energy
(See Note 8B). PEC measures compensation expense for stock options as the
difference between the market price of Progress Energy's common stock and
the exercise price of the option at the grant date. The exercise price at
which options are granted by Progress Energy equals the market price at the
grant date, and, accordingly, no compensation expense has been recognized
for stock option grants. For purposes of the pro forma disclosures required
by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure - an Amendment of FASB Statement No. 123" (SFAS No. 148), the
estimated fair value of Progress Energy's stock options is amortized to
expense over the options' vesting period. The following table illustrates
the effect on net income if the fair value method had been applied to all
outstanding and unvested awards in each period.
150
- -----------------------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- -----------------------------------------------------------------------------------------------------
Net income, as reported $ 461 $ 482 $ 431
Deduct: Total stock option expense determined under fair
value method for all awards, net of related tax effects 7 6 5
- -----------------------------------------------------------------------------------------------------
Pro forma net income $ 454 $ 476 $ 426
- -----------------------------------------------------------------------------------------------------
UTILITY PLANT
Utility plant in service is stated at historical cost less accumulated
depreciation. PEC capitalizes all construction-related direct labor and
material costs of units of property as well as indirect construction costs.
Certain costs that would otherwise not be capitalized under GAAP are
capitalized in accordance with regulatory treatment. The cost of renewals
and betterments is also capitalized. Maintenance and repairs of property
(including planned major maintenance activities), and replacements and
renewals of items determined to be less than units of property, are charged
to maintenance expense as incurred. The cost of units of property replaced
or retired, less salvage, is charged to accumulated depreciation. Removal,
disposal or decommissioning costs that do not represent ARO's under SFAS
No. 143 "Accounting for Asset Retirement Obligations," (SFAS No. 143) are
charged to regulatory liabilities.
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform system of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income and the borrowed
funds portion is credited to interest charges.
ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2003, PEC adopted the guidance in SFAS No. 143 to
account for legal obligations associated with the retirement of certain
tangible long-lived assets. The present value of retirement costs for which
PEC has a legal obligation are recorded as liabilities with an equivalent
amount added to the asset cost and depreciated over an appropriate period.
The liability is then accreted over time by applying an interest method of
allocation to the liability.
The adoption of this statement had no impact on the income of PEC, as the
effects were offset by the establishment of a regulatory asset pursuant to
SFAS No. 71 and related orders by the North Carolina Utilities Commission
(NCUC) and the Public Service Commission of South Carolina (SCPSC) (See
Note 6A). The NCUC and SCPSC also issued an order to authorize deferral of
all prospective effects related to SFAS No. 143 as a regulatory asset or
liability. Therefore, SFAS No. 143 has no impact on the income of PEC.
DEPRECIATION AND AMORTIZATION - UTILITY PLANT
For financial reporting purposes, substantially all depreciation of utility
plant other than nuclear fuel is computed on the straight-line method based
on the estimated remaining useful life of the property, adjusted for
estimated salvage (See Note 4A). Pursuant to their rate-setting authority,
the NCUC and SCPSC can also grant approval to accelerate or reduce
depreciation and amortization of utility assets.
Amortization of nuclear fuel costs is computed primarily on the
units-of-production method. In PEC's retail jurisdictions, provisions for
nuclear decommissioning costs are approved by the NCUC and the SCPSC and
are based on site-specific estimates that include the costs for removal of
all radioactive and other structures at the site. In the wholesale
jurisdictions, the provisions for nuclear decommissioning costs are
approved by the Federal Energy Regulatory Commission (FERC).
CASH AND CASH EQUIVALENTS
PEC considers cash and cash equivalents to include unrestricted cash on
hand, cash in banks and temporary investments purchased with a maturity of
three months or less.
151
INVENTORY
PEC accounts for inventory using the average-cost method. Inventories are
valued at the lower cost or market.
REGULATORY ASSETS AND LIABILITIES
PEC's regulated operations are subject to SFAS No. 71, which allows a
regulated company to record costs that have been or are expected to be
allowed in the ratemaking process in a period different from the period in
which the costs would be charged to expense by a nonregulated enterprise.
Accordingly, PEC records assets and liabilities that result from the
regulated ratemaking process that would not be recorded under GAAP for
nonregulated entities. These regulatory assets and liabilities represent
expenses deferred for future recovery from customers or obligations to be
refunded to customers and are primarily classified in the Consolidated
Balance Sheets as regulatory assets and regulatory liabilities (See Note
6A).
DIVERSIFIED BUSINESS PROPERTY
Diversified business property is stated at cost less accumulated
depreciation. If an impairment loss is recognized on an asset, the fair
value becomes its new cost basis. The costs of renewals and betterments are
capitalized. The cost of repairs and maintenance is charged to expense as
incurred. Depreciation is computed on a straight-line basis using the
estimated useful lives disclosed in Note 4B.
UNAMORTIZED DEBT PREMIUMS, DISCOUNTS AND EXPENSES
Long-term debt premiums, discounts and issuance expenses for the utility
are amortized over the life of the related debt using the straight-line
method. Any expenses or call premiums associated with the reacquisition of
debt obligations by the utility are amortized over the remaining life of
the original debt using the straight-line method consistent with ratemaking
treatment (See Note 6A).
DERIVATIVES
Effective January 1, 2001, PEC adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended
by SFAS No. 138 and SFAS No. 149. SFAS No. 133, as amended, establishes
accounting and reporting standards for derivative instruments, including
certain derivative instruments embedded in other contracts, and for hedging
activities. SFAS No. 133 requires that an entity recognize all derivatives
as assets or liabilities in the balance sheet and measure those instruments
at fair value, unless the derivatives meet the SFAS No. 133 criteria for
normal purchases or normal sales and are designated as such. PEC generally
designates derivative instruments as normal purchases or normal sales
whenever the SFAS No. 133 criteria are met. If normal purchase or normal
sale criteria are not met, PEC will generally designate the derivative
instruments as cash flow or fair value hedges if the related SFAS No. 133
hedge criteria are met. During 2003, the FASB reconsidered an
interpretation of SFAS No. 133. See Note 13 for the effect of the
interpretation and additional information regarding risk management
activities and derivative transactions.
ENVIRONMENTAL
As discussed in Note 17, PEC accrues environmental remediation liabilities
when the criteria for SFAS No. 5, "Accounting for Contingencies," has been
met. Environmental expenditures that relate to an existing condition caused
by past operations and that have no future economic benefits are expensed.
Accruals for estimated losses from environmental remediation obligations
generally are recognized no later than completion of the remedial
feasibility study. Such accruals are adjusted as additional information
develops or circumstances change. Costs of future expenditures for
environmental remediation obligations are not discounted to their present
value. Recoveries of environmental remediation costs from other parties are
recognized when their receipt is deemed. Environmental expenditures that
have future economic benefits are capitalized in accordance with PEC's
asset capitalization policy.
IMPAIRMENT OF LONG-LIVED ASSETS AND INVESTMENTS
PEC reviews the recoverability of long-lived tangible and intangible assets
whenever indicators exist. Examples of these indicators include current
period losses, combined with a history of losses or a projection of
continuing losses, or a significant decrease in the market price of a
long-lived asset group. If an indicator exists, then the asset group is
tested for recoverability by comparing the carrying value to the sum of
152
undiscounted expected future cash flows directly attributable to the asset
group. If the asset group is not recoverable through undiscounted cash
flows, then an impairment loss is recognized for the difference between the
carrying value and the fair value of the asset group. The accounting for
impairment of long-lived assets is based on SFAS No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets."
PEC reviews its investments to evaluate whether or not a decline in fair
value below the carrying value is an other-than-temporary decline. PEC
considers various factors, such as the investee's cash position, earnings
and revenue outlook, liquidity and management's ability to raise capital in
determining whether the decline is other-than-temporary. If PEC determines
that an other-than-temporary decline exists in the value of its
investments, it is PEC's policy to write-down these investments to fair
value. See Note 7 for a discussion of impairment evaluations performed and
charges taken.
SUBSIDIARY STOCK TRANSACTIONS
Gains and losses realized as a result of common stock sales by PEC's
subsidiaries are recorded in the Consolidated Statements of Income, except
for any transactions that must be credited directly to equity in accordance
with the provisions of Staff Accounting Bulletin No. 51, "Accounting for
Sales of Stock by a Subsidiary."
2. NEW ACCOUNTING STANDARDS
FASB STAFF POSITION 106-2, "ACCOUNTING AND DISCLOSURE REQUIREMENTS RELATED
TO THE MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND MODERNIZATION ACT OF
2003"
In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (Medicare Act) was signed into law. In accordance
with guidance issued by the FASB in FASB Staff Position 106-1, "Accounting
and Disclosure Requirements Related to the Medicare Prescription Drug
Improvement and Modernization Act of 2003" (FASB Staff Position 106-1), PEC
elected to defer accounting for the effects of the Medicare Act due to
uncertainties regarding the effects of the implementation of the Medicare
Act and the accounting for certain provisions of the Medicare Act. In May
2004, the FASB issued definitive accounting guidance for the Medicare Act
in FASB Staff Position 106-2, which was effective for PEC in the third
quarter of 2004. FASB Staff Position 106-2 results in the recognition of
lower other postretirement employee benefit (OPEB) costs to reflect
prescription drug-related federal subsidies to be received under the
Medicare Act. As a result of the Medicare Act, PEC's accumulated
postretirement benefit obligation as of January 1, 2004, was reduced by
approximately $42 million, and PEC's 2004 net periodic cost was reduced by
approximately $7 million.
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 123 (REVISED 2004),
"SHARE-BASED PAYMENT" (SFAS NO. 123R)
In December 2004, the FASB issued SFAS No. 123R, which revises SFAS No.
123, "Accounting for Stock-Based Compensation" and supersedes Accounting
Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to
Employees." The key requirement of SFAS No. 123R is that the cost of
share-based awards to employees will be measured based on an award's fair
value at the grant date, with such cost to be amortized over the
appropriate service period. Previously, entities could elect to continue
accounting for such awards at their grant date intrinsic value under APB
Opinion No. 25, and PEC made that election. The intrinsic value method
resulted in PEC recording no compensation expense for stock options granted
to employees (See Note 1D).
SFAS No. 123R will be effective for PEC on July 1, 2005. PEC intends to
implement the standard using the required modified prospective method.
Under that method, PEC will record compensation expense under SFAS No. 123R
for all awards it grants after July 1, 2005, and it will record
compensation expense (as previous awards continue to vest) for the unvested
portion of previously granted awards that remain outstanding at July 1,
2005. In 2004, Progress Energy made the decision to cease granting stock
options and intends to replace that compensation program with other
programs. Therefore, the amount of stock option expense expected to be
recorded in 2005 is below the amount that would have been recorded if the
stock option program had continued. PEC expects to record approximately $1
million of pre-tax expense for stock options in 2005.
153
3. HURRICANE RELATED COSTS
Hurricanes Charley and Ivan struck significant portions of PEC's service
territories during the third quarter of 2004. PEC incurred restoration
costs of $13 million, of which $12 million was charged to operation and
maintenance expense and $1 million was charged to capital expenditures. PEC
does not have an ongoing regulatory mechanism to recover storm costs; and
therefore, hurricane restoration costs recorded in the third quarter of
2004 were charged to operations and maintenance expenses or capital
expenditures based on the nature of the work performed. In connection with
other storms, PEC has previously sought and received permission from the
NCUC and the SCPSC to defer storm expenses and amortize them over a
five-year period. PEC did not seek deferral of 2004 hurricane restoration
costs (See Note 6B).
4. PROPERTY, PLANT AND EQUIPMENT
A. Utility Plant
The balances of utility plant in service at December 31 are listed below,
with a range of depreciable lives for each:
- -----------------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------------
Production plant (7-33 years) $ 7,954 $ 8,024
Transmission plant (30-75 years) 1,212 1,155
Distribution plant (12-50 years) 3,701 3,538
General plant and other (8-75 years) 654 614
- -----------------------------------------------------------------------------
Utility plant in service $ 13,521 $ 13,331
- -----------------------------------------------------------------------------
Generally, electric utility plant, other than nuclear fuel, is pledged as
collateral for the first mortgage bonds of PEC (See Note 9).
Allowance for funds used during construction (AFUDC) represents the
estimated debt and equity costs of capital funds necessary to finance the
construction of new regulated assets. As prescribed in the regulatory
uniform systems of accounts, AFUDC is charged to the cost of the plant. The
equity funds portion of AFUDC is credited to other income, and the borrowed
funds portion is credited to interest charges. Regulatory authorities
consider AFUDC an appropriate charge for inclusion in the rates charged to
customers by the utilities over the service life of the property. The
composite AFUDC rate for PEC's electric utility plant was 7.2% in 2004,
4.0% in 2003 and 6.2% in 2002.
Depreciation provisions on utility plant, as a percent of average
depreciable property other than nuclear fuel, were 2.1% in 2004, and 2.7%
in 2003 and 2002, respectively. The depreciation provisions related to
utility plant were $275 million, $345 million and $326 million in 2004,
2003 and 2002, respectively. In addition to utility plant depreciation
provisions, depreciation and amortization expense also includes
decommissioning cost provisions, asset retirement obligations (ARO)
accretion, cost of removal provisions (See Note 4D), regulatory approved
expenses (See Note 6) and clean air amortization (See Note 6B).
During 2004, PEC met the requirements of both the NCUC and the SCPSC for
the implementation of a depreciation study which allowed the utility to
reduce the rates used to calculate depreciation expense. The annual
reduction in depreciation expense is approximately $82 million. The
reduction is due primarily to extended lives at each of PEC's nuclear
units. The new depreciation rates were effective January 1, 2004.
Amortization of nuclear fuel costs, including disposal costs associated
with obligations to the U.S. Department of Energy (DOE) and costs
associated with obligations to the DOE for the decommissioning and
decontamination of enrichment facilities, for the years ended December 31,
2004, 2003 and 2002 were $106 million, $112 million and $109 million,
respectively, and are included in fuel used for electric generation.
B. Diversified Business Property
Gross diversified business property was $7 million at December 31, 2004 and
2003, respectively. These amounts consist primarily of buildings and
equipment that are being depreciated over periods ranging from 31 to 65
years. Accumulated depreciation was $2 million and $1 million at December
31, 2004 and 2003, respectively. Diversified business depreciation expense
was $1 million in 2004 and 2003, and $4 million in 2002. Net diversified
business property is included in miscellaneous other property and
investments on the Consolidated Balance Sheets.
154
C. Joint Ownership of Generating Facilities
PEC holds ownership interests in certain jointly owned generating
facilities. PEC is entitled to shares of the generating capability and
output of each unit equal to their respective ownership interests. PEC also
pays its ownership share of additional construction costs, fuel inventory
purchases and operating expenses. PEC's share of expenses for the jointly
owned facilities is included in the appropriate expense category. PEC's
ownership interest in the jointly owned generating facilities is listed
below with related information at December 31 ($ in millions):
- -------------------------------------------------------------------------------------------------------------
2004 Company Ownership Plant Accumulated Construction
Facility Interest Investment Depreciation Work in Progress
- -------------------------------------------------------------------------------------------------------------
Mayo Plant 83.83% $ 516 $ 249 $ 1
Harris Plant 83.83% 3,185 1,387 13
Brunswick Plant 81.67% 1,624 888 28
Roxboro Unit No. 4 87.06% 323 147 1
- -------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
2003 Company Ownership Plant Accumulated Construction
Facility Interest Investment Depreciation Work In Progress
- -------------------------------------------------------------------------------------------------------------
Mayo Plant 83.83% $ 464 $ 242 $ 50
Harris Plant 83.83% 3,248 1,424 7
Brunswick Plant 81.67% 1,611 885 21
Roxboro Unit No. 4 87.06% 323 139 1
- -------------------------------------------------------------------------------------------------------------
In the tables above, plant investment and accumulated depreciation are not
reduced by the regulatory disallowances related to the Shearon Harris
Nuclear Plant (Harris Plant).
D. Asset Retirement Obligations
At December 31, 2004 and 2003, the asset retirement costs related to
nuclear decommissioning of irradiated plant, net of accumulated
depreciation, totaled $46 million and $113 million, respectively. Funds set
aside in PEC's nuclear decommissioning trust funds for the nuclear
decommissioning liability totaled $580 million and $505 million at December
31, 2004 and 2003, respectively. Net nuclear decommissioning trust
unrealized gains are included in regulatory liabilities (See Note 6A).
Decommissioning cost provisions, which are included in depreciation and
amortization expense, were $31 million in each of 2004, 2003 and 2002.
Management believes that the decommissioning costs that have been and will
be recovered through rates will be sufficient to provide for the costs of
decommissioning. PEC's expense recognized for the disposal or removal of
utility assets that are not SFAS No. 143 asset removal obligations, which
are included in depreciation and amortization expense, were $83 million,
$86 million and $81 million in 2004, 2003 and 2002, respectively.
PEC recognizes removal, nonirradiated decommissioning and dismantlement
costs in regulatory liabilities on the Consolidated Balance Sheets (See
Note 6A). At December 31, 2004, such costs consist of removal costs of $601
million and removal costs for nonirradiated areas at nuclear facilities of
$70 million. At December 31, 2003, such costs consist of removal costs of
$901 million and removal costs for nonirradiated areas at nuclear
facilities of $67 million. During 2004, PEC reduced its estimated removal
costs to take into account the estimates used in the depreciation studies
implemented during 2004 (See Note 4A). This resulted in a downward revision
in the PEC estimated removal costs and equal increase in accumulated
depreciation of approximately $345 million.
PEC re-measured its ARO for the nuclear decommissioning of irradiated
plants to take into account updated site-specific decommissioning cost
studies, which are required by the NCUC every five years. The ARO for
nuclear decommissioning was reduced by $63 million to $924 million.
PEC's most recent site-specific estimates of decommissioning costs were
developed in 2004, using 2004 cost factors, and are based on prompt
dismantlement decommissioning, which reflects the cost of removal of all
radioactive and other structures currently at the site, with such removal
occurring after operating license expiration. These estimates, in 2004
dollars, are $294 million for Robinson Unit No. 2, $290 million for
Brunswick Unit No. 1, $313 million for Brunswick Unit No. 2 and $359
million for the Harris Plant. The estimates are subject to change based on
a variety of factors including, but not limited to, cost escalation,
changes in technology applicable to nuclear decommissioning and changes in
federal, state or local regulations. The cost estimates exclude the portion
attributable to North Carolina Eastern Municipal Power Agency (Power
Agency), which holds an undivided ownership interest in the Brunswick and
Harris nuclear generating facilities. NRC operating licenses held by PEC
currently expire in December 2014 and September 2016 for Brunswick Units 2
155
and 1, respectively. An application to extend these licenses 20 years was
submitted in October 2004. The NRC operating license held by PEC for the
Shearon Harris Nuclear Plant (Harris Plant) currently expires in October
2026. An application to extend this license 20 years is expected to be
submitted in the fourth quarter of 2006. On April 19, 2004, the NRC
announced that it has renewed the operating license for PEC's Robinson
Nuclear Plant (Robinson) for an additional 20 years through July 2030.
PEC has identified but not recognized AROs related to electric transmission
and distribution assets as the result of easements over property not owned
by PEC. These easements are generally perpetual and require retirement
action only upon abandonment or cessation of use of the property for the
specified purpose. The ARO is not estimable for such easements as PEC
intends to utilize these properties indefinitely. In the event PEC decides
to abandon or cease the use of a particular easement, an ARO would be
recorded at that time.
The following table shows the changes to the asset retirement obligations:
- --------------------------------------------------------------------
(in millions)
- --------------------------------------------------------------------
Asset retirement obligations as of January 1, 2003 $ 880
Accretion expense 52
- --------------------------------------------------------------------
Asset retirement obligations as of December 31, 2003 932
Accretion expense 55
Deductions (63)
- --------------------------------------------------------------------
Asset retirement obligations as of December 31, 2004 $ 924
- --------------------------------------------------------------------
E. Insurance
PEC is a member of Nuclear Electric Insurance Limited (NEIL), which
provides primary and excess insurance coverage against property damage to
members' nuclear generating facilities. Under the primary program, PEC is
insured for $500 million at each of its nuclear plants. In addition to
primary coverage, NEIL also provides decontamination, premature
decommissioning and excess property insurance with limits of $2.0 billion
on the Brunswick and Harris Plants and $1.1 billion on the Robinson Plant.
Insurance coverage against incremental costs of replacement power resulting
from prolonged accidental outages at nuclear generating units is also
provided through membership in NEIL. PEC is insured there under, following
a 12-week deductible period, for 52 weeks in the amount of $3 million per
week at the Brunswick and Harris Plants and $2.5 million per week at the
Robinson Plant. An additional 110 weeks of coverage is provided at 80% of
the above weekly amounts. For the current policy period, PEC is subject to
retrospective premium assessments of up to approximately $23 million with
respect to the primary coverage, $27 million with respect to the
decontamination, decommissioning and excess property coverage, and $15
million for the incremental replacement power costs coverage, in the event
covered losses at insured facilities exceed premiums, reserves, reinsurance
and other NEIL resources. Pursuant to regulations of the NRC, PEC's
property damage insurance policies provide that all proceeds from such
insurance be applied, first, to place the plant in a safe and stable
condition after an accident and, second, to decontaminate, before any
proceeds can be used for decommissioning, plant repair or restoration. PEC
is responsible to the extent losses may exceed limits of the coverage
described above.
PEC is insured against public liability for a nuclear incident up to $10.8
billion per occurrence. Under the current provisions of the Price Anderson
Act, which limits liability for accidents at nuclear power plants, PEC, as
an owner of nuclear units, can be assessed for a portion of any third-party
liability claims arising from an accident at any commercial nuclear power
plant in the United States. In the event that public liability claims from
an insured nuclear incident exceed $300 million (currently available
through commercial insurers), PEC would be subject to pro rata assessments
of up to $101 million for each reactor owned per occurrence. Payment of
such assessments would be made over time as necessary to limit the payment
in any one year to no more than $10 million per reactor owned. Congress
could possibly approve revisions to the Price Anderson Act during 2005 that
could include increased limits and assessments per reactor owned. The final
outcome of this matter cannot be predicted at this time.
Under the NEIL policies, if there were multiple terrorism losses occurring
within one year, NEIL would make available one industry aggregate limit of
$3.2 billion, along with any amounts it recovers from reinsurance,
government indemnity or other sources up to the limits for each claimant.
If terrorism losses occurred beyond the one-year period, a new set of
limits and resources would apply. For nuclear liability claims arising out
of terrorist acts, the primary level available through commercial insurers
is now subject to an industry aggregate limit of $300 million. The second
level of coverage obtained through the assessments discussed above would
continue to apply to losses exceeding $300 million and would provide
coverage in excess of any diminished primary limits due to the terrorist
acts.
156
PEC self-insures its transmission and distribution lines against loss due
to storm damage and other natural disasters.
5. CURRENT ASSETS
RECEIVABLES
At December 31, receivables were comprised of:
- ------------------------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------------------------
Trade accounts receivable $ 240 $ 254
Unbilled accounts receivable 155 145
Other receivables 12 28
Allowance for doubtful accounts receivable (10) (17)
- ------------------------------------------------------------------------------
Total receivables $ 397 $ 410
- ------------------------------------------------------------------------------
Income tax receivables and interest income receivables are not included in
this classification. These amounts are included in prepayments and other
current assets on the Consolidated Balance Sheets.
INVENTORY
At December 31, inventory was comprised of:
- ----------------------------------------------------------------------
(in millions) 2004 2003
- ----------------------------------------------------------------------
Fuel for production $ 127 $ 117
Materials and supplies 263 270
- ----------------------------------------------------------------------
Total inventory $ 390 $ 387
- ----------------------------------------------------------------------
6. REGULATORY MATTERS
A. Regulatory Assets and Liabilities
As a regulated entity, PEC is subject to the provisions of SFAS No. 71.
Accordingly, PEC records certain assets and liabilities resulting from the
effects of the ratemaking process that would not be recorded under GAAP for
nonregulated entities. PEC's ability to continue to meet the criteria for
application of SFAS No. 71 may be affected in the future by competitive
forces and restructuring in the electric utility industry. In the event
that SFAS No. 71 no longer applied to a separable portion of PEC's
operations, related regulatory assets and liabilities would be eliminated
unless an appropriate regulatory recovery mechanism was provided.
Additionally, these factors could result in an impairment of utility plant
assets as determined pursuant to SFAS No. 144 (See Note 1D).
157
At December 31, the balances of PEC's regulatory assets (liabilities) were
as follows:
- ---------------------------------------------------------------------------------------------
(in millions) 2004 2003
- ---------------------------------------------------------------------------------------------
Deferred fuel cost - current (Note 6B) $ 140 $ 66
- ---------------------------------------------------------------------------------------------
Deferred fuel cost - long-term (Note 6B) 28 47
Deferred impact of ARO (Note 1D) 305 291
Income taxes recoverable through future rates (Note 11) 36 33
Loss on reacquired debt (Note 1D) 22 22
Storm deferral (Note 3 and 6B) 25 21
Deferred DOE enrichment facilities-related costs 12 19
Other 45 30
- ---------------------------------------------------------------------------------------------
Total long-term regulatory assets 473 463
- ---------------------------------------------------------------------------------------------
Non-ARO cost of removal (Note 4D) (671) (968)
Emission allowance (8) (8)
Net nuclear decommissioning trust unrealized gains (Note 4D) (125) (99)
Clean air compliance (Note 6B) (248) (74)
- ---------------------------------------------------------------------------------------------
Total long-term regulatory liabilities (1,052) (1,149)
- ---------------------------------------------------------------------------------------------
Net regulatory assets (liabilities) $ (439) $ (620)
- ---------------------------------------------------------------------------------------------
Except for portions of deferred fuel, all assets earn a return on the cash
that has not yet been expended, in which case the assets are offset by
liabilities that do not incur a carrying cost. PEC expects to fully recover
these assets and refund the liabilities through customer rates under
current regulatory practice.
B. Retail Rate Matters
As of December 31, 2004, PEC's North Carolina retail fuel costs were
under-recovered by $145 million. This amount is comprised of $117 million
eligible for recovery in 2005 and $28 million deferred from a 2001 order
from the NCUC that cannot be collected during 2005, and has therefore been
classified as a long-term asset. PEC intends to collect this amount by
October 31, 2007.
On October 15, 2004, the SCPSC approved PEC's request to leave fuel rates
unchanged. The deferred fuel balance at December 31, 2004, is $23 million.
This amount is eligible for recovery in PEC's 2005 South Carolina fuel
review.
PEC obtained SCPSC and NCUC approval of fuel factors in annual
fuel-adjustment proceedings. The NCUC approved an annual increase of $62
million, $20 million and $46 million by orders issued in September 2004,
2003 and 2002, respectively. The SCPSC approved PEC's petition each year
and the changes were insignificant.
PEC filed with the SCPSC seeking permission to defer expenses incurred from
the first quarter 2004 winter storm. The SCPSC approved PEC's request to
defer the costs and amortize them ratably over five years beginning in
January 2005. Approximately $9 million related to storm costs was deferred
in 2004.
In October 2003, PEC filed with the NCUC seeking permission to defer
expenses incurred from Hurricane Isabel and the February 2003 winter
storms. In December 2003, the NCUC approved PEC's request to defer the
costs associated with Hurricane Isabel and the February 2003 ice storm and
amortize them over a period of five years. PEC charged approximately $24
million in 2003 from Hurricane Isabel and from ice storms to the deferred
account. PEC recognized $5 million and $3 million of NC storm amortization
during 2004 and 2003, respectively.
The NCUC and SCPSC have approved proposals to accelerate cost recovery of
PEC's nuclear generating assets beginning January 1, 2000, and continuing
through 2009. The aggregate minimum and maximum amounts of cost recovery
are $530 million and $750 million, respectively. Accelerated cost recovery
of these assets resulted in no additional expense in 2004 and 2003 and
additional depreciation expense of approximately $53 million 2002. Total
accelerated depreciation recorded through December 31, 2004 was $403
million.
The North Carolina Clean Smokestacks Act enacted in June 2002 (NC Clean
Air), requires state utilities to reduce emissions of nitrogen oxide (NOx)
and sulfur dioxide (SO2) from coal-fired plants. The NCUC has allowed the
utilities to amortize and recover the costs associated with meeting the new
emission standards over a seven-year period beginning January 1, 2003. The
legislation provides for significant flexibility in the amount of annual
amortization recorded, which allows the utilities to vary the amount
amortized within certain limits. This flexibility provides a utility with
the opportunity to consider the impacts of other factors on its regulatory
return on equity when setting the amortization amount for each year. PEC
recognized $174 million and $74 million of clean air amortization during
2004 and 2003, respectively. This legislation freezes PEC's base rates in
North Carolina for five years, subject to certain conditions (See Note 17).
158
In conjunction with the Florida Progress Corporation (FPC) merger, PEC
reached a settlement with the Public Staff of the NCUC in which it agreed
to provide credits to its nonreal time pricing customers in the amounts of
$3 million in 2002, $5 million in 2003 and $6 million in both 2004 and
2005.
In conjunction with the acquisition of NCNG in 1999, PEC agreed not to seek
a base retail electric rate increase in North Carolina and South Carolina
through December 2004. The agreement not to seek a base retail electric
rate increase in South Carolina was extended to December 2005 in
conjunction with regulatory approval to form a holding company.
C. Regional Transmission Organizations and Standard Market Design
In 2000, the FERC issued Order No. 2000 on RTOs, which set minimum
characteristics and functions that RTOs must meet, including independent
transmission service. In July 2002, the FERC issued its Notice of Proposed
Rulemaking in Docket No. RM01-12-000, Remedying Undue Discrimination
through Open Access Transmission Service and Standard Electricity Market
Design (SMD NOPR). If adopted as proposed, the rules set forth in the SMD
NOPR would have materially alter the manner in which transmission and
generation services are provided and paid for. In April 2003, the FERC
released a White Paper on the Wholesale Market Platform. The White Paper
provided an overview of what the FERC intended to include in a final rule
in the SMD NOPR docket. The White Paper retained the fundamental and most
protested aspects of SMD NOPR, including mandatory RTOs and the FERC's
assertion of jurisdiction over certain aspects of retail service. The FERC
has not yet issued a final rule on SMD NOPR. PEC cannot predict the outcome
of these matters or the effect that they may have on the GridSouth
proceedings currently ongoing before the FERC. However, by order issued
December 22, 2004, the FERC terminated a portion of the proceedings
regarding GridSouth. The GridSouth Companies asked the FERC for further
clarification to the portions of the GridSouth docket it intended to
address. On March 2, 2005, the FERC affirmed that it only intended to close
the mediation portion of the GridSouth docket. It is unknown what impact
the future proceedings will have on PEC's earnings, revenues or prices.
PEC had $33 million invested in GridSouth related to startup costs at
December 31, 2004. PEC expects to recover these startup costs in
conjunction with the GridSouth original structure or in conjunction with
any alternate combined transmission structures that emerge.
D. FERC Market Power Mitigation
A FERC order issued in November 2001 on certain unaffiliated utilities'
triennial market-based wholesale power rate authorization updates required
certain mitigation actions that those utilities would need to take for
sales/purchases within their control areas and required those utilities to
post information on their Web sites regarding their power systems' status.
As a result of a request for rehearing filed by certain market
participants, FERC issued an order delaying the effective date of the
mitigation plan until after a planned technical conference on market power
determination. In December 2003, the FERC issued a staff paper discussing
alternatives and held a technical conference in January 2004. In April
2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market
power of applicants for wholesale market-based rates, and described
additional analyses and mitigation measures that could be presented if an
applicant does not pass one of these interim screens. In July 2004, the
FERC issued an order on rehearing affirming its conclusions in the April
order. In the second order, the FERC initiated a rulemaking to consider
whether the FERC's current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based
rates should be modified in any way. Given the difficulty PEC believes it
would experience in passing one of the interim screens, on August 12, 2004,
PEC notified the FERC that it would revise its Market-based Rate tariff to
restrict it to sales outside PEC's control area and file a new cost-based
tariff for sales within PEC's control area that incorporates the FERC's
default cost-based rate methodologies for sales of one year or less. PEC
anticipates making this filing first quarter of 2005. Although PEC cannot
predict the ultimate outcome of these changes, PEC does not anticipate that
its current operations would be impacted materially if PEC were unable to
sell power at market-based rates in its respective control areas.
159
E. Energy Delivery Capitalization Practice
PEC has reviewed its capitalization policy for its Energy Delivery business
unit. That review indicated that in the areas of outage and emergency work
not associated with major storms and allocation of indirect costs, PEC
should revise the way that it estimates the amount of capital costs
associated with such work. PEC has implemented such changes effective
January 1, 2005, which include more detailed classification of outage and
emergency work and result in more precise estimation and a process of
retesting accounting estimates on an annual basis. As a result of the
changes in accounting estimates for the outage and emergency work and
indirect costs, a lesser proportion of PEC's costs will be capitalized on a
going forward basis. PEC estimates that the impact in 2005 will be that
approximately $25 million of costs that would have been capitalized under
the previous policies will be expensed. Pursuant to SFAS No. 71, PEC has
informed the state regulators having jurisdiction over them of this change
and that the new estimation process will be implemented effective January
1, 2005.
7. IMPAIRMENTS OF LONG-LIVED ASSETS AND INVESTMENTS
PEC applies SFAS No. 144 for the accounting and reporting of impairment or
disposal of long-lived assets. In 2003 and 2002, PEC recorded pre-tax
long-lived asset and investment impairments and other charges of
approximately $21 million and $133 million, respectively.
A. Long-Lived Assets
In 2002, PEC initiated an independent valuation study to assess the
recoverability of Caronet's long-lived assets. Based on this assessment,
PEC recorded asset impairments of $101 million on a pre-tax basis and other
charges of $7 million on a pre-tax basis in the third quarter of 2002. This
write-down constituted a significant reduction in the book value of these
long-lived assets. The long-lived asset impairments included an impairment
of property, plant and equipment, construction work in process and
intangible assets. The impairment charge represents the difference between
the fair value and carrying amount of these long-lived assets. The fair
value of these assets was determined using a valuation study heavily
weighted on the discounted cash flow methodology, while using market
approaches as supporting information.
B. Investments
PEC continually reviews its investments to determine whether a decline in
fair value below the cost basis is other than temporary. In 2003, PEC's
affordable housing investment (AHI) portfolio was reviewed and deemed to be
impaired based on various factors including continued operating losses of
the AHI portfolio and management performance issues arising at certain
properties within the AHI portfolio. As a result, PEC recorded an
impairment on the AHI portfolio of $18 million on a pre-tax basis during
the fourth quarter of 2003. PEC also recorded a pre-tax impairment of $3
million on a cost investment.
In May 2002, Interpath merged with a third party and PEC's ownership was
diluted to approximately 19% of Interpath. As a result, PEC reviewed the
Interpath investment for impairment and wrote off the remaining amount of
its cost-basis investment in Interpath, recording a pre-tax impairment of
$25 million in the third quarter of 2002. In the fourth quarter of 2002,
PEC sold its remaining interest in Interpath for a nominal amount.
8. EQUITY
A. Capitalization
At December 31, 2004, PEC was authorized to issue up to 200 million shares
of common stock. All shares issued and outstanding are held by Progress
Energy.
160
Preferred stock outstanding at December 31, 2004 and 2003 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
- -----------------------------------------------------------------------------------------------
PEC's common stock increased by $22 million, $23 million and $26 million
for the years ended December 31, 2004, 2003 and 2002, respectively, related
primarily to the allocation of ESOP shares.
There are various provisions limiting the use of retained earnings for the
payment of dividends under certain circumstances. At December 31, 2004,
there were no significant restrictions on the use of retained earnings.
PEC's Articles of Incorporation provide that cash dividends on common stock
shall be limited to 75% of net income available for dividends if common
stock equity falls below 25% of total capitalization, and to 50% if common
stock equity falls below 20%. On December 31, 2004, PEC's common stock
equity was approximately 52.2% of total capitalization. Refer to Note 9 for
additional dividend restrictions related to PEC's mortgage.
B. Stock-Based Compensation Plans
EMPLOYEE STOCK OWNERSHIP PLAN
Progress Energy sponsors the Progress Energy 401(k) Savings and Stock
Ownership Plan (401(k)) for which substantially all full-time nonbargaining
unit employees and certain part-time nonbargaining employees within
participating subsidiaries are eligible. PEC is a participating subsidiary
of the 401(k), which has matching and incentive goal features, encourages
systematic savings by employees and provides a method of acquiring Progress
Energy common stock and other diverse investments. The 401(k), as amended
in 1989, is an Employee Stock Ownership Plan (ESOP) that can enter into
acquisition loans to acquire Progress Energy common stock to satisfy 401(k)
common stock needs. Qualification as an ESOP did not change the level of
benefits received by employees under the 401(k). Common stock acquired with
the proceeds of an ESOP loan is held by the 401(k) Trustee in a suspense
account. The common stock is released from the suspense account and made
available for allocation to participants as the ESOP loan is repaid. Such
allocations are used to partially meet common stock needs related to
Progress Energy matching and incentive contributions and/or reinvested
dividends.
There were 3.5 million and 4.0 million ESOP suspense shares at December 31,
2004 and 2003, respectively, with a fair value of $156 million and $183
million, respectively. PEC's matching and incentive goal compensation cost
under the 401(k) is determined based on matching percentages and incentive
goal attainment as defined in the plan. Such compensation cost is allocated
to participants' accounts in the form of Progress Energy common stock, with
the number of shares determined by dividing compensation cost by the common
stock market value at the time of allocation. The 401(k) common stock share
needs are met with open market purchases, with shares released from the
ESOP suspense account and with newly issued shares. Costs for incentive
goal compensation are accrued during the fiscal year and typically paid
with shares in the following year; costs for the matching component are
typically met with shares in the same year incurred. PEC's matching and
incentive cost, which were and will be met with shares released from the
suspense account, totaled approximately $12 million, $11 million and $13
million for the years ended December 31, 2004, 2003 and 2002, respectively.
Matching and incentive cost totaled approximately $18 million, $16 million
and $14 million for the years ended December 31, 2004, 2003 and 2002,
respectively. PEC has a long-term note receivable from the 401(k) Trustee
related to the purchase of common stock from PEC in 1989 (now Progress
Energy common stock). The balance of the note receivable from the 401(k)
Trustee is included in the determination of unearned ESOP common stock,
which reduces common stock equity. Interest income on the note receivable
is not recognized for financial statement purposes.
STOCK OPTION AGREEMENTS
Pursuant to Progress Energy's 1997 Equity Incentive Plan and 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002, Progress
Energy may grant options to purchase shares of common stock to directors,
officers and eligible employees. For the years ended December 31, 2004,
2003 and 2002, respectively, approximately 28 thousand, 3.0 million and 2.9
million common stock options were granted. Of these amounts, approximately
1.9 million and 1.2 million options were granted to officers and eligible
employees of PEC in 2003 and 2002, respectively. No stock options were
161
granted to officers and employees of PEC in 2004. PEC expects to begin
expensing stock options on July 1, 2005, by adopting new FASB guidance on
accounting for stock-based compensation (See Note 2). In 2004, however,
Progress Energy made the decision to cease granting stock options and
intends to replace that compensation program with other programs.
Therefore, the amount of stock option expense expected to be recorded in
2005 is below the amount that would have been recorded if the stock option
program had continued.
The pro forma information presented in Note 1D regarding net income is
required by SFAS No. 148. Under this statement, compensation cost is
measured at the grant date based on the fair value of the award and is
recognized over the vesting period. The pro forma amounts presented in Note
1D have been determined as if PEC had accounted for its employee stock
options under SFAS No. 123.
OTHER STOCK-BASED COMPENSATION PLANS
Progress Energy has additional compensation plans for officers and key
employees that are stock-based in whole or in part. PEC participates in
these plans. The two primary active stock-based compensation programs are
the Performance Share Sub-Plan (PSSP) and the Restricted Stock Awards
program (RSA), both of which were established pursuant to Progress Energy's
1997 Equity Incentive Plan and were continued under the 2002 Equity
Incentive Plan, as amended and restated as of July 10, 2002.
Under the terms of the PSSP, officers and key employees are granted
performance shares on an annual basis that vest over a three-year
consecutive period. Each performance share has a value that is equal to,
and changes with, the value of a share of Progress Energy's common stock,
and dividend equivalents are accrued on, and reinvested in, the performance
shares. The PSSP has two equally weighted performance measures, both of
which are based on Progress Energy's results as compared to a peer group of
utilities. Compensation expense is recognized over the vesting period based
on the expected ultimate cash payout and is reduced by any forfeitures.
The RSA program allows Progress Energy to grant shares of restricted common
stock to officers and key employees of PEC. The restricted shares generally
vest on a graded vesting schedule over a minimum of three years.
Compensation expense, which is based on the fair value of common stock at
the grant date, is recognized over the applicable vesting period and is
reduced by any forfeitures.
The total amount expensed by PEC for other stock-based compensation plans
was $7 million, $15 million and $11 million in 2004, 2003 and 2002,
respectively.
C. Accumulated Other Comprehensive Loss
Components of accumulated other comprehensive loss are as follows:
- ------------------------------------------------------------------------
(in millions) 2004 2003
- ------------------------------------------------------------------------
Loss on cash flow hedges $ (7) $ (6)
Minimum pension liability adjustments (107) (1)
- ------------------------------------------------------------------------
Total accumulated other comprehensive loss $ (114) $ (7)
- ------------------------------------------------------------------------
9. DEBT AND CREDIT FACILITIES
A. Debt and Credit
At December 31, PEC's long-term debt consisted of the following (maturities
and weighted-average interest rates at December 31, 2004):
162
- -----------------------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------------------
First mortgage bonds, maturing 2005-2033 6.33% $ 1,600 $ 1,900
Pollution control obligations, maturing 2017-2024 1.98% 669 708
Unsecured notes, maturing 2012 6.50% 500 500
Medium-term notes, maturing 2008 6.65% 300 300
Unamortized premium and discount, net (19) (22)
Current portion of long-term debt (300) (300)
- -----------------------------------------------------------------------------------
Total Long-Term Debt, Net $ 2,750 $ 3,086
- -----------------------------------------------------------------------------------
At December 31, 2004, PEC had committed lines of credit, which are used to
support its commercial paper borrowings and are included in short-term
obligations. At December 31, 2004, the weighted average interest rate on
borrowings under the lines of credit was 3.29%. PEC is required to pay
minimal annual commitment fees to maintain its credit facilities.
The following table summarizes PEC's credit facilities (in millions):
- -------------------------------------------------------------------------
Desscription Total Outstanding Available
- -------------------------------------------------------------------------
364-Day (expiring 7/27/05) $ 165 $ 90 $ 75
3-Year (expiring 7/31/05) 285 - 285
Less: amounts reserved(a) (131)
- -------------------------------------------------------------------------
$ 450 $ 90 $ 229
- -------------------------------------------------------------------------
(a) To the extent amounts are reserved for commercial paper outstanding or
backing letters of credit, they are not available for additional
borrowings.
At December 31, 2004 and 2003, PEC had $131 million and $4 million,
respectively, of outstanding commercial paper and other short-term debt
classified as short-term obligations. The weighted-average interest rates
of such short-term obligations at December 31, 2004 and 2003 were 2.77% and
2.25%, respectively.
The combined aggregate maturities of long-term debt for 2005 through 2009
are approximately, in millions, $300, $0, $200, $300 and $400,
respectively.
B. Covenants and Default Provisions
FINANCIAL COVENANTS
PEC's credit line contains various terms and conditions that could affect
PEC's ability to borrow under these facilities. These include a maximum
debt to total capital ratio, a material adverse change clause and a
cross-default provision.
PEC's credit line requires a maximum total debt to total capital ratio of
65%. Indebtedness as defined by the bank agreement includes certain letters
of credit and guarantees that are not recorded on the Consolidated Balance
Sheets. At December 31, 2004, PEC's total debt to total capital ratio was
52.3%.
MATERIAL ADVERSE CHANGE CLAUSE
The credit facility of PEC includes a provision under which lenders could
refuse to advance funds in the event of a material adverse change in the
borrower's financial condition.
CROSS-DEFAULT PROVISIONS
PEC's credit lines include cross-default provisions for defaults of
indebtedness in excess of $10 million. PEC's cross-default provisions only
apply to defaults of indebtedness by PEC and its subsidiaries,
respectively, and not to other affiliates of PEC. In addition, the credit
lines of Progress Energy include a similar provision. Progress Energy's
cross-default provisions apply only to defaults of indebtedness by Progress
Energy and its significant subsidiaries, which includes PEC.
163
The lenders may accelerate payment of any outstanding debt if cross-default
provisions are triggered. Any such acceleration would cause a material
adverse change in the respective company's financial condition. Certain
agreements underlying PEC's indebtedness also limit PEC's ability to incur
additional liens or engage in certain types of sale and leaseback
transactions.
OTHER RESTRICTIONS
PEC's mortgage indenture provides that, as long as any first mortgage bonds
are outstanding, cash dividends and distributions on PEC's common stock and
purchases of PEC's common stock are restricted to aggregate net income
available for PEC, since December 31, 1948, plus $3 million, less the
amount of all preferred stock dividends and distributions, and all common
stock purchases, since December 31, 1948. At December 31, 2004, none of
PEC's retained earnings was restricted. Refer to Note 8 for additional
dividend restrictions related to PEC's Articles of Incorporation.
C. Collateralized Obligations
PEC's first mortgage bonds are collateralized by their respective mortgage
indentures. PEC's mortgage constitutes a first lien on substantially all of
its fixed properties, subject to certain permitted encumbrances and
exceptions. The PEC mortgage also constitutes a lien on subsequently
acquired property. At December 31, 2004, PEC had approximately $2.269
billion in first mortgage bonds outstanding, including those related to
pollution control obligations. The PEC mortgage allows the issuance of
additional mortgage bonds upon the satisfaction of certain conditions.
D. Hedging Activities
PEC uses interest rate derivatives to adjust the fixed and variable rate
components of its debt portfolio and to hedge cash flow risk of fixed rate
debt to be issued in the future. See discussion of risk management and
derivative transactions at Note 13.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts of cash and cash equivalents and short-term
obligations approximate fair value due to the short maturities of these
instruments. At December 31, 2004 and 2003, there were miscellaneous
investments consisting primarily of investments in company-owned life
insurance and other benefit plan assets with carrying amounts totaling
approximately $94 million and $90 million, respectively, included in
miscellaneous other property and investments in the Consolidated Balance
Sheets. The carrying amount of these investments approximates fair value
due to the short maturity of certain instruments. Other instruments,
including short-term investments, are presented at fair value in accordance
with GAAP. The carrying amount of PEC's long-term debt, including current
maturities, was $3.050 billion and $3.386 billion at December 31, 2004 and
2003, respectively. The estimated fair value of this debt, as obtained from
quoted market prices for the same or similar issues, was $3.307 billion and
$3.686 billion at December 31, 2004 and 2003, respectively.
External trust funds have been established to fund certain costs of nuclear
decommissioning. These nuclear decommissioning trust funds are invested in
stocks, bonds and cash equivalents. Nuclear decommissioning trust funds are
presented at amounts that approximate fair value. Fair value is obtained
from quoted market prices for the same or similar investments.
11. INCOME TAXES
Deferred income taxes have been provided for temporary differences. These
occur when there are differences between book and tax carrying amounts of
assets and liabilities. Investment tax credits related to regulated
operations have been deferred and are being amortized over the estimated
service life of the related properties. To the extent that the
establishment of deferred income taxes under SFAS No. 109, "Accounting for
Income Taxes," (SFAS No. 109) is different from the recovery of taxes by
PEC through the ratemaking process, the differences are deferred pursuant
to SFAS No. 71. A regulatory asset or liability has been recognized for the
impact of tax expenses or benefits that are recovered or refunded in
different periods by the utility pursuant to rate orders.
164
Accumulated deferred income tax assets (liabilities) at December 31 are:
- ---------------------------------------------------------------------------------------
(in millions) 2004 2003
- ---------------------------------------------------------------------------------------
Current deferred tax asset - other
Included in prepayments and other current assets 36 16
- ---------------------------------------------------------------------------------------
Noncurrent deferred tax asset (liability)
Investments 4 5
Supplemental executive retirement plans 9 7
Other post-employment benefits (OPEB) 52 46
Other pension plans 56 (8)
Income tax credit carry forward 21 22
Accumulated depreciation and property cost differences (960) (1,066)
Deferred costs (13) 26
Deferred fuel (55) 31
Valuation allowance (1) (1)
Miscellaneous other temporary differences, net (1) (39)
- ---------------------------------------------------------------------------------------
Total noncurrent deferred tax liability (888) (977)
- ---------------------------------------------------------------------------------------
Total deferred income tax liabilities were $1,713 million and $1,758
million at December 31, 2004 and 2003, respectively. Total deferred income
tax assets were $861 million and $797 million at December 31, 2004 and
2003, respectively. Total noncurrent income tax liabilities on the
Consolidated Balance Sheets at December 31, 2004 and 2003 include $103
million and $80 million, respectively, related to probable tax liabilities,
on which PEC accrues interest that would be payable with the related tax
amount in future years. All tax contingency reserves relate to
capitalization and basis issues.
The federal income tax credit carry forward at December 31, 2004 consists
of $21 million of general business credit with a carry forward period that
will begin to expire in 2020.
PEC did not establish any additional valuation allowances in 2004. PEC
established additional valuation allowances of $1 million and $4 million
during 2003 and 2002, respectively, due to the uncertainty of realizing
certain future state tax benefits. PEC believes that it is more likely than
not that the results of future operations will generate sufficient taxable
income to allow for the utilization of the remaining deferred tax assets.
Reconciliations of PEC's effective income tax rate to the statutory federal
income tax rate are:
- ------------------------------------------------------------------------------
2004 2003 2002
- ------------------------------------------------------------------------------
Effective income tax rate 34. 1% 32.3% 32.5%
State income taxes, net of federal benefit (2.9) (1.9) (3.1)
Investment tax credit amortization 1.1 1.4 1.9
Progress Energy tax benefit allocation 3.0 3.0 5.0
AFUDC amortization (0.5) (1.5) (5.8)
Other differences, net 0.2 1.7 4.5
- ------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
- ------------------------------------------------------------------------------
165
Income tax expense (benefit) applicable to continuing operations is
comprised of:
- -----------------------------------------------------------------------------
(in millions) 2004 2003 2002
- -----------------------------------------------------------------------------
Income tax expense (credit):
Current - federal $ 232 $ 283 $ 265
state 33 37 36
Deferred - federal (18) (56) (76)
state (1) (13) (6)
Investment tax credit (7) (10) (12)
- -----------------------------------------------------------------------------
Total income tax expense $ 239 $ 241 $ 207
- -----------------------------------------------------------------------------
PEC and each of its wholly owned subsidiaries have entered into a Tax
Agreement with Progress Energy (See Note 1D). PEC's intercompany tax
receivable was $62 million and $40 million at December 31, 2004 and 2003,
respectively.
12. BENEFIT PLANS
PEC and some of its subsidiaries have a noncontributory defined benefit
retirement (pension) plan for substantially all full-time employees. PEC
also has supplementary defined benefit pension plans that provide benefits
to higher-level employees. In addition to pension benefits, PEC and some of
its subsidiaries provide contributory other postretirement benefits (OPEB),
including certain health care and life insurance benefits, for retired
employees who meet specified criteria. PEC uses a measurement date of
December 31 for its pension and OPEB plans.
The components of net periodic benefit cost for the years ended December 31
are:
- --------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
----------------------------------- -----------------------------
(in millions) 2004 2003 2002 2004 2003 2002
- --------------------------------------------------------------------------------------------------------
Service cost $ 24 $ 23 $ 19 $ 6 $ 7 $ 6
Interest cost 52 51 51 15 15 14
Expected return on plan assets (69) (70) (73) (4) (3) (3)
Amortization, net 1 - 1 3 5 2
- --------------------------------------------------------------------------------------------------------
Net periodic cost / (benefit) $ 8 $ 4 $ (2) $ 20 $ 24 $ 19
- --------------------------------------------------------------------------------------------------------
Net periodic cost for other postretirement benefits decreased during 2004
due to the implementation of FASB Staff Position 106-2 (See Note 2).
Prior service costs and benefits are amortized on a straight-line basis
over the average remaining service period of active participants. Actuarial
gains and losses in excess of 10% of the greater of the obligation or the
market-related value of assets are amortized over the average remaining
service period of active participants. PEC uses a five-year averaging
method to determine its market-related value of assets.
166
Reconciliations of the changes in the plans' benefit obligations and the
plans' funded status are:
- ------------------------------------------------------------------------- ---------------------------------
Pension Benefits Other Postretirement Benefits
------------------------- -------------------------------
(in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------
Obligation at January 1 $ 837 $ 802 $ 218 $ 234
Service cost 24 23 6 7
Interest cost 52 51 15 15
Plan amendment 14 - - -
Benefit payments (50) (46) (5) (8)
Actuarial loss (gain) 51 7 28 (30)
- -----------------------------------------------------------------------------------------------------------
Obligation at December 31 928 837 262 218
Fair value of plan assets at December 31 753 694 45 43
- -----------------------------------------------------------------------------------------------------------
Funded status (175) (143) (217) (175)
Unrecognized transition obligation - - 9 23
Unrecognized prior service cost 18 4 - -
Unrecognized net actuarial (gain) loss 181 150 36 (1)
Minimum pension liability adjustment (194) (2) - -
- -----------------------------------------------------------------------------------------------------------
Prepaid (accrued) cost at December 31, net $ (170) $ 9 $ (172) $ (153)
- -----------------------------------------------------------------------------------------------------------
The 2003 OPEB obligation information above has been restated due to the
implementation of FASB Staff Position 106-2 (See Note 2).
The net accrued pension cost of $170 million at December 31, 2004, is
included in accrued pension and other benefits in the Consolidated Balance
Sheets. The net prepaid pension cost of $9 million at December 31, 2003, is
recognized in the Consolidated Balance Sheets as prepaid pension cost of
$28 million, which is included in other assets and deferred debits, and
accrued benefit cost of $19 million, which is included in accrued pension
and other benefits. The defined benefit pension plans with accumulated
benefit obligations in excess of plan assets had projected benefit
obligations totaling $928 million and $22 million at December 31, 2004 and
2003, respectively. Those plans had accumulated benefit obligations
totaling $923 million and $19 million, at December 31, 2004 and 2003,
respectively, plan assets of $753 million at December 31, 2004 and no plan
assets at December 31, 2003. The total accumulated benefit obligation for
pension plans was $923 million and $834 million at December 31, 2004 and
2003, respectively. The accrued OPEB cost is included in accrued pension
and other benefits in the Consolidated Balance Sheets.
A minimum pension liability adjustment of $194 million was recorded at
December 31, 2004. This adjustment resulted in a charge of $18 million to
intangible assets, included in other assets and deferred debits, and a
pre-tax charge of $176 million to accumulated other comprehensive loss, a
component of common stock equity. A minimum pension liability adjustment of
$2 million was recorded at December 31, 2003. This adjustment was offset by
a corresponding pre-tax charge to accumulated other comprehensive loss, a
component of common stock equity.
Reconciliations of the fair value of plan assets are:
- --------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefits Benefits
--------------------- ---------------------
(in millions) 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------
Fair value of plan assets January 1 $ 693 $ 574 $ 43 $ 33
Actual return on plan assets 89 165 5 10
Benefit payments (50) (46) (5) (8)
Employer contributions 21 1 2 8
- --------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 753 $ 694 $ 45 $ 43
- --------------------------------------------------------------------------------------------
In the table above, substantially all employer contributions represent
benefit payments made directly from PEC assets except for the 2004 pension
amount. The remaining benefits payments were made directly from plan
assets. In 2004, PEC made a contribution directly to pension plan assets of
approximately $20 million, which represented its allocated share of a
required Progress Energy contribution. The OPEB benefit payments represent
the net PEC cost after participant contributions. Participant contributions
represent approximately 40% of gross benefit payments.
167
The asset allocation for PEC's plans at the end of 2004 and 2003 and the
target allocation for the plans, by asset category, are as follows:
- ----------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
------------------------------------ ---------------------------------
Target Percentage of Plan Target Percentage of Plan
Allocations Assets at Year End Allocations Assets at Year End
------------- -------------------- ----------- ------------------
Asset Category 2005 2004 2003 2005 2004 2003
- ----------------------------------------------------------------------------------------------------
Equity - domestic 48% 47% 49% 48% 47% 49%
Equity - international 15% 21% 22% 15% 21% 22%
Debt - domestic 12% 9% 11% 12% 9% 11%
Debt - international 10% 11% 11% 10% 11% 11%
Other 15% 12% 7% 15% 12% 7%
- ----------------------------------------------------------------------------------------------------
Total 100% 100% 100% 100% 100% 100%
- ----------------------------------------------------------------------------------------------------
PEC sets target allocations among asset classes to provide broad
diversification to protect against large investment losses and excessive
volatility, while recognizing the importance of offsetting the impacts of
benefit cost escalation. In addition, PEC employs external investment
managers who have complementary investment philosophies and approaches.
Tactical shifts (plus or minus 5%) in asset allocation from the target
allocations are made based on the near-term view of the risk and return
tradeoffs of the asset classes.
In 2005, PEC expects to make no contributions directly to pension plan
assets. The expected benefit payments for the pension benefit plan for 2005
through 2009 and in total for 2010-2014, in millions, are approximately
$59, $57, $58, $62, $64 and $375, respectively. The expected benefit
payments for the OPEB plan for 2005 through 2009 and in total for
2010-2014, in millions, are approximately $14, $15, $16, $16, $17, and $98,
respectively. The expected benefit payments include benefit payments
directly from plan assets and benefit payments directly from Company
assets. The benefit payment amounts reflect the net cost to PEC after any
participant contributions. PEC expects to begin receiving prescription
drug-related federal subsidies in 2006 (See Note 2), and the expected
subsidies for 2006 through 2009 and in total for 2010-2014, in millions,
are approximately $1, $1, $1, $2 and $10, respectively. The expected
benefit payments above do not reflect the potential effects of the 2005
voluntary enhanced retirement program (See Note 18).
The following weighted-average actuarial assumptions were used in the
calculation of the year-end obligation:
- -------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
---------------- -----------------------------
2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
Discount rate 5.90% 6.30% 5.90% 6.30%
Rate of increase in future compensation - supplementary plan 5.25% 5.00% - -
Initial medical cost trend rate for pre-Medicare benefits - - 7.25% 7.25%
Initial medical cost trend rate for post-Medicare benefits - - 7.25% 7.25%
Ultimate medical cost trend rate - - 5.00% 5.25%
Year ultimate medical cost trend rate is achieved - - 2008 2009
- --------------------------------------------------------------------------------------------------- ---------------
PEC's primary defined benefit retirement plan for nonbargaining employees
is a "cash balance" pension plan as defined in EITF Issue No. 03-4.
Therefore, effective December 31, 2003, PEC began to use the traditional
unit credit method for purposes of measuring the benefit obligation of this
plan. Under the traditional unit credit method, no assumptions are included
about future changes in compensation and the accumulated benefit obligation
and projected benefit obligation are the same.
168
The following weighted-average actuarial assumptions were used in the
calculation of the net periodic cost:
- -------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Postretirement Benefits
------------------------- -------------------------------
2004 2003 2002 2004 2003 2002
- -------------------------------------------------------------------------------------------------- --------- ------------
Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50%
Rate of increase in future compensation - nonbargaining - 4.00% 4.00% - - -
Rate of increase in future compensation - supplementary plan 5.00% 4.00% 4.00% - - -
Expected long-term rate of return on plan assets 9.25% 9.25% 9.25% 9.25% 9.25% 9.25%
- -------------------------------------------------------------------------------------------------- --------- ------------
The expected long-term rates of return on plan assets were determined by
considering long-term historical returns for the plans and long-term
projected returns based on the plans' target asset allocations. Those
benchmarks support an expected long-term rate of return between 9.0% and
9.5%. PEC has chosen to use an expected long-term rate of 9.25%.
The medical cost trend rates were assumed to decrease gradually from the
initial rates to the ultimate rates. Assuming a 1% increase in the medical
cost trend rates, the aggregate of the service and interest cost components
of the net periodic OPEB cost for 2004 would increase by $1 million, and
the OPEB obligation at December 31, 2004, would increase by $14 million.
Assuming a 1% decrease in the medical cost trend rates, the aggregate of
the service and interest cost components of the net periodic OPEB cost for
2004 would decrease by $1 million and the OPEB obligation at December 31,
2004, would decrease by $13 million.
13. RISK MANAGEMENT ACTIVITIES AND DERIVATIVES TRANSACTIONS
Under its risk management policy, PEC may use a variety of instruments,
including swaps, options and forward contracts, to manage exposure to
fluctuations in commodity prices and interest rates. Such instruments
contain credit risk if the counterparty fails to perform under the
contract. PEC minimizes such risk by performing credit reviews using, among
other things, publicly available credit ratings of such counterparties.
Potential nonperformance by counterparties is not expected to have a
material effect on the consolidated financial position or consolidated
results of operations of PEC.
A. Commodity Derivatives
GENERAL
Most of PEC's commodity contracts are not derivatives pursuant to SFAS No.
133 or qualify as normal purchases or sales pursuant to SFAS No. 133.
Therefore, such contracts are not recorded at fair value.
During 2003 the FASB reconsidered an interpretation of SFAS No. 133 related
to the pricing of contracts that include broad market indices (e.g., CPI).
In particular, that guidance discussed whether the pricing in a contract
that contains broad market indices could qualify as a normal purchase or
sale (the normal purchase or sale term is a defined accounting term, and
may not, in all cases, indicate whether the contract would be "normal" from
an operating entity viewpoint). The FASB issued final superseding guidance
(DIG Issue C20) on this issue effective October 1, 2003, for PEC. DIG Issue
C20 specifies new pricing-related criteria for qualifying as a normal
purchase or sale, and it required a special transition adjustment as of
October 1, 2003.
PEC determined that it had one existing "normal" contract that was affected
by DIG Issue C20. Pursuant to the provisions of DIG Issue C20, PEC recorded
a pre-tax fair value loss transition adjustment of $38 million ($23 million
after-tax) in the fourth quarter of 2003, which was reported as a
cumulative effect of a change in accounting principle. The subject contract
meets the DIG Issue C20 criteria for normal purchase or sale and,
therefore, was designated as a normal purchase as of October 1, 2003. The
original liability of $38 million associated with the fair value loss is
being amortized to earnings over the term of the related contract. At
December 31, 2004 and 2003, the remaining liability was $26 million and $35
million, respectively.
ECONOMIC DERIVATIVES
Derivative products, primarily electricity and natural gas contracts, are
entered into for economic hedging purposes. While management believes the
economic hedges mitigate exposures to fluctuations in commodity prices,
these instruments are not designated as hedges for accounting purposes and
are monitored consistent with trading positions. PEC manages open positions
with strict policies that limit its exposure to market risk and require
daily reporting to management of potential financial exposures. Gains and
losses from such contracts were not material to results of operations
during 2004, 2003 or 2002, and PEC did not have material outstanding
positions in such contracts at December 31, 2004 or 2003.
169
CASH FLOW HEDGES
PEC uses cash flow hedging strategies to hedge variable interest rates on
long-term and short-term debt and to hedge interest rates with regard to
future fixed-rate debt issuances. As of December 31, 2004, PEC had $110
million notional amount of pay-fixed forward swaps to hedge its exposure to
interest rates with regard to future issuances of debt (pre-issue hedges)
and $21 million notional amount of pay-fixed forward starting swaps to
hedge its exposure to interest rates with regard to an upcoming railcar
lease. On February 4, 2005, PEC entered another $50 million notional amount
of its pre-issue hedges. All the swaps have a computational period of ten
years. These hedges had a fair value liability position of $2 million at
December 31, 2004. PEC had no open cash flow hedges at December 31, 2003.
The ineffective portion of interest rate cash flow hedges was not material
to PEC's results of operations in 2004. As of December 31, 2004, PEC had $7
million of after-tax deferred losses in accumulated other comprehensive
income (OCI), including amounts related to terminated hedges, of which $1
million is expected to be reclassified to earnings within the next 12
months. Due to the volatility of interest rates, the value in OCI is
subject to change prior to its reclassification into earnings.
FAIR VALUE HEDGES
PEC uses fair value hedging strategies to manage its exposure to fixed
interest rates on long-term debt. At December 31, 2004 and 2003, PEC had no
open interest rate fair value hedges.
The notional amounts of interest rate derivatives are not exchanged and do
not represent exposure to credit loss. In the event of default by a
counterparty, the risk in these transactions is the cost of replacing the
agreements at current market rates.
14. RELATED PARTY TRANSACTIONS
The Company's subsidiaries provide and receive services, at cost, to and
from Progress Energy and its subsidiaries, in accordance with agreements
approved by the U.S. Securities and Exchange Commission (SEC) pursuant to
Section 13(b) of the PUHCA. Services include purchasing, human resources,
accounting, legal, transmission and delivery support, engineering
materials, contract support, loaned employees payroll costs, constructions
management and other centralized administrative, management and support
services. The costs of the services are billed on a direct-charge basis,
whenever possible, and on allocation factors for general costs that cannot
be directly attributed. Billings from affiliates are capitalized or
expensed depending on the nature of the services rendered. Amounts
receivable from and/or payable to affiliated companies for these services
are included in receivables from affiliated companies and payables to
affiliated companies on the Consolidated Balance Sheets.
Progress Energy Service Company, LLC, (PESC) provides the majority of the
affiliated services under the approved agreements. Service provided by PESC
during 2004, 2003 and 2002 to PEC amounted to $209 million, $184 million
and $198 million, respectively. Based on a standard review by the Office of
Public Utility Regulation within the SEC the method for allocating certain
PESC governance costs changed and retroactive reallocations for 2002 and
2001 charges were recorded in 2003. The net after-tax impact of the
reallocation of costs was a reduction of expenses at PEC by $10 million.
PEC and an affiliated utility also provide and receive services at cost.
Services provided by PEC during 2004, 2003 and 2002 amount to $52 million,
$35 million and $72 million, respectively. Services received by PEC during
2004, 2003 and 2002 amount to $16 million, $7 million and $16 million,
respectively.
To facilitate commercial transactions of Progress Energy's subsidiaries,
Progress Energy and certain wholly owned subsidiaries enter into agreements
providing future financial or performance assurances to third parties. As
of December 31, 2004, Progress Energy's guarantees include $181 million to
support nuclear decommissioning. PEC determined that its external funding
levels did not fully meet the nuclear decommissioning financial assurance
levels required by NRC, therefore PEC obtained parent company guarantees.
The Company and PEC also purchased $43 million of surety bonds and
authorized the issuance of standby letters of credit by financial
institutions of $4 million on behalf of PEC.
170
PEC participates in an internal money pool, operated by Progress Energy, to
more effectively utilize cash resources and to reduce outside short-term
borrowings. The money pool is also used to settle intercompany balances.
The weighted-average interest rate for the money pool was 1.72%, 1.47% and
2.18% at December 31, 2004, 2003 and 2002, respectively. Amounts payable to
the money pool are included in notes payable to affiliated companies on the
Consolidated Balance Sheets. PEC recorded insignificant interest expense
related to the money pool for all the years presented.
The Company sold North Carolina Natural Gas Corporation (NCNG) to Piedmont
Natural Gas Company, Inc., on September 30, 2003. During the years ended
December 31, 2003 and 2002, gas sales from NCNG to PEC amounted to $11
million and $18 million, respectively. The gas sales for 2003 indicated
above exclude any sales subsequent to September 2003. Strategic Resource
Solutions, Corp. and its subsidiary, which were wholly owned until 2004,
managed subcontracts for PEC. Amounts for the three years presented were
not significant. PEC has entered into a Tax Agreement with Progress Energy
(See Note 11).
15. FINANCIAL INFORMATION BY BUSINESS SEGMENT
PEC's operations consist primarily of the PEC Electric segment, which is
engaged in the generation, transmission, distribution and sale of electric
energy primarily in portions of North Carolina and South Carolina. These
electric operations are subject to the rules and regulations of the FERC,
the NCUC, the SCPSC and the NRC.
The Other segment, whose operations are primarily in the United States, is
made up of other nonregulated business areas including telecommunications
and other nonregulated subsidiaries that do not separately meet the
disclosure requirements of SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information" and consolidation entities and
eliminations. Included are the operations of Caronet, which recognized an
$87 million after-tax asset and investment impairment in 2002.
- -------------------------------------------------------------------------------------------------
(in millions) PEC Electric Other Total
- -------------------------------------------------------------------------------------------------
Year Ended December 31, 2004
Revenues $ 3,628 $ 1 $ 3,629
Depreciation and amortization 570 - 570
Total interest charges, net 192 - 192
Income tax expense (benefit) 237 2 239
Income (loss) excluding cumulative effect 464 (6) 458
Total segment assets 10,590 197 10,787
Capital and investment
expenditures 519 - 519
- -------------------------------------------------------------------------------------------------
Year Ended December 31, 2003
Revenues $ 3,589 $ 11 $ 3,600
Depreciation and amortization 562 1 563
Total interest charges, net 197 - 197
Impairment of long-lived assets &
investments 11 10 21
Income tax expense (benefit) 238 3 241
Income (loss) excluding cumulative effect 515 (13) 502
Total segment assets 10,748 190 10,938
Capital and investment
expenditures 445 1 446
- -------------------------------------------------------------------------------------------------
Year Ended December 31, 2002
Revenues $ 3,539 $ 15 $ 3,554
Depreciation and amortization 524 4 528
Total interest charges, net 212 - 212
Impairment of long-lived assets &
investments - 126 126
Income tax expense (benefit) 237 (30) 207
Income (loss) excluding cumulative effect 513 (85) 428
Total segment assets 10,139 266 10,405
Capital and investment
expenditures 619 12 631
- -------------------------------------------------------------------------------------------------
171
16. OTHER INCOME AND OTHER EXPENSE
Other income and expense includes interest income, impairment of
investments and other income and expense items as discussed below. The
components of other, net, as shown on the Consolidated Statements of Income
for years ended December 31, are as follows:
- ---------------------------------------------------------------------------------------
(in millions) 2004 2003 2002
- ---------------------------------------------------------------------------------------
Other income
Nonregulated energy and delivery services income $ 15 $ 12 $ 16
DIG Issue C20 amortization (Note 13A) 9 2 -
AFUDC equity 4 2 6
Gain on sale of property 12 6 3
Other 2 - 16
- ---------------------------------------------------------------------------------------
Total other income $ 42 $ 22 $ 41
- ---------------------------------------------------------------------------------------
Other expense
Nonregulated energy and delivery services expenses $ 9 $ 9 $ 14
Donations 7 6 7
Losses from Equity Investments 1 16 7
Other 14 2 -
- ---------------------------------------------------------------------------------------
Total other expense $ 31 $ 33 $ 28
- ---------------------------------------------------------------------------------------
Other, net 11 (11) 13
- ---------------------------------------------------------------------------------------
Nonregulated energy and delivery services include power protection services
and mass market programs (surge protection, appliance services and area
light sales) and delivery, transmission and substation work for other
utilities.
17. ENVIRONMENTAL MATTERS
PEC is subject to federal, state and local regulations addressing hazardous
and solid waste management, air and water quality and other environmental
matters.
HAZARDOUS AND SOLID WASTE MANAGEMENT
The provisions of the Comprehensive Environmental Response, Compensation
and Liability Act of 1980, as amended (CERCLA), authorize the EPA to
require the cleanup of hazardous waste sites. This statute imposes
retroactive joint and several liabilities. Some states, including North and
South Carolina, have similar types of legislation. PEC is periodically
notified by regulators including the EPA and various state agencies of
their involvement or potential involvement in sites that may require
investigation and/or remediation. There are presently several sites with
respect to which PEC has been notified by the EPA and the State of North
Carolina of its potential liability, as described below in greater detail.
PEC is also currently in the process of assessing potential costs and
exposures at other sites. For all sites, assessments are developed and
analyzed, PEC will accrue costs for the sites to the extent the costs are
probable and can be reasonably estimated.
Various organic materials associated with the production of manufactured
gas, generally referred to as coal tar, are regulated under federal and
state laws. The principal regulatory agency that is responsible for a
specific former manufactured gas plant (MGP) site depends largely upon the
state in which the site is located. There are several MGP sites to which
PEC has some connection. In this regard, PEC and other potentially
responsible parties (PRPs) are participating in, investigating and, if
necessary, remediating former MGP sites with several regulatory agencies,
including, but not limited to, the U.S. Environmental Protection Agency
(EPA) and the North Carolina Department of Environment and Natural
Resources, Division of Waste Management (DWM).
PEC has filed claims with its general liability insurance carriers to
recover costs arising from actual or potential environmental liabilities.
All claims have been settled other than with insolvent carriers. These
settlements have not had a material effect on the consolidated financial
position or results of operations.
172
ENVIRONMENTAL LIABILITIES
There are nine former MGP sites and a number of other sites associated with
PEC that have required or are anticipated to require investigation and/or
remediation costs.
During the fourth quarter of 2004, the EPA advised PEC that it had been
identified as a PRP at the Ward Transformer site located in Raleigh, North
Carolina. The EPA offered PEC and 34 other PRPs the opportunity to
negotiate cleanup of the site and reimbursement of less than $2 million to
the EPA for EPA's past expenditures in addressing conditions at the site.
Although a loss is considered probable, an agreement among PRPs has not
been reached; consequently, it is not possible at this time to reasonably
estimate the total amount of PEC's obligation for remediation of the Ward
Transformer site.
At December 31, 2004 and 2003, PEC's accruals for probable and estimable
costs related to various environmental sites, which are included in other
liabilities and deferred credits and are expected to be paid out over many
years, were:
- -----------------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------------
Insurance fund $ 7 $ 9
Transferred from NCNG at time of sale 2 2
- -----------------------------------------------------------------------
Total accrual for environmental sites $ 9 $ 11
- -----------------------------------------------------------------------
PEC received insurance proceeds to address costs associated with
environmental liabilities related to its involvement with some sites. All
eligible expenses related to these are charged against a specific fund
containing these proceeds. PEC spent approximately $2 million related to
environmental remediation in 2004. PEC is unable to provide an estimate of
the reasonably possible total remediation costs beyond what is currently
accrued due to the fact that investigations have not been completed at all
sites.
This accrual has been recorded on an undiscounted basis. PEC measures its
liability for these sites based on available evidence including its
experience in investigating and remediating environmentally impaired sites.
The process often involves assessing and developing cost-sharing
arrangements with other PRPs. PEC will accrue costs for the sites to the
extent its liability is probable and the costs can be reasonably estimated.
Because the extent of environmental impact, allocation among PRPs for all
sites, remediation alternatives (which could involve either minimal or
significant efforts), and concurrence of the regulatory authorities have
not yet reached the stage where a reasonable estimate of the remediation
costs can be made, PEC cannot determine the total costs that may be
incurred in connection with the remediation of all sites at this time. It
is anticipated that sufficient information will become available for
several sites during 2005 to allow a reasonable estimate of PEC's
obligation for those sites to be made.
AIR QUALITY
Congress is considering legislation that would require reductions in air
emissions of NOx, SO2, carbon dioxide and mercury. Some of these proposals
establish nationwide caps and emission rates over an extended period of
time. This national multi-pollutant approach to air pollution control could
involve significant capital costs, which could be material to PEC's
consolidated financial position or results of operations. Control equipment
that will be installed on North Carolina fossil generating facilities as
part of the NC Clean Air legislation discussed below may address some of
the issues outlined above. However, PEC cannot predict the outcome of this
matter.
The EPA is conducting an enforcement initiative related to a number of
coal-fired utility power plants in an effort to determine whether changes
at those facilities were subject to New Source Review requirements or New
Source Performance Standards under the Clean Air Act. PEC was asked to
provide information to the EPA as part of this initiative and cooperated in
supplying the requested information. The EPA initiated civil enforcement
actions against other unaffiliated utilities as part of this initiative.
Some of these actions resulted in settlement agreements calling for
expenditures by these unaffiliated utilities, in excess of $1.0 billion.
These settlement agreements have generally called for expenditures to be
made over extended time periods, and some of the companies may seek
recovery of the related cost through rate adjustments or similar
mechanisms. PEC cannot predict the outcome of this matter.
In 2003, the EPA published a final rule addressing routine equipment
replacement under the New Source Review program. The rule defines routine
equipment replacement and the types of activities that are not subject to
New Source Review requirements or New Source Performance Standards under
the Clean Air Act. The rule was challenged in the Federal Appeals Court and
its implementation stayed. In July 2004, the EPA announced it will
reconsider certain issues arising from the final routine equipment
replacement rule. The comment period closed on August 30, 2004. PEC cannot
predict the outcome of this matter.
173
In 1998, the EPA published a final rule under Section 110 of the Clean Air
Act addressing the regional transport of ozone (NOx SIP Call). Total
capital expenditures to meet the requirements of the NOx SIP Call Rule in
North and South Carolina could reach approximately $370 million. PEC has
spent approximately $282 million to date related to these projected
amounts. Increased operation and maintenance costs relating to the NOx SIP
Call are not expected to be material to PEC's results of operations.
Further controls are anticipated as electricity demand increases.
In 1997, the EPA issued final regulations establishing a new 8-hour ozone
standard. In April 2004, the EPA identified areas that do not meet the
standard. The states with identified areas, including North and South
Carolina, are proceeding with the implementation of the federal 8-hour
ozone standard. Both states promulgated final regulations, which will
require PEC to install NOx controls under the states' programs to comply
with the 8-hour standard. The costs of those controls are included in the
$370 million cost estimate above. However, further technical analysis and
rulemaking may result in requirements for additional controls at some
units. PEC cannot predict the outcome of this matter.
In June 2002, the NC Clean Air legislation was enacted in North Carolina
requiring the state's electric utilities to reduce the emissions of NOx and
SO2 from coal-fired power plants. Progress Energy projects that its capital
costs to meet these emission targets will total approximately $895 million
by the end of 2013. PEC has expended approximately $108 million of these
capital costs through December 31, 2004. PEC currently has approximately
5,100 MW of coal-fired generation capacity in North Carolina that is
affected by this Act. The law requires the emissions reductions to be
completed in phases by 2013, and applies to each utility's total system
rather than setting requirements for individual power plants. The law also
freezes the utilities' base rates for five years unless there are
extraordinary events beyond the control of the utilities or unless the
utilities persistently earn a return substantially in excess of the rate of
return established and found reasonable by the NCUC in the utilities' last
general rate case. The law requires PEC to amortize $569 million,
representing 70% of the original cost estimate of $813 million, during the
five-year rate freeze period. PEC recognized amortization of $174 million
and $74 million for the years ended December 31, 2004, and 2003,
respectively, and has recognized $248 million in cumulative amortization
through December 31, 2004. The remaining amortization requirement of $321
million will be recorded over the three-year period ending December 31,
2007. The law permits PEC the flexibility to vary the amortization schedule
for recording of the compliance costs from none up to $174 million per
year. The NCUC will hold a hearing prior to December 31, 2007, to determine
cost recovery amounts for 2008 and future periods. Pursuant to the law, PEC
entered into an agreement with the State of North Carolina to transfer to
the State certain NOx and SO2 emissions allowances that result from
compliance with the collective NOx and SO2 emissions limitations set out in
the law. The law also requires the State to undertake a study of mercury
and carbon dioxide emissions in North Carolina. Operation and maintenance
costs will increase due to the additional personnel, materials and general
maintenance associated with the equipment. Operation and maintenance
expenses are recoverable through base rates, rather than as part of this
program. PEC cannot predict the future regulatory interpretation,
implementation or impact of this law.
In 1997, the EPA's Mercury Study Report and Utility Report to Congress
concluded that mercury is not a risk to the average person in America and
expressed uncertainty about whether reductions in mercury emissions from
coal-fired power plants would reduce human exposure. Nevertheless, the EPA
determined in 2000 that regulation of mercury emissions from coal-fired
power plants was appropriate. In 2003, the EPA proposed alternative control
plans that would limit mercury emissions from coal-fired power plants. The
final rule was released on March 15, 2005. The EPA's rule establishes a
mercury cap and trade program for coal-fired power plants that requires
limits to be met in two phases, in 2010 and 2018. PEC is reviewing the
final rule. Installation of additional air quality controls is likely to be
needed to meet the mercury rule's requirements. Compliance plans and the
cost to comply with the rule will be determined once PEC completes its
review.
In conjunction with the proposed mercury rule, the EPA proposed a MACT
standard to regulate nickel emissions from residual oil-fired units. The
agency estimates the proposal will reduce national nickel emissions to
approximately 103 tons. PEC does not have units impacted by this proposal.
The EPA expects to finalize the nickel rule in March 2005.
In December 2003, the EPA released its proposed Interstate Air Quality
Rule, currently referred to as the Clean Air Interstate Rule (CAIR). The
final rule was released on March 10, 2005. The EPA's rule requires 28
states and the District of Columbia, including North Carolina and South
Carolina, to reduce NOx and SO2 emissions in order to attain preset state
NOx and SO2 emissions levels. PEC is reviewing the final rule. Installation
174
of additional air quality controls is likely to be needed to meet the CAIR
requirements. Compliance plans and the cost to comply with the rule will be
determined once PEC completes its review. The air quality controls already
installed for compliance with the NOx SIP Call and currently planned by PEC
to comply with the NC Clean Air legislation will reduce the costs required
to meet the CAIR requirements for PEC's North Carolina units.
In March 2004, the North Carolina Attorney General filed a petition with
the EPA under Section 126 of the Clean Air Act, asking the federal
government to force coal-fired power plants in 13 other states, including
South Carolina to reduce their NOx and SO2 emissions. The state of North
Carolina contends these out-of-state emissions interfere with North
Carolina's ability to meet national air quality standards for ozone and
particulate matter. The EPA has agreed to make a determination on the
petition by August 1, 2005. PEC cannot predict the outcome of this matter.
WATER QUALITY
As a result of the operation of certain control equipment needed to address
the air quality issues outlined above, new wastewater streams may be
generated at the affected facilities. Integration of these new wastewater
streams into the existing wastewater treatment processes may result in
permitting, construction and treatment requirements imposed on PEC in the
immediate and extended future.
After many years of litigation and settlement negotiations, the EPA adopted
regulations in February 2004 to implement Section 316(b) of the Clean Water
Act. These regulations became effective September 7, 2004. The purpose of
these regulations is to minimize adverse environmental impacts caused by
cooling water intake structures and intake systems. Over the next several
years these regulations will impact the larger base load generation
facilities and may require the facilities to mitigate the effects to
aquatic organisms by constructing intake modifications or undertaking other
restorative activities. PEC currently estimates that from 2005 through 2009
the range of its expenditures to meet the Section 316(b) requirements of
the Clean Water Act will be $20 million to $30 million.
OTHER ENVIRONMENTAL MATTERS
The Kyoto Protocol was adopted in 1997 by the United Nations to address
global climate change by reducing emissions of carbon dioxide and other
greenhouse gases. In 2004, Russia ratified the Protocol, and the treaty
went into effect on February 16, 2005. The United States has not adopted
the Kyoto Protocol, and the Bush administration has stated it favors
voluntary programs. A number of carbon dioxide emissions control proposals
have been advanced in Congress. Reductions in carbon dioxide emissions to
the levels specified by the Kyoto Protocol and some legislative proposals
could be materially adverse to PEC's consolidated financial position or
results of operations if associated costs of control or limitation cannot
be recovered from customers. PEC favors the voluntary program approach
recommended by the administration and continually evaluates options for the
reduction, avoidance and sequestration of greenhouse gases. However, PEC
cannot predict the outcome of this matter.
Progress Energy has announced its plan to issue a report on it's activities
associated with current and future environmental requirements. The report
will include a discussion of the environmental requirements that the PEC
currently faces and expects to face in the future, as well as an assessment
of potential mandatory constraints on carbon dioxide emissions. The report
will be issued by March 31, 2006.
18. COMMITMENTS AND CONTINGENCIES
A. Purchase Obligations
The following table reflects PEC's contractual cash obligations and other
commercial commitments at December 31, 2004, in the respective periods in
which they are due.
- ----------------------------------------------------------------------------------------
(in millions) 2005 2006 2007 2008 2009 Thereafter
- ----------------------------------------------------------------------------------------
Fuel $ 649 $ 450 $ 393 $ 126 $ 135 $ 586
Purchased power 137 130 125 84 86 526
Other Purchase Obligations 12 - - - - 13
- ----------------------------------------------------------------------------------------
Total $ 798 $ 580 $ 518 $ 210 $ 221 $ 1,125
- ----------------------------------------------------------------------------------------
175
FUEL AND PURCHASED POWER
PEC has entered into various long-term fuel contracts for coal, oil and gas
requirements of its generating plants. Total payments under these
commitments were $477 million, $562 million and $524 million in 2004, 2003
and 2002, respectively.
Pursuant to the terms of the 1981 Power Coordination Agreement, as amended,
between PEC and the North Carolina Eastern Municipal Power Agency (Power
Agency), PEC is obligated to purchase a percentage of Power Agency's
ownership capacity of, and energy from, the Harris Plant. In 1993, PEC and
Power Agency entered into an agreement to restructure portions of their
contracts covering power supplies and interests in jointly owned units.
Under the terms of the 1993 agreement, PEC increased the amount of capacity
and energy purchased from Power Agency's ownership interest in the Harris
Plant, and the buyback period was extended six years through 2007. The
estimated minimum annual payments for these purchases, which reflect
capacity and energy costs, total approximately $38 million. These
contractual purchases totaled $39 million, $36 million and $36 million for
2004, 2003 and 2002, respectively. In 1987, the NCUC ordered PEC to reflect
the recovery of the capacity portion of these costs on a levelized basis
over the original 15-year buyback period, thereby deferring for future
recovery the difference between such costs and amounts collected through
rates. In 1988, the SCPSC ordered similar treatment, but with a 10-year
levelization period. At December 31, 2004, all previously deferred costs
have been expensed.
PEC has a long-term agreement for the purchase of power and related
transmission services from Indiana Michigan Power Company's Rockport Unit
No. 2 (Rockport). The agreement provides for the purchase of 250 MW of
capacity through 2009 with estimated minimum annual payments of
approximately $43 million, representing capital-related capacity costs.
Estimated annual payments for energy and capacity costs are approximately
$72 million through 2009. Total purchases (including energy and
transmission use charges) under the Rockport agreement amounted to $63
million, $66 million and $59 million for 2004, 2003 and 2002, respectively.
PEC executed two long-term agreements for the purchase of power from Broad
River LLC's Broad River facility. One agreement provides for the purchase
of approximately 500 MW of capacity through 2021 with an original minimum
annual payment of approximately $16 million, primarily representing
capital-related capacity costs. The second agreement provided for the
additional purchase of approximately 300 MW of capacity through 2022 with
an original minimum annual payment of approximately $16 million
representing capital-related capacity costs. Total purchases for both
capacity and energy under the Broad River agreements amounted to $42
million, $37 million and $38 million in 2004, 2003 and 2002 respectively.
PEC has various pay-for-performance purchased power contracts with certain
cogenerators (qualifying facilities) for approximately 400 MW of capacity
expiring at various times through 2012. These purchased power contracts
generally provide for capacity and energy payments. Payments for both
capacity and energy are contingent upon the QFs' ability to generate.
Payments made under these contracts were $91 million, $113 million and $145
million in 2004, 2003 and 2002, respectively.
CONSTRUCTION OBLIGATIONS
At December 31, 2004, PEC has no construction obligations. Total purchases
under various combustion turbine construction obligations were $5 million,
$21 million and $13 million for 2004, 2003 and 2002, respectively.
OTHER CONTRACTUAL OBLIGATIONS
On December 31, 2002, PEC entered into a contractual commitment to purchase
at least $13 million of capital parts by December 31, 2010. During 2004 and
2003, no capital parts have been purchased under this contract.
PEC has various purchase obligations related to reactor vessel head
replacements, power uprates and spent fuel storages. Total purchases under
these contracts were $17 million for 2004 and $3 million for 2003. Future
purchase obligations are $12 million for 2005.
PEC incurred expenses related to various other purchase obligations
allocated from PESC of $8 million for 2004 and 2003 and $4 million for
2002.
176
B. Leases
PEC leases office buildings, computer equipment, vehicles, and other
property and equipment with various terms and expiration dates. Rent
expense under operating leases totaled $20 million for 2004 and 2003 and
$22 million for 2002. These amounts include rent expense allocated from
PESC of $11 million, $10 million and $12 million for 2004, 2003 and 2002,
respectively. Purchased power expense under agreements classified as
operating leases were approximately $24 million during 2004 and $5 million
during 2003. Assets recorded under capital leases consist of:
- -----------------------------------------------------------------
(in millions) 2004 2003
- -----------------------------------------------------------------
Buildings $ 30 $ 30
Less: Accumulated amortization (11) (10)
- -----------------------------------------------------------------
$ 19 $ 20
- -----------------------------------------------------------------
Minimum annual payments, excluding executory costs such as property taxes,
insurance and maintenance, under long-term noncancelable leases at December
31, 2004, are:
- ------------------------------------------------------------------------------------
(in millions) Capital Leases Operating Leases
- ------------------------------------------------------------------------------------
2005 $ 2 $ 28
2006 2 24
2007 2 13
2008 2 13
2009 2 12
Thereafter 25 97
- ------------------------------------------------------------------------------------
$ 35 $ 187
-----------------
Less amount representing imputed interest (16)
- -------------------------------------------------------------------
Present value of net minimum lease payments $ 19
- ------------------------------------------------------------------------------------
PEC is the lessor of electric poles, streetlights and other facilities.
Minimum rentals receivables under noncancelable leases are $9 million for
2005 and none thereafter. Rents received totaled $32 million, $31 million
and $28 million for 2004, 2003 and 2002, respectively.
C. Claims and Uncertainties
OTHER CONTINGENCIES
1. Pursuant to the Nuclear Waste Policy Act of 1982, the predecessors to
PEC entered into contracts with the U.S. Department of Energy (DOE) under
which the DOE agreed to begin taking spent nuclear fuel by no later than
January 31, 1998. All similarly situated utilities were required to sign
the same standard contract.
DOE failed to begin taking spent nuclear fuel by January 31, 1998. In
January 2004, PEC filed a complaint in the United States Court of Federal
Claims against the DOE, claiming that the DOE breached the Standard
Contract for Disposal of Spent Nuclear Fuel (SNF) by failing to accept SNF
from various PEC facilities on or before January 31, 1998. Damages due to
DOE's breach will likely exceed $100 million. Approximately 60 cases
involving the Government's actions in connection with spent nuclear fuel
are currently pending in the Court of Federal Claims.
DOE and the PEC parties have agreed to a stay of the lawsuit, including
discovery. The parties agreed to, and the trial court entered, a stay of
proceedings, in order to allow for possible efficiencies due to the
resolution of legal and factual issues in previously filed cases in which
similar claims are being pursued by other plaintiffs. These issues may
include, among others, so-called "rate issues," or the minimum mandatory
schedule for the acceptance of SNF and high level waste (HLW) by which the
Government was contractually obligated to accept contract holders' SNF
and/or HLW, and issues regarding recovery of damages under a partial breach
of contract theory that will be alleged to occur in the future. These
issues have been or are expected to be presented in the trials that are
currently scheduled to occur during 2005. Resolution of these issues in
other cases could facilitate agreements by the parties in the PEC lawsuit,
or at a minimum, inform the Court of decisions reached by other courts if
they remain contested and require resolution in this case. The trial court
has continued this stay until June 24, 2005.
With certain modifications and additional approval by the NRC, including
the installation of onsite dry storage facilities at Robinson and
Brunswick, PEC's spent nuclear fuel storage facilities will be sufficient
to provide storage space for spent fuel generated on PEC's system through
the expiration of the operating licenses for all of PEC's nuclear
generating units.
177
In July 2002, Congress passed an override resolution to Nevada's veto of
DOE's proposal to locate a permanent underground nuclear waste storage
facility at Yucca Mountain, Nevada. In January 2003, the State of Nevada,
Clark County, Nevada, and the City of Las Vegas petitioned the U.S. Court
of Appeals for the District of Columbia Circuit for review of the
Congressional override resolution. These same parties also challenged EPA's
radiation standards for Yucca Mountain. On July 9, 2004, the Court rejected
the challenge to the constitutionality of the resolution approving Yucca
Mountain, but ruled that the EPA was wrong to set a 10,000-year compliance
period in the radiation protection standard. EPA is currently reworking the
standard but has not stated when the work will be complete. DOE originally
planned to submit a license application to the NRC to construct the Yucca
Mountain facility by the end of 2004. However, in November 2004, DOE
announced it would not submit the license application until mid-2005 or
later. Also in November 2004, Congressional negotiators approved $577
million for fiscal year 2005 for the Yucca Mountain project, approximately
$300 million less than requested by DOE but approximately the same as
approved in 2004. The DOE continues to state it plans to begin operation of
the repository at Yucca Mountain in 2010. PEC cannot predict the outcome of
this matter.
2. In 2001, PEC entered into a contract to purchase coal from Dynegy
Marketing and Trade (DMT). After DMT experienced financial difficulties,
including credit ratings downgrades by certain credit reporting agencies,
PEC requested credit enhancements in accordance with the terms of the coal
purchase agreement in July 2002. When DMT did not offer credit
enhancements, as required by a provision in the contract, PEC terminated
the contract in July 2002.
PEC initiated a lawsuit seeking a declaratory judgment that the termination
was lawful. DMT counterclaimed, stating the termination was a breach of
contract and an unfair and deceptive trade practice. On March 23, 2004, the
United States District Court for the Eastern District of North Carolina
ruled that PEC was liable for breach of contract, but ruled against DMT on
its unfair and deceptive trade practices claim. On April 6, 2004, the Court
entered a judgment against PEC in the amount of approximately $10 million.
The Court did not rule on DMT's request under the contract for pending
legal costs.
On May 4, 2004, PEC authorized its outside counsel to file a notice of
appeal of the April 6, 2004, judgment and on May 7, 2004, the notice of
appeal was filed with the United States Court of Appeals for the Fourth
Circuit. On June 8, 2004, DMT filed a motion to dismiss the appeal on the
ground that PEC's notice of appeal should have been filed on or before May
6, 2004. On June 16, 2004, PEC filed a motion with the trial court
requesting an extension of the deadline for the filing of the notice of
appeal. By order dated September 10, 2004, the trial court denied the
extension request. On September 15, 2004, PEC filed a notice of appeal of
the September 10, 2004, order and by order dated September 29, 2004, the
appellate court consolidated the first and second appeals. DMT's motion to
dismiss the first appeal remains pending.
The consolidated appeal has been fully briefed, and the court of appeals
has indicated that it will hear arguments, which tentatively have been
scheduled for the week of May 23, 2005.
PEC recorded a liability for the judgment of approximately $10 million and
a regulatory asset for the probable recovery through its fuel adjustment
clause in the first quarter of 2004. PEC cannot predict the outcome of this
matter.
3. On February 1, 2002, PEC filed a complaint with the Surface
Transportation Board (STB) challenging the rates charged by Norfolk
Southern Railway Company (Norfolk Southern) for coal transportation to
certain generating plants. In a decision dated December 23, 2003, the STB
found that the rates were unreasonable, awarded reparations and prescribed
maximum rates. Both parties petitioned the STB for reconsideration of the
December 23, 2003 decision. On October 20, 2004, the STB reconsidered its
December 23, 2003 decision and concluded that the rates charged by Norfolk
Southern were not unreasonable. Because PEC paid the maximum rates
prescribed by the STB in its December 23, 2003 decision for several months
during 2004, which were less than the rates ultimately found to be
reasonable, the STB ordered PEC to pay to Norfolk Southern the difference
between the rate levels plus interest.
178
PEC subsequently filed a petition with the STB to phase in the new rates
over a period of time, and filed a notice of appeal with the U.S. Court of
Appeals for the D.C. Circuit. Pursuant to an order issued by the STB on
January 6, 2005, the phasing proceeding will proceed on a schedule that
appears likely to produce an STB decision before the end of 2005. On
January 12, 2005, the STB filed a Motion to Dismiss PEC's appeal on the
grounds that its October 20, 2004, order is not "final" until PEC's phasing
application has been decided.
As of December 31, 2004, PEC has accrued a liability of $42 million, of
which $23 million represents reparations previously remitted to PEC by
Norfolk Southern that are now subject to refund. Of the remaining $19
million, $17 million has been recorded as deferred fuel cost on the
Consolidated Balance Sheet while the remaining $2 million attributable to
wholesale customers has been charged to fuel used in electric generation on
the Consolidated Statements of Income.
PEC cannot predict the outcome of this matter.
4. PEC and its subsidiaries are involved in various litigation matters in
the ordinary course of business, some of which involve substantial amounts.
Where appropriate, accruals have been made in accordance with SFAS No. 5,
"Accounting for Contingencies," to provide for such matters. In the opinion
of management, the final disposition of pending litigation would not have a
material adverse effect on PEC's consolidated results of operations or
financial position.
19. SUBSEQUENT EVENT
Cost Management Initiative
On February 28, 2005, as part of a previously announced cost management
initiative, the executive officers of Progress Energy approved a workforce
restructuring. The restructuring is expected to be completed in September
of 2005. In addition to the workforce restructuring, the cost management
initiative includes a voluntary enhanced retirement program.
In connection with the cost management initiative, PEC expects to incur
one-time pre-tax charges of approximately $55 million. Approximately $10
million of that amount relates to payments for severance benefits, and will
be recognized in the first quarter of 2005 and paid over time. The
remaining approximately $45 million will be recognized in the second
quarter of 2005 and relates primarily to postretirement benefits that will
be paid over time to those eligible employees who elect to participate in
the voluntary enhanced retirement program. The total cost management
initiative charges could change significantly depending upon how many
eligible employees elect early retirement under the voluntary enhanced
retirement program and the salary, service years and age of such employees.
20. CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
- ----------------------------------------------------------------------------------------------------------------
(in millions) First Quarter Second Quarter Third Quarter Fourth Quarter
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2004
Operating revenues $ 901 $ 862 $ 1,014 $ 852
Operating income 236 191 317 133
Income before cumulative effect of
change in accounting principles 115 96 175 75
Net income 115 96 175 75
- ----------------------------------------------------------------------------------------------------------------
Year ended December 31, 2003
Operating revenues $ 929 $ 819 $ 1,012 $ 840
Operating income 256 184 295 234
Income before cumulative effect of
change in accounting principles 135 89 158 123
Net income 135 89 158 100
- ----------------------------------------------------------------------------------------------------------------
In the opinion of management, all adjustments necessary to fairly present
amounts shown for interim periods have been made. Results of operations for
an interim period may not give a true indication of results for the year.
Fourth quarter 2004 includes approximately $99 million ($59 million
after-tax) more NC Clean Air legislation amortization than the other
quarters presented. Fourth quarter 2004 also includes a reduction in
depreciation expense of $63 million ($38 million after-tax) resulting from
a revised depreciation study due to extended lives at each of PEC's nuclear
units (See Note 4A). Fourth quarter 2003 includes impairment charges
related to certain investments of $21 million ($13 million after-tax) (See
Note 7). Fourth quarter 2003 includes the impact of a cumulative effect for
DIG Issue C20 of $38 million ($23 million after-tax) (See Note 13).
179
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.:
We have audited the consolidated financial statements of Progress Energy, Inc.,
and its subsidiaries (the Company) as of December 31, 2004 and 2003, and for
each of the three years in the period ended December 31, 2004, management's
assessment of the effectiveness of the Company's internal control over financial
reporting as of December 31, 2004, and the effectiveness of the Company's
internal control over financial reporting as of December 31, 2004, and have
issued our reports thereon dated March 7, 2005 (which reports express an
unqualified opinion and include an explanatory paragraph concerning the adoption
of new accounting principles in 2003); such reports are included elsewhere in
this Form 10-K. Our audits also included the consolidated financial statement
schedule of the Company listed in Item 15. This consolidated financial statement
schedule is the responsibility of the Company's management. Our responsibility
is to express an opinion based on our audits. In our opinion, such consolidated
financial statement schedule, when considered in relation to the basic
consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2005
180
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND SHAREHOLDER OF CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS, INC.:
We have audited the consolidated financial statements of Carolina Power & Light
Company d/b/a Progress Energy Carolinas, Inc., and its subsidiaries (PEC) as of
December 31, 2004 and 2003, and for each of the three years in the period ended
December 31, 2004, and have issued our report thereon dated March 7, 2005 (which
expresses an unqualified opinion and includes an explanatory paragraph
concerning the adoption of new accounting principles in 2003); such report is
included elsewhere in this Form 10-K. Our audits also included the consolidated
financial statement schedule of PEC listed in Item 15. This financial statement
schedule is the responsibility of PEC's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial statement
schedule, when considered in relation to the basic financial statements taken as
a whole, presents fairly, in all material respects, the information set forth
therein.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2004
181
PROGRESS ENERGY, INC.
Schedule II - Valuation and Qualifying Accounts
For the Years Ended
(in millions)
- -----------------------------------------------------------------------------------------------------------------------
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expenses Additions Deductions (a) Period
- -----------------------------------------------------------------------------------------------------------------------
Valuation and qualifying
accounts deducted in the
balance sheet from the
related assets:
DECEMBER 31, 2004
Uncollectible accounts $ 32 $ 17 $ (4) $ (16) $ 29
Fossil dismantlement
reserve 143 1 - - 144
Nuclear refueling
outage reserve 2 10 - - 12
DECEMBER 31, 2003
Uncollectible accounts $ 39 $ 24 $ 4 $ (35) $ 32
Fossil dismantlement
reserve 142 1 - - 143
Nuclear refueling outage
reserve 10 8 - (16) (b) 2
DECEMBER 31, 2002
Uncollectible accounts $ 39 $ 22 $ - $ (22) $ 39
Fossil dismantlement
reserve 141 1 - - 142
Nuclear refueling outage
reserve - 10 - - 10
- -----------------------------------------------------------------------------------------------------------------------
(a) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
uncollectible accounts, such deductions are reduced by recoveries of
amounts previously written off.
(b) Represents payments of actual expenditures related to the outages.
- -----------------------------------------------------------------------------------------------------------------------
182
CAROLINA POWER & LIGHT COMPANY
d/b/a PROGRESS ENERGY CAROLINAS
Schedule II - Valuation and Qualifying Accounts
For the Years Ended
(in millions)
- -----------------------------------------------------------------------------------------------------------------------
Balance at Additions Balance at
Beginning Charged to Other End of
Description of Period Expense Additions Deductions (a) Period
- -----------------------------------------------------------------------------------------------------------------------
Valuation and qualifying accounts
deducted in the balance sheet from
the related assets:
December 31, 2004
Uncollectible accounts $ 17 $ 7 $ (4) $ (10) $ 10
December 31, 2003
Uncollectible accounts $ 12 $ 12 $ 4 $ (11) $ 17
December 31, 2002
Uncollectible accounts $ 14 $ 8 $ - $ (10) $ 12
- -----------------------------------------------------------------------------------------------------------------------
(a) Deductions from provisions represent losses or expenses for which the
respective provisions were created. In the case of the provision for
uncollectible accounts, such deductions are reduced by recoveries of
amounts previously written off.
- -----------------------------------------------------------------------------------------------------------------------
183
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Progress Energy, Inc.
DISCLOSURE CONTROLS AND PROCEDURES
Pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934, Progress
Energy carried out an evaluation, with the participation of its management,
including Progress Energy's Chairman and Chief Executive Officer and Chief
Financial Officer, of the effectiveness of Progress Energy's disclosure controls
and procedures (as defined under Rule 13a-15(e) under the Securities Exchange
Act of 1934) as of the end of the period covered by this report. Based upon that
evaluation, Progress Energy's Chief Executive Officer and Chief Financial
Officer concluded that its disclosure controls and procedures are effective to
ensure that information required to be disclosed by Progress Energy in the
reports that it files or submits under the Exchange Act, is recorded, processed,
summarized and reported, within the time periods specified in the SEC's rules
and forms, and that such information is accumulated and communicated to Progress
Energy's management, including the Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
It is the responsibility of Progress Energy's management to establish and
maintain adequate internal control over financial reporting, as such term is
defined in Rules 13a-15(f) and 15(d)-15(f) of the Securities Exchange Act of
1934, as amended. Progress Energy's internal control over financial reporting is
a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles in the
United States of America. Internal control over financial reporting includes
policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of Progress Energy; (2) provide reasonable assurance
that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles in the
United States of America; (3) provide reasonable assurance that receipts and
expenditures of Progress Energy are being made only in accordance with
authorizations of management and directors of Progress Energy; and (4) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of Progress Energy's assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance
with the policies or procedures may deteriorate.
Management assessed the effectiveness of Progress Energy's internal control over
financial reporting as of December 31, 2004. Management based this assessment on
criteria for effective internal control over financial reporting described in
"Internal Control - Integrated Framework" issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Management's assessment
included an evaluation of the design of Progress Energy's internal control over
financial reporting and testing of the operational effectiveness of its internal
control over financial reporting. Management reviewed the results of its
assessment with the Audit Committee of the Board of Directors.
Based on our assessment, management determined that, as of December 31, 2004,
Progress Energy maintained effective internal control over financial reporting.
Management's assessment of the effectiveness of Progress Energy's internal
control over financial reporting as of December 31, 2004, has been audited by
Deloitte & Touche LLP, an independent registered public accounting firm, as
stated in their report which is included herein in Item 9A Controls and
procedures of this Annual Report on Form 10-K.
184
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.
There has been no change in Progress Energy's internal control over financial
reporting during the quarter ended December 31, 2004, that has materially
affected, or is reasonably likely to materially affect its internal control over
financial reporting.
The Company notes, however, that as part of the Company's review of internal
controls for compliance with Section 404 of the Sarbanes-Oxley Act, the Company
will be implementing changes related to capitalization practices for its Energy
Delivery business units in PEC and PEF effective January 1, 2005. A review of
these practices indicated that in the areas of outage and emergency work, not
associated with major storm and allocation of indirect costs, both PEC and PEF
should revise the way that they estimate the amount of capital costs associated
with such work. The changes for 2005 in this area include use of more detailed
accounts to segregate capital and expense items, more regular testing of
accounting estimates and realignment of certain accounting functions. This
matter is also discussed at Footnote 8F to the Progress Energy Consolidated
Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF PROGRESS ENERGY, INC.
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control Over Financial Reporting, that Progress
Energy, Inc., and its subsidiaries (the "Company") maintained effective internal
control over financial reporting as of December 31, 2004, based on the criteria
established in Internal Control--Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. The Company's management is
responsible for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on management's
assessment and an opinion on the effectiveness of the Company's internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed by,
or under the supervision of, the Company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
Company's board of directors, management, and other personnel to provide
reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the Company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the Company are
being made only in accordance with authorizations of management and directors of
the Company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of the Company's
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be
prevented or detected on a timely basis. Also, projections of any evaluation of
the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
185
In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial
reporting as of December 31, 2004, based on the criteria established in Internal
Control--Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2004, of the Company and
our report dated March 7, 2005, expressed an unqualified opinion on those
consolidated financial statements.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 7, 2005
Progress Energy Carolinas, Inc.
Pursuant to the Securities Exchange Act of 1934, PEC carried out an evaluation,
with the participation of its management, including PEC's Chairman and Chief
Executive Officer and Chief Financial Officer, of the effectiveness of PEC's
disclosure controls and procedures (as defined under the Securities Exchange Act
of 1934) as of the end of the period covered by this report. Based upon that
evaluation, PEC's Chief Executive Officer and Chief Financial Officer concluded
that its disclosure controls and procedures are effective to ensure that
information required to be disclosed by PEC in the reports that it files or
submits under the Exchange Act, is recorded, processed, summarized and reported,
within the time periods specified in the SEC's rules and forms, and that such
information is accumulated and communicated to PEC's management, including the
Chief Executive Officer and Chief Financial Officer, as appropriate, to allow
timely decisions regarding required disclosure.
There has been no change in PEC's internal control over financial reporting
during the quarter ended December 31, 2004, that has materially affected, or is
reasonably likely to materially affect, its internal control over financial
reporting.
As noted above, PEC will be implementing changes related to capitalization
practices for its Energy Delivery business unit effective January 1, 2005. A
review of these practices indicated that in the areas of outage and emergency
work, not associated with major storm and allocation of indirect costs, PEC
should revise the way that it estimates the amount of capital costs associated
with such work. The changes for 2005 in this area include use of more detailed
accounts to segregate capital and expense items, more regular testing of
accounting estimates and realignment of certain accounting functions. This
matter is also discussed in Note 6E to the PEC Consolidated Financial
Statements.
ITEM 9B. OTHER INFORMATION
In March 2005, Progress Energy, Inc.'s 5-year credit facility was amended to
increase the maximum total debt to total capital ratio from 65% to 68% in
anticipation of the potential impacts of proposed accounting rules for uncertain
tax positions.
186
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
a) Information on Progress Energy, Inc.'s directors is set forth in the
Progress Energy 2004 definitive proxy statement dated March 31, 2005, and
incorporated by reference herein. Information on PEC's directors is set
forth in the PEC 2004 definitive proxy statement dated March 31, 2005, and
incorporated by reference herein.
b) Information on both Progress Energy's and PEC's executive officers is set
forth in PART I and incorporated by reference herein.
c) The Company has adopted a Code of Ethics that applies to all of its
employees, including its Chief Executive Officer, Chief Financial Officer,
Chief Accounting Officer and Controller (or persons performing similar
functions). The Company's Board of Directors has adopted the Company's Code
of Ethics as its own standard. Board members, Company officers and Company
employees certify their compliance with the Code of Ethics on an annual
basis. The Company's Code of Ethics is posted on its Internet Web site and
can be accessed at www.progress-energy.com and is available in print to any
shareholder upon request by writing to Progress Energy, Inc.
The Company intends to satisfy the disclosure requirement under Item 10 of
Form 8-K relating to amendments to or waivers from any provision of the
Code of Ethics applicable to the Company's CEO, CFO, CAO and Controller by
posting such information on its Internet Web site, www.progress-energy.com.
d) The Board of Directors has determined that David L. Burner and Carlos A.
Saladrigas are the "Audit Committee Financial Experts," as that term is
defined in the rules promulgated by the Securities and Exchange Commission
pursuant to the Sarbanes-Oxley Act of 2002, and have designated them as
such. Both Mr. Burner and Mr. Saladrigas are "independent," as that term is
defined in the general independence standards of the New York Stock
Exchange listing standards.
e) The following are available on the Company's Web site and in print at no
cost:
o Audit Committee Charter
o Corporate Governance Committee Charter
o Organization and Compensation Committee Charter
o Corporate Governance Guidelines
ITEM 11. EXECUTIVE COMPENSATION
Information on Progress Energy's executive compensation is set forth in the
Progress Energy 2004 definitive proxy statement dated March 31, 2005, and
incorporated by reference herein. Information on PEC's executive compensation is
set forth in the PEC 2004 definitive proxy statement dated March 31, 2005, and
incorporated by reference herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
a) Information regarding any person Progress Energy knows to be the beneficial
owner of more than five (5%) percent of any class of its voting securities
is set forth in its 2004 definitive proxy statement, dated March 31, 2005,
and incorporated herein by reference.
Information regarding any person PEC knows to be the beneficial owner of
more than 5% of any class of its voting securities is set forth in its 2004
definitive proxy statement, dated March 31, 2005, and incorporated herein
by reference.
187
b) Information on security ownership of the Progress Energy's and PEC's
management is set forth in the Progress Energy and PEC 2004 definitive
proxy statements dated March 31, 2005, and incorporated by reference
herein.
c) Information on the equity compensation plans of Progress Energy is set
forth under the heading "Equity Compensation Plan Information" in the
Progress Energy 2004 definitive proxy statement dated March 31, 2005, and
incorporated by reference herein.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information on certain relationships and related transactions is set forth in
the Progress Energy and PEC 2004 definitive proxy statements dated March 31,
2005, and incorporated by reference herein.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services is set forth in the
Progress Energy and PEC 2004 definitive proxy statements dated March 31, 2005,
and incorporated by reference herein.
188
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
a) The following documents are filed as part of the report:
1. Consolidated Financial Statements Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary
Data
2. Consolidated Financial Statement Schedules Filed:
See ITEM 8 - Consolidated Financial Statements and Supplementary
Data
3. Exhibits Filed:
See EXHIBIT INDEX
189
PROGRESS ENERGY, INC. RISK FACTORS
In this section, unless the context indicates otherwise, references to "our,"
"we," "us" or similar terms refer to Progress Energy, Inc. and its consolidated
subsidiaries. Investing in our securities involves risks, including the risks
described below, that could affect the energy industry, as well as us and our
business. Most of the business information as well as the financial and
operational data contained in our risk factors are updated periodically in the
reports we file with the SEC. Although we have tried to discuss key factors,
please be aware that other risks may prove to be important in the future. New
risks may emerge at any time and we cannot predict such risks or estimate the
extent to which they may affect our financial performance. Before purchasing our
securities, you should carefully consider the following risks and the other
information in this Annual Report, as well as the documents we file with the SEC
from time to time. Each of the risks described below could result in a decrease
in the value of our securities and your investment therein.
Risks Related to the Energy Industry
We are subject to fluid and complex government regulations that may have a
negative impact on our business, financial condition and results of operations.
We are subject to comprehensive regulation by several federal, state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are subject
to regulatory oversight with respect to, among other things, rates and service
for electric energy sold at retail, retail service territory and issuances of
securities. In addition our operating utilities are subject to regulation with
respect to transmission and sales of wholesale power, accounting and certain
other matters. We are also required to have numerous permits, approvals and
certificates from the agencies that regulate our business. We believe the
necessary permits, approvals and certificates have been obtained for our
existing operations and that our business is conducted in accordance with
applicable laws; however, we are unable to predict the impact on our operating
results from the future regulatory activities of any of these agencies. Changes
in regulations or the imposition of additional regulations could have an adverse
impact on our results of operations.
The 108th Congress spent much of 2004 working on a comprehensive energy bill.
While that legislation passed the House, the Senate failed to pass the
legislation in 2004. There will probably be an effort to resurrect the
legislation in 2005. The legislation would have further clarified the Federal
Energy Regulatory Commission's ("FERC") role with respect to Standard Market
Design and mandatory Regional Transmission Organizations ("RTOs") and would have
repealed the Public Utility Holding Company Act of 1935 ("PUHCA"). The Company
cannot predict the outcome or impact of the proposed or any future energy bill.
FERC, the U.S. Nuclear Regulatory Commission ("NRC"), the U.S. Environmental
Protection Agency ("EPA"), the North Carolina Utilities Commission ("NCUC"), the
Florida Public Service Commission ("FPSC"), and the Public Service Commission of
South Carolina ("SCPSC") regulate many aspects of our utility operations,
including siting and construction of facilities, customer service and the rates
that we can charge customers. Our system is also subject to the jurisdiction of
the SEC under PUHCA. The rules and regulations promulgated under PUHCA impose a
number of restrictions on the operations of registered utility holding companies
and their subsidiaries. These restrictions include a requirement that, subject
to a number of exceptions, the SEC approve in advance securities issuances,
acquisitions and dispositions of utility assets or of securities of utility
companies, and acquisitions of other businesses. PUHCA also generally limits the
operations of a registered holding company like ours to a single integrated
public utility system, plus additional energy-related businesses. Furthermore,
PUHCA rules require that transactions between affiliated companies in a
registered holding company system be performed at cost, with limited exceptions.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business, financial condition and results of operations.
190
We are subject to numerous environmental laws and regulations that require
significant capital expenditures, increase our cost of operations, and which may
impact or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.
In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount or
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all PRPs.
Our compliance with environmental regulations requires significant capital
expenditures that impact our financial condition. For example, in June 2002,
legislation was enacted in North Carolina requiring the state's electric
utilities to reduce the emissions of nitrogen oxide ("NOx") and sulfur dioxide
("SO2") from coal-fired power plants. We expect the capital costs required to
meet these emission targets will total approximately $895 million by 2013. Over
the next three years, we expect to incur approximately $510 million of total
capital costs associated with this legislation.
Congress currently considering further legislation that would require reductions
in air emissions of NOx, SO2, carbon dioxide and mercury. Some of these
proposals establish nationwide caps and emission rates over an extended period
of time. This national multi-pollutant approach to air pollution control could
involve significant capital costs which could be material to our consolidated
financial position or results of operations. However, the Company cannot predict
the outcome, costs or impact of this matter. In December 2003, the EPA released
its proposed Interstate Air Quality Rule, currently referred to as the Clean Air
Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions, including
North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO2
emissions in order to attain preset state NOx and SO2 emissions levels. The rule
is expected to become final in March 2005. While the air quality controls
already installed and currently planned for installation to comply with the NC
Clean Air legislation will reduce the costs required to meet the CAIR
requirements for the our North Carolina units, additional compliance costs will
be determined once the rule is finalized. In March 2004, the North Carolina
Attorney General filed a petition with the EPA under Section 126 of the Clean
Air Act, asking the federal government to force coal-fired power plants in
thirteen other states, including South Carolina to reduce their NOx and SO2
emissions. The state of North Carolina contends these out-of-state emissions
interfere with North Carolina's ability to meet national air quality standards
for ozone and particulate matter. The EPA has agreed to make a determination on
the petition by August 1, 2005. The Company cannot predict the outcome or costs
associated with the matter.
See additional discussion of these environmental matters in Note 22 to the
Progress Energy Consolidated Financial Statements.
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
Congress, FERC, and the state utility regulators have paid significant attention
in recent years to transmission issues, including the possibility of regional
transmission organizations. While these deliberations have not yet resulted in
significant changes to our utilities' transmission operations, they cast
uncertainty over those operations, which constitute a material portion of our
assets.
191
For the last several years, the FERC has supported independent RTOs and has
indicated a belief that it has the authority to order transmission-owning
utilities to transfer operational control of their transmission assets to such
RTOs. Many state regulators, including most regulators in the Southeast, have
expressed skepticism over the potential benefits of RTOs and generally disagree
with the FERC's interpretation of its authority to mandate RTOs. In July 2002,
the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000,
Remedying Undue Discrimination through Open Access Transmission Service and
Standard Electricity Market Design (SMD NOPR). In its current form, SMD NOPR
could materially alter the manner in which transmission and generation services
are provided and paid for, and includes provisions for mandatory RTOs and the
FERC's assertion of jurisdiction over certain aspects of retail service. The
Company cannot predict the outcome or timing of any final rules or the effect
that they may have on the GridSouth and GridFlorida proceedings currently
ongoing before the FERC.
At the state level, significant uncertainty exists with respect to what action,
if any, the NCUC or FPSC will ultimately take. The Company has $33 million and
$4 million invested in GridSouth and GridFlorida, respectively, related to
startup costs at December 31, 2004. These amounts are included as a regulatory
asset at December 31, 2004. The Company expects to recover these startup costs
in conjunction with the GridSouth and GridFlorida original structures or in
conjunction with any alternate combined transmission structures that may be
required. Furthermore, the SMD NOPR presents several uncertainties, including
what percentage of our investments in GridSouth and GridFlorida will be
recovered, how the elimination of transmission charges, as proposed in the SMD
NOPR, will impact us, and what amount of capital expenditures will be necessary
to create a new wholesale market.
The actual structure of GridSouth, GridFlorida or any alternative combined
transmission structure, as well as the date it may become operational, depends
upon the resolution of all regulatory approvals and technical issues. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, GridFlorida or an alternate combined transmission structure, we
cannot predict whether they will be created, or whether they will have any
material adverse effect on our future consolidated results of operations, cash
flows or financial condition.
Since weather conditions directly influence the demand for and cost of providing
electricity, our results of operations, financial condition, cash flows and
ability to pay dividends on our common stock can fluctuate on a seasonal or
quarterly basis and can be negatively affected by changes in weather conditions
and severe weather.
Our results of operations, financial condition, cash flows and ability to pay
dividends on our common stock may be affected by changing weather conditions.
Weather conditions in our service territories, primarily North Carolina, South
Carolina, and Florida, directly influence the demand for electricity affect the
price of energy commodities necessary to provide electricity to our customers
and energy commodities that our nonregulated businesses sell.
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power and market prices peak during the hot summer months.
In other areas, power demand peaks during the winter. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.
The pattern of this fluctuation may change depending on the nature and location
of facilities we acquire and the terms of power sale contracts into which we
enter. In addition, we have historically sold less power, and consequently
earned less income, when weather conditions are milder. While we believe that
our North Carolina, South Carolina, and Florida markets complement each other
during normal seasonal fluctuations, unusually mild weather could diminish our
results of operations and harm our financial condition.
Furthermore, severe weather in these states, such as hurricanes, tornadoes,
severe thunderstorms, snow and ice storms, can be destructive, causing outages,
downed power lines and property damage, requiring us to incur additional and
unexpected expenses and causing us to lose generating revenues. For example,
during the third quarter of 2004, four hurricanes hit our service territories,
resulting in storm costs of approximately $398 million. In addition, these storm
costs reduced our projected 2004 regular federal income tax liability, and
consequently, our ability to benefit from the tax credits generated from our
synthetic fuel operations.
192
Our ability to recover significant costs resulting from severe weather events is
subject to regulatory oversight and the timing and amount of any such recovery
is uncertain and may impact our financial conditions.
During the third quarter of 2004, four hurricanes struck significant portions of
our service territories, most significantly impacting PEF's territory. The total
estimated restoration cost of these storms is $398 million. PEC incurred
restoration costs of $13 million, of which $12 million was charged to operation
and maintenance expense and $1 million was charged to capital expenditures. PEF
had estimated total costs of $385 million, of which $47 million was charged to
capital expenditures, and $338 million was charged to the storm damage reserve
pursuant to a regulatory order.
Under a regulatory order, PEF maintains a storm damage reserve account for major
storms. With respect to storm costs in excess of the storm damage reserve
account, PEF may seek recover from retail ratepayers. On November 2, 2004, PEF
filed a petition with the FPSC to recover $252 million of storm costs plus
interest from retail ratepayers over a two-year period. Given that not all
invoices have been received as of December 31, 2004, it is PEF's position that
its petition presents a fair projection of total cost and does not need to be
updated at this time. PEF will update its request upon receipt and audit of all
actual charges incurred. Storm reserve costs of $13 million are attributable to
wholesale customers and such costs may be amortized consistent with recovery of
such amounts in wholesale rates. The timing of any FPSC decision and ultimate
amount recovered is uncertain at this time.
PEC is not required to maintain a storm damage reserve account and does not have
an on-going regulatory mechanism to recover storm costs and; therefore,
hurricane restoration costs recorded in the third quarter of 2004 were charged
to operations and maintenance expenses or capital expenditures based on the
nature of the work performed. In connection with other storms, PEC has
previously sought and received permission from the NCUC and the SCPSC to defer
storm expenses and amortize them over a five-year period. PEC did not seek
recovery of 2004 storm costs from the NCUC.
While we believe that we are legally entitled to recover these costs, if we
cannot recover these costs, or costs associated with future significant weather
events, in a timely manner, or in an amount sufficient to cover our actual
costs, our financial conditions and results of operations could be materially
and adversely impacted.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers
as well as the demand and competitive state of the wholesale market.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2004, commercial and industrial customers represented approximately
37% of our total electric revenues. As a result, changes in the macroeconomy can
have negative impacts on our revenues. As our commercial and industrial
customers experience economic hardships, our revenues can be negatively
impacted. In recent years, in North and South Carolina, sales to industrial
customers have been affected by downturns in the textile and chemical
industries.
For the year ended December 31, 2004, 12% of our total electric revenues were
from wholesale sales. Wholesale revenues fluctuate with regional demand, fuel
prices, and contracted capacity. Our wholesale profitability is dependent upon
our ability to renew or replace expiring wholesale contracts on favorable terms.
During 2004, wholesale revenues decreased from expiring contracts being
renegotiated by PEC at less favorable terms due to slightly depressed markets
and from increased competition in the wholesale markets served by PEC. If this
trend market environment persists, we may experience further declines in our
wholesale revenues.
In April 2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market power
of applicants for wholesale market-based rates, and described additional
analyses and mitigation measures that could be presented if an applicant does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider whether the FERC's current methodology
for determining whether a public utility should be allowed to sell wholesale
electricity at market-based rates should be modified in any way. PEF does not
have market-based rate authority for wholesale sales in peninsular Florida.
Given the difficulty PEC believes it would experience in passing one of the
interim screens, on August 12, 2004, PEC notified the FERC that it would revise
its Market-based Rate tariff to restrict it to sales outside PEC's control area
and file a new cost-based tariff for sales within PEC's control area that
incorporates the FERC's default cost-based rate methodologies for sales of one
year or less. We anticipate making this filing the first quarter of 2005. We
cannot predict what impact PEC's requirement to implement cost-based tariffs
will have on our future financial condition, results of operations or cash
flows.
193
Deregulation or restructuring in the electric industry may result in increased
competition and unrecovered costs that could adversely affect the financial
condition, results of operations or cash flows of us and our utilities'
businesses.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on us and our utility subsidiaries
and consequently on our results of operations and cash flows. Increased
competition could also result in increased pressure to lower costs, including
the cost of electricity. Retail competition and the unbundling of regulated
energy and gas service could have a significant adverse financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower profit margins or increased costs of capital. Because we have not
previously operated in a competitive retail environment, we cannot predict the
extent and timing of entry by additional competitors into the electric markets.
Due to several factors, however, there currently is little discussion of any
movement toward deregulation in North Carolina, South Carolina and Florida. We
cannot predict when we will be subject to changes in legislation or regulation,
nor can we predict the impact of these changes on our financial condition,
results of operations or cash flows.
Increased commodity prices may adversely affect the financial condition, results
of operations or cash flows of us and our utilities' businesses.
The Company is exposed to the effects of market fluctuations in the price of
natural gas, coal, fuel oil, electricity and other energy-related products
marketed and purchased as a result of its ownership of energy-related assets.
While each state commission allows electric utilities to recover certain of
these costs through various cost recovery clauses, there is the potential that
all or a portion of these future costs could be deemed imprudent by the
respective commissions. There is also a delay between the timing of when these
costs are incurred by the utilities and when these costs are recovered from the
ratepayers, which can adversely impact the cash flow of the Company and its
subsidiaries.
Prices for SO2 emission allowance credits under the EPA's emission trading
program increased significantly during 2004. While SO2 allowances are eligible
for annual recovery in the Company's jurisdictions in Florida and South
Carolina, no such annual recovery exists in North Carolina. Future increases in
the price of SO2 allowances could have a significant adverse financial impact on
us and PEC and consequently on our results of operations and cash flows.
Risks Related to Us and Our Business
As a holding company, we are dependent on upstream cash flows from our
subsidiaries, primarily our regulated utilities. As a result, our ability to
meet our ongoing and future financial obligations and to pay dividends on our
common stock is primarily dependent on the earnings and cash flows of our
operating subsidiaries and their ability to pay upstream dividends or to repay
funds to us.
We are a holding company. As such, we have no operations of our own. Our ability
to meet our financial obligations associated with interest charges on $4.3
billion of holding company debt and to pay dividends on our common stock at the
current rate is primarily dependent on the earnings and cash flows of our
operating subsidiaries, primarily our regulated utilities, and the ability of
our subsidiaries to pay upstream dividends or to repay funds to us. Prior to
funding us, our subsidiaries have financial obligations that must be satisfied,
including among others, debt service, dividends and obligations to trade
creditors. For the year ending December 31, 2004, approximately 100% of the
Company's cash from operations was provided by its utility subsidiaries. Other
sources of cash include the issuance of equity, short-term debt and intercompany
charges for capital costs.
The rates that our utility subsidiaries may charge retail customers for electric
power are subject to the authority of state regulators. Accordingly, our profit
margins could be adversely affected if we or our utility subsidiaries do not
control operating costs.
The NCUC, the SCPSC and the FPSC each exercises regulatory authority for review
and approval of the retail electric power rates charged within its respective
state. State regulators may not allow our utility subsidiaries to increase
retail rates in the manner or to the extent requested by those subsidiaries.
State regulators may also seek to reduce retail rates. For example, in March
2002, PEF entered into a Stipulation and Settlement Agreement (the "Agreement")
that required PEF, among other things, to reduce its retail rates and to operate
under a revenue sharing plan through 2005 which provides for possible rate
refunds to its retail customers. The Agreement will also require increased
capital expenditures for PEF's Commitment to Excellence program. However, if
PEF's base rate earnings fall below a 10% return on equity, PEF may petition the
FPSC to amend its base rates. As discussed below, in January 2005, PEF
petitioned the FPSC for an increase in its retail base rates.
194
Additionally, under the NC Clean Air legislation in North Carolina, passed in
2002, PEC's base retail rates were frozen for five years unless there are
significant cost changes due to governmental action, significant expenditures
due to force majeure or other extraordinary events beyond the control of PEC,
and PEC has agreed not to seek a base retail electric rate increase in South
Carolina through 2005. The same legislation required a significant increase in
capital expenditures over the next several years for clean air improvements. The
cash costs incurred by our utility subsidiaries are generally not subject to
being fixed or reduced by state regulators. Our utility subsidiaries will also
require dedicated capital expenditures. Thus, our ability to maintain our profit
margins depends upon stable demand for electricity and our efforts to manage our
costs.
If the FPSC does not approve our request for increased base rates, we will be
faced with a significantly increased cost structure that will not be adequately
covered by our base rates and, as a result, our results of operations, financial
condition and ability to pay dividends could be materially and adversely
impacted.
In January 2005, in anticipation of the expiration of the Agreement approved by
the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified the FPSC
that it intends to request an increase in its base rates, effective January 1,
2006. In its notice, PEF requested the FPSC to approve calendar year 2006 as the
projected test period for setting new base rates. We have faced significant cost
increases over the past decade and expect our operational costs to continue to
increase. These costs include the costs associated with (i) completion of our
Hines 3 generation facility, (ii) extraordinary hurricane damage costs,
including approximately $50 million in capital costs which are not expected to
be directly recoverable, (iii) our need to replenish our depleted storm reserve
or adjust the annual accrual by approximately $50 million annually in light of
recent history on a going-forward basis, and (iv) the expected infrastructure
investment necessary to meet high customer expectations, coupled with the
demands placed on our strong customer growth. In addition, significant
additional costs include increased depreciation and fossil dismantlement
expenses in excess of $70 million when the provisions of the Agreement
addressing these expenses expire at the end of this year. We also face the
prospect of significant compliance costs from participation in the GridFlorida
regional transmission organization pursuant to FERC's transmission independence
initiative and the FPSC's related directive. Finally, as is the case with most
companies in our industry, we will continue to experience the pervasive upward
pressure of inflation on costs in general, especially the rapidly increasing
costs of employee healthcare and other benefit programs.
Under the Agreement, our base rates are at a level that existed in 1983; by
contrast, the Consumer Price Index has increased just over 90% since then. If
the FPSC does not approve our request for increased base rates, we will be faced
with a significantly increased cost structure that will not be covered by our
base rates. Additionally, as discussed below, the credit ratings of PEF may be
negatively impacted by the outcome of the rate case. As a result, our results of
operations, financial condition and ability to pay dividends could be materially
and adversely impacted.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
We own and operate five nuclear units through our subsidiaries, PEC (four units)
and PEF (one unit), that represent approximately 4,286 MW, or 18%, of our
generation capacity for the year ended December 31, 2004. Our nuclear facilities
are subject to environmental, health and financial risks such as the ability to
dispose of spent nuclear fuel, the ability to maintain adequate capital reserves
for decommissioning, potential liabilities arising out of the operation of these
facilities, and the costs of securing the facilities against possible terrorist
attacks. We maintain decommissioning trusts and external insurance coverage to
minimize the financial exposure to these risks; however, it is possible that
damages could exceed the amount of our insurance coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could require us to make substantial capital expenditures at our
nuclear plants. In addition, although we have no reason to anticipate a serious
nuclear incident at our plants, if an incident did occur, it could materially
and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.
195
From time to time, our facilities require licenses that need to be renewed or
extended in order to continue operating. We do not anticipate any problems
renewing these licenses as required. However, as a result of potential terrorist
threats and increased public scrutiny of utilities, the licensing process could
result in increased licensing or compliance costs that are difficult or
impossible to predict.
Our financial performance depends on the successful operation of electric
generating facilities by our subsidiaries and our ability to deliver electricity
to our customers.
Operating electric generating facilities and delivery systems involves many
risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as hurricanes, fires, earthquakes,
explosions, floods, terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated from our subsidiaries' electric
generating facilities and electricity delivery systems or an increase in the
cost of operating the facilities could have an adverse effect on our business
and results of operations.
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
We rely on access to both short-term and long-term capital markets, and lines of
credit with commercial banks as a significant source of liquidity for capital
requirements not satisfied by the cash flow from our operations. If we are not
able to access these sources of liquidity, our ability to implement our strategy
will be adversely affected. We believe that we will maintain sufficient access
to these financial markets based upon current credit ratings. However, certain
market disruptions or a downgrade of our credit rating to below investment grade
would increase our cost of borrowing and may adversely affect our ability to
access one or more financial markets. Market disruptions create a unique
uncertainty as they typically result from factors beyond are control. Such
market disruptions could include:
o an economic downturn;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
o allegations of corporate scandal at unrelated companies;
o market prices for electricity and gas;
o terrorist attacks or threatened attacks on our facilities or unrelated
energy companies; or
o the overall health of the utility industry.
In addition, we believe that these market disruptions, unrelated to our
business, could result in a ratings downgrade and, correspondingly, increase our
cost of capital. Additional risks regarding the impact of a ratings downgrade
are discussed below. Restrictions on our ability to access financial markets may
affect our ability to execute our business plan as scheduled. An inability to
access capital may limit our ability to pursue improvements or acquisitions that
we may otherwise rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
electric utilities. In addition to operating cash flows, we rely heavily on our
commercial paper and long-term debt. At December 31, 2004, commercial paper and
bank borrowings and long-term debt balances for Progress Energy and its
subsidiaries were as follows (in millions):
196
-----------------------------------------------------------------------------------------
Outstanding
Commercial Paper Total Long-Term
Company and Bank Borrowings Debt, Net
-----------------------------------------------------------------------------------------
Progress Energy, unconsolidated (a) $ 170 $ 4,449
PEC 221 2,750
PEF 293 1,912
Other Subsidiaries - 410 (b)
-----------------------------------------------------------------------------------------
Progress Energy, consolidated $ 684 $ 9,521 (c)
-----------------------------------------------------------------------------------------
(a) Represents solely the outstanding indebtedness of the holding company.
(b) Includes the following subsidiaries: Florida Progress Funding Corporation
($270 million) and Progress Capital Holdings, Inc. ($140 million).
(c) Net of current portion, which at December 31, 2004, was $349 million on a
consolidated basis.
At December 31, 2004, Progress Energy and its subsidiaries have an aggregate of
five committed credit lines that support our commercial paper programs totaling
$1.98 billion. While our financial policy precludes us from issuing commercial
paper in excess of our credit lines, at December 31, 2004, we had an outstanding
commercial paper balance and letters of credit of $574 million, leaving an
additional $931 million available for future borrowing under our credit lines.
On January 31, 2005 Progress Energy, Inc. entered into a new $600 million
revolving credit agreement, which expires December 30, 2005. This facility was
added to provide additional liquidity during 2005 due in part to storm
restoration costs incurred in Florida during 2004. The Credit Agreement includes
a defined maximum total debt to total capital ratio of 65% and a minimum
interest coverage ratio of 2.5 to 1. The Credit Agreement also contains various
cross-default and other acceleration provisions. On February 4, 2005, $300
million was drawn under the new facility to reduce commercial paper and bank
loans outstanding.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include defined maximum total debt to total capital (leverage)
ratios and minimum coverage ratios. Under the credit facilities, indebtedness
includes certain letters of credit and guarantees which are not recorded on our
consolidated Balance Sheets. At December 31, 2004, the required and actual
ratios were as follows:
- -----------------------------------------------------------------------------
Leverage Ratios Coverage Ratios
- -----------------------------------------------------------------------------
Actual Actual
Company Maximum Ratio Ratio Minimum Ratio Ratio
- -----------------------------------------------------------------------------
Progress Energy 65% 60.7% 2.5:1 4.00:1
PEC 65% 52.3% n/a n/a
PEF 65% 50.8% 3.0:1 7.93:1
- -----------------------------------------------------------------------------
In March 2005, Progress Energy, Inc.'s 5-year credit facility was amended to
increase the maximum total debt to total capital ratio from 65% to 68% in
connection with the potential accounting rules for uncertain tax positions. See
Notes 2 and 23E to the Progress Energy Consolidated Financial Statements.
In the event our capital structure changes such that we approach the permitted
ratios, our access to capital and additional liquidity could decrease.
Furthermore, the credit lines of PEC and PEF each include provisions under which
lenders could refuse to advance funds to each company under their respective
credit lines in the event of a material adverse change in the respective
company's financial condition. For Progress Energy's credit lines, loan draws
for the payment of maturing commercial paper are excluded from this provision. A
limitation in our liquidity could have a material adverse impact on our business
strategy and our ongoing financing needs.
Our indebtedness also includes several cross-default provisions which could
significantly impact our financial condition. Progress Energy's, PEC's and PEF's
credit lines each include cross-default provisions for defaults of indebtedness
in excess of $10 million. Under these provisions, if the applicable borrower or
certain subsidiaries fail to pay various debt obligations in excess of $10
million, the lenders could accelerate payment of any outstanding borrowings and
terminate their commitments to the credit facility. Progress Energy's cross
default provisions only apply to defaults of indebtedness by Progress Energy and
its significant subsidiaries (i.e., PEC, Florida Progress, PEF, PCH and Progress
Fuels). PEC's and PEF's cross-default provisions only apply to defaults of
indebtedness by PEC and PEF and their subsidiaries, respectively, not other
affiliates of PEC and PEF.
197
Additionally, certain of Progress Energy's long-term debt indentures contain
cross-default provisions for defaults of indebtedness in excess of $25 million;
these provisions only apply to other obligations of Progress Energy, not its
subsidiaries. In the event that either of these cross-default provisions is
triggered, the debt holders could accelerate payment of approximately $4.3
billion in long-term debt. Any such acceleration would cause a material adverse
change in the respective company's financial condition. Certain agreements
underlying our indebtedness also limit our ability to incur additional liens or
engage in certain types of sale and leaseback transactions.
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o impacting our ability to pay dividends on our common stock at the
current rate;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it,
for working capital, acquisitions, debt service requirements or other
purposes;
o increasing our vulnerability to adverse economic and industry
conditions;
o requiring us to dedicate a substantial portion of our cash flow from
operations to payments on our debt, which would reduce funds available
to us for operations, future business opportunities or other purposes;
o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors
who have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings which would cause us to be rated below
investment grade would likely increase our borrowing costs, limit our access to
additional capital and require posting of collateral, all of which could
materially and adversely affect our business, results of operations and
financial condition.
On February 11, 2005, Moody's Investors Service (Moody's) credit rating agency
announced that it lowered the ratings of Progress Energy Florida, Progress
Capital Holdings and FPC Capital Trust I and changed their rating outlooks to
stable from negative. Moody's affirmed the ratings of Progress Energy and PEC.
The rating outlooks continue to be stable at PEC and negative at Progress
Energy. Moody's stated that it took this action primarily due to declining
credit metrics, higher O&M costs, uncertainty regarding the timing of hurricane
cost recovery, regulatory risks associated with the upcoming rate case in
Florida and ongoing capital requirements to meet Florida's growing demand.
In October 2004, Moody's changed its outlook for Progress Energy from stable to
negative and placed the ratings of PEF under review for possible downgrade.
PEC's ratings were affirmed. Accordingly, Progress Energy's senior unsecured
debt is rated "Baa2," (negative outlook) by Moody's. Moody's cited weak
financial ratios relative to its current ratings category, rising O&M, pension,
benefit and insurance costs, and delays in executing its deleveraging plan as
the primary reasons for the change in outlook. With respect to PEF, Moody's
cited declining cash flows and rising leverage over the last several years,
expected funding needs for large capital expenditure programs, risks regarding
its upcoming 2005 rate case and the timing of hurricane cost recovery as the
primary reason for placing the PEF's credit ratings under review.
In October 2004, S&P also changed Progress Energy's outlook from stable to
negative. S&P cited uncertainties regarding the timing of recovery of hurricane
costs, the Company's debt reduction plans, and the IRS audit of our Earthco
synthetic fuel facilities as the primary reasons for the change in outlook. In
addition, for similar reasons, S&P reduced the short-term debt rating of
Progress Energy, PEC and PEF to "A-3" from "A-2". Progress Energy's senior
unsecured debt is rated "BBB-" by S&P. PEC's senior unsecured debt has been
assigned a rating by S&P of "BBB" (negative outlook) and by Moody's of "Baa1"
(stable outlook). PEF's senior unsecured debt has been assigned a rating by S&P
of "BBB" (negative outlook) and by Moody's of "A-3" (stable outlook).
The forgoing ratings actions by S&P and Moody's do not trigger any debt or
collateral guarantee requirement, however our short-term cost of capital has
increased by between 25 to 87.5 basis points. However, the ratings currently
assigned to Progress Energy's, senior unsecured debt is S&P's lowest investment
grade ratings category and has a negative outlook. Accordingly, any further
downgrade by S&P of Progress Energy's senior unsecured rating will result in a
noninvestment grade rating and will trigger debt and collateral guarantee
requirements (as described below), and may have a material adverse impact on our
cost of capital, results of operations and liquidity.
198
While the Company's long-term target credit ratings for each entity are above
the minimum investment grade ranking, we cannot assure you that any of Progress
Energy's current ratings, or those of PEC and PEF, will remain in effect for any
given period of time or that a rating will not be lowered or withdrawn entirely
by a rating agency if, in its judgment, circumstances in the future so warrant.
Any downgrade could increase our borrowing costs and may adversely affect our
access to capital, which could negatively impact our financial results. Further,
we may be required to pay a higher interest rate in future financings, and our
potential pool of investors and funding sources could decrease. Although we
would have access to liquidity under our committed and uncommitted credit lines,
if our short-term rating were to fall below A-3 or P-2, the current ratings
assigned by S&P and Moody's, respectively, our access to the commercial paper
market would be significantly limited. We note that the ratings from credit
agencies are not recommendations to buy, sell or hold our securities or those of
PEC or PEF and that each rating should be evaluated independently of any other
rating.
Our energy marketing business relies on Progress Energy's investment grade
ratings to stand behind transactions in that business. At December 31, 2004,
Progress Energy has issued guarantees with a notional amount of approximately
$809 million to support CCO's energy marketing businesses. Based upon the amount
of trading positions outstanding at December 31, 2004, if Progress Energy's
ratings were to decline below investment grade by either S&P or Moody's (i.e.,
below "BBB-" at S&P or below "Baa3" at Moody's), we would have to deposit cash
or provide letters of credit or other cash collateral for approximately $450
million for the benefit of our counterparties. Additionally, the power supply
agreement with Jackson Electric Membership Corporation that PVI acquires from
Williams Energy Marketing and Trading Company includes a performance guarantee
that Progress Energy assumed. In the event that Progress Energy's credit ratings
fall below investment grade, Progress Energy will be required to provide
additional security for its guarantee in form and amount acceptable to Jackson,
but not to exceed the coverage amount. The coverage amount at the inception of
PVI's power sale to Jackson is $285 million and will decline over the life of
the transaction. At December 31, 2004, the coverage amount is $275 million.
These collateral requirements could adversely affect our profitability on energy
trading and marketing transactions and limit our overall liquidity. In addition,
if we are unable to fund or otherwise satisfy these guarantee obligations our
financial condition and liquidity would be further impacted in a material
adverse manner.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
We could incur a significant tax liability, and our results of operations and
cash flows may be materially and adversely affected if the Internal Revenue
Service denies or otherwise makes unusable the Section 29 tax credits related to
our coal and synthetic fuels businesses.
Synthetic Fuel Risks Associated With the IRS Audit
Through our Fuels segment, we produce coal-based solid synthetic fuel. The
production and sale of the synthetic fuel from these facilities qualifies for
tax credits under Section 29 if certain requirements are satisfied, including a
requirement that the synthetic fuel differs significantly in chemical
composition from the coal used to produce such synthetic fuel and that the fuel
was produced from a facility that was placed in service before July 1, 1998. All
of our synthetic fuel facilities have received favorable private letter rulings
(PLRs) from the Internal Revenue Service (IRS) with respect to their synthetic
fuel operations, although these PLR's do not make any "placed-in-service"
determinations. These tax credits are subject to review by the IRS.
In July 2004, we were notified that the IRS field auditors anticipated taking an
adverse position regarding the placed-in-service date of the Company's four
Earthco synthetic fuel facilities. Due to the auditors' position, the IRS
decided to exercise its right to withdraw from the PFA program with us. In
October 2004, we received the IRS field auditors' report concluding that the
Earthco facilities had not been placed in service before July 1, 1998, and that
the tax credits generated by those facilities should be disallowed. We intend to
contest the field auditors' findings and their proposed disallowance of the tax
credits. We believe that the appeals process, including proceedings before the
IRS's National Office, could take up to two years to complete. We cannot control
the actual timing of resolution and cannot predict the outcome of this matter.
199
Through December 31, 2004, on a consolidated basis, we have or carried forward
approximately $1.0 billion of tax credits generated by the Earthco facilities.
If these credits were disallowed, our one-time exposure for cash tax payments
would be $294 million (excluding interest), and earnings and equity would be
reduced by approximately $1.0 billion, excluding interest. If we were required
to reverse approximately $1.0 billion of tax credits and pay $294 million for
taxes our financial condition, results of operations and liquidity would be
materially and adversely impacted.
Progress Energy's amended $1.13 billion credit facility includes a covenant
which limits the maximum debt-to-total capital ratio to 68%. This ratio includes
other forms of indebtedness such as guarantees issued by Progress Energy,
letters of credit and capital leases. As of December 31, 2004, Progress Energy's
debt-to-total capital ratio was 60.7% based on the credit agreement definition
for this ratio. The impact on this ratio of reversing approximately $1.0 billion
of tax credits and paying $294 million for taxes would be to increase the ratio
to 65.7%.
We believe that we operate in conformity with all the necessary requirements to
be allowed such credits under Section 29. The current Section 29 tax credit
program will expire at the end of 2007. With respect to any IRS review or audit
of our synthetic fuel operations, if we fail to prevail through the
administrative or legal process, there could be a significant tax liability owed
for previously taken Section 29 credits or we could lose our ability to claim
future tax credits that we might otherwise be able to benefit from both of which
would significantly impact earnings and cash flows.
In October 2003, the United States Senate Permanent Subcommittee on
Investigations began a general investigation concerning synthetic fuel tax
credits claimed under Section 29 of the Internal Revenue Code. The investigation
generally relates to the utilization of the tax credits, the nature of the
technologies and fuels created, the use of the synthetic fuel, and other aspects
of Section 29 and is not specific to our synthetic fuel operations. We are
providing information in connection with this investigation as requested.
Synthetic Fuel Risks Associated with Pending Accounting Rules for Uncertain Tax
Positions
In July 2004, the Financial Accounting Standards Board ("FASB") stated that it
plans to issue an exposure draft of a proposed interpretation of SFAS No. 109,
"Accounting for Income Taxes," that would address the accounting for uncertain
tax positions. The FASB has indicated that the interpretation would require that
uncertain tax benefits be probable of being sustained in order to record such
benefits in the financial statements. The exposure draft is expected to be
issued in the first quarter of 2005. Under the prevailing sentiment, the IRS
field auditors' recommendation that the Earthco tax credits be disallowed would
make it difficult to conclude that the tax benefits from the Earthco facilities
are probable of being sustained. Accordingly, it is likely we would not be able
to record the benefit of the Earthco tax credits on our financial statements.
This could require us to create a reserve up to $1.0 billion until the IRS issue
is resolved, which would immediately increase our debt to capitalization ratios.
The Company cannot predict what actions the FASB will take or how any such
actions might ultimately affect the Company's financial position or results of
operations, but such changes could have a material impact on the Company's
evaluation and recognition of Section 29 tax credits, which, in turn, may have a
material impact on our results of operations and financial condition.
Synthetic Fuel Risks Associated With Fluctuations in the Company's Regular
Income Tax Liability
The Company's synthetic fuel production levels and the amount of tax credits it
can claim each year are a function of the Company's projected consolidated
regular federal income tax liability. Any conditions that negatively impact the
Company's tax liability, such as weather, could also diminish the Company's
ability to utilize credits, including those previously generated, and the
synthetic fuel is generally not economical to produce absent the credits.
Synthetic Fuel Risks Associated With Crude Oil Prices
Recent unprecedented and unanticipated increases in the price of oil could limit
the amount of Section 29 tax credits or eliminate them altogether. Section 29
provides that if the average wellhead price per barrel for unregulated domestic
crude oil for the year (the "Annual Average Price") exceeds a certain threshold
value (the "Threshold Price"), the amount of Section 29 tax credits are reduced
for that year. Also, if the Annual Average Price increases high enough (the
"Phase Out Price"), the Section 29 tax credits are eliminated for that year. For
2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was
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$62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted
annually for inflation. Although data for 2004 is not yet available, we do not
expect the amount of our 2004 Section 29 tax credits to be adversely affected by
oil prices. We cannot predict with any certainty the Annual Average Price for
2005 or beyond. Therefore, we cannot predict whether the price of oil will have
a material effect on our synthetic fuel business after 2004. However, if during
2005 through 2007, oil prices remain at historically high levels or increase,
our synthetic fuel business may be adversely affected for those years and,
depending on the magnitude of such increases in oil prices, the adverse affect
for those years could be material and could have an impact on our synthetic fuel
production plans which, in turn, may have a material impact on our results of
operations and financial condition.
There are risks involved with the operation of our nonregulated plants,
including dependence on third parties and related counter-party risks, and a
lack of operating history, all of which may make our wholesale generation and
overall operations less profitable and more unstable.
At December 31, 2004, we had approximately 3,100 MW of nonregulated generation
in commercial operation.
The operation of wholesale generation facilities is subject to many risks,
including those listed below. During the execution of our wholesale generation
strategy, these risks will intensify. These risks include:
o We may enter into or otherwise acquire long-term contracts that take
effect at a future date based upon our current expectations of our
future wholesale generation capacity. If our expected future capacity
does not meet our expectations, we may not be able to meet our
obligations under any such long-term contracts and may have to
purchase power in the spot market at then prevailing prices.
Accordingly, we may lose current and future customers, impair our
ability to implement our wholesale strategy, and suffer reputational
harm. Additionally, if we are unable to secure favorable pricing in
the spot market, our results of operations may be diminished. We may
also become liable under any related performance guarantees then in
existence.
o Our wholesale facilities depend on third parties through power
purchase agreements, fuel supply and transportation agreements, and
transmission grid connection agreements. If such third parties breach
o their obligations to us, our revenues, financial condition, cash
flow and ability to make payments of interest and principal on our
outstanding debts may be impaired. Any material breach by any of these
parties of their obligations under the project contracts could
adversely affect our cash flows.
o We depend on transmission and distribution facilities owned and
operated by utilities and other energy companies to deliver the
electricity and natural gas that we sell to the wholesale market. If
transmission is disrupted, or if capacity is inadequate, our ability
to sell and deliver products and satisfy our contractual obligations
may be hindered. Although the FERC has issued regulations designed to
encourage competition in wholesale market transactions for
electricity, there is the potential that fair and equal access to
transmission systems will not be available or that sufficient
transmission capacity will not be available to transmit electric power
as we desire. We cannot predict the timing of industry changes as a
result of these initiatives or the adequacy of transmission facilities
in specific markets.
o Agreements with our counter-parties frequently will include the right
to terminate and/or withhold payments or performance under the
contracts if specific events occur. If a project contract were to be
terminated due to nonperformance by us or by the other party to the
contract, our ability to enter into a substitute agreement having
substantially equivalent terms and conditions is uncertain.
o Because many of our facilities are newly constructed and have no
significant operating history, various unexpected events may increase
our expenses or reduce our revenues. As with any new business venture
of this size and nature, operation of our facility could be affected
by many factors, including start-up problems, the breakdown or failure
of equipment or processes, the performance of our facility below
expected levels of output or efficiency, failure to operate at design
specifications, labor disputes, changes in law, failure to obtain
necessary permits or to meet permit conditions, government exercise of
eminent domain power or similar events and catastrophic events
including fires, explosions, earthquakes and droughts.
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o Our facilities seek to enter into long-term power purchase agreements
to sell all or a portion of their generating capacity. CCO currently
owns six electricity generation facilities with approximately 3,100 MW
of generation capacity, and it has contractual rights to an additional
2,500 MW of generation capacity from mixed fuel generation facilities
through its agreements with 16 Georgia electric membership
cooperatives (EMCs). CCO has contracts for its combined production
capacity of approximately 77% for 2005, 81% for 2006 and 75% for 2007.
Three above-market tolling agreements for approximately 1,200 MW of
capacity expired at the end of 2004. CCO has replaced the expired
agreements with the increased cooperative load in Georgia. The
increased cooperative load in Georgia will significantly increase
CCO's revenue and cost of sales from 2004 to 2005 with lower margins
expected. Following the expiration or early termination of our power
purchase agreements, or to the extent we cannot otherwise secure
contracts for our current and future generation capacity, our
facilities will generally become merchant facilities. Our merchant
facilities may not be able to find adequate purchasers, attain
favorable pricing, or otherwise compete effectively in the wholesale
market. Additionally, numerous legal and regulatory limitations
restrict our ability to operate a facility on a wholesale basis.
Our energy marketing and trading operations are subject to risks that may reduce
our revenues and adversely impact our results of operations and financial
condition, many of which are beyond our control.
Our fleet of nonregulated plants may sell energy into the spot market or other
competitive power markets or on a contractual basis. We may also enter into
contracts to purchase and sell electricity, natural gas and coal as part of our
power marketing and energy trading operations. Our business may also include
entering into long-term contracts that supply customers' full electric
requirements. More recently we have moved from tolling arrangements to full
requirements contracts which have lower margins. These contracts do not
guarantee us any rate of return on our capital investments through mandated
rates, and our revenues and results of operations from these contracts are
likely to depend, in large part, upon prevailing market prices for power in our
regional markets and other competitive markets. These market prices can
fluctuate substantially over relatively short periods of time. Trading margins
may erode as markets mature, and should volatility decline, we may have
diminished opportunities for gain.
In particular, we believe that over the past few years, the Southeastern
wholesale energy market has been overbuilt and accordingly believe that supply
exceeds demand. Due to this overbuilding, we believe that spot prices as well as
contractual pricing will provide us with a reduced rate of return on our capital
investment and our revenues and results of operations from this market will be
lower than originally expected unless and until demand catches up with supply.
In addition, the Enron Corporation bankruptcy and enhanced regulatory scrutiny
have contributed to more rigorous credit rating review of participants in the
energy marketing and trading business. Credit downgrades of certain other market
participants have significantly reduced such participants' participation in the
wholesale power markets. These events are causing a decrease in the number of
significant participants in the wholesale power markets, which could result in a
decrease in the volume and liquidity in the wholesale power markets. We are
unable to predict the impact of such developments on our power marketing and
trading business.
Furthermore, the FERC, which has jurisdiction over wholesale power rates, as
well as ISOs that oversee some of these markets, may impose price limitations,
bidding rules and other mechanisms to address some of the volatility in these
markets. Fuel prices also may be volatile, and the price we can obtain for power
sales may not change at the same rate as fuel costs changes. These factors could
reduce our margins and therefore diminish our revenues and results of
operations.
Volatility in market prices for fuel and power may result from:
o weather conditions;
o seasonality;
o power usage;
o illiquid markets;
o transmission or transportation constraints or inefficiencies;
o availability of competitively priced alternative energy sources;
o demand for energy commodities;
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o natural gas, crude oil and refined products, and coal production
levels;
o natural disasters, wars, embargoes and other catastrophic events; and
o federal, state and foreign energy and environmental regulation and
legislation.
We actively manage the market risk inherent in our energy marketing operations.
Nonetheless, adverse changes in energy and fuel prices may result in losses in
our earnings or cash flows and adversely affect our balance sheet. Our marketing
and risk management procedures may not work as planned. As a result, we cannot
predict with precision the impact that our marketing, trading and risk
management decisions may have on our business, operating results or financial
position. In addition, to the extent that we do not cover the entire exposure of
our assets or our positions to market price volatility, or our hedging
procedures do not work as planned, fluctuating commodity prices could cause our
sales and net income to be volatile.
Our Fuels business segment is involved in natural gas drilling and production,
coal terminal services, coal mining, and fuel transportation and delivery
operations that are subject to risks that may reduce our revenues and adversely
impact our results of operations and financial condition.
The Fuels business segment engages in businesses that have significant
operational and financial risk. Operational risk includes the activities
involved with natural gas drilling, coal mining, terminal and barge operations
and fuel delivery. Financial risks include exposure to commodity prices,
primarily fuel prices. We actively manage the operational and financial risks
associated with these businesses. Nonetheless, adverse changes in fuel prices
and operational issues beyond our control may result in losses in our earnings
or cash flows and adversely affect our balance sheet.
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PROGRESS ENERGY CAROLINAS, INC. RISK FACTORS
In this section, unless the context indicates otherwise, references to "our,"
"we," "us" or similar terms refer to Progress Energy Carolinas, Inc., and its
consolidated subsidiaries. Investing in our securities involves risks, including
the risks described below, that could affect the energy industry, as well as us
and our business. Most of the business information as well as the financial and
operational data contained in our risk factors are updated periodically in the
reports we file with the SEC. Although we have tried to discuss key factors,
please be aware that other risks may prove to be important in the future. New
risks may emerge at any time and we cannot predict such risks or estimate the
extent to which they may affect our financial performance. Before purchasing our
securities, you should carefully consider the following risks and the other
information in this Annual Report, as well as the documents we file with the SEC
from time to time. Each of the risks described below could result in a decrease
in the value of our securities and your investment therein.
Risks Related to the Energy Industry
We are subject to fluid and complex government regulations that may have a
negative impact on our business, financial condition and results of operations.
We are subject to comprehensive regulation by several federal, state and local
regulatory agencies, which significantly influence our operating environment and
may affect our ability to recover costs from utility customers. We are subject
to regulatory oversight with respect to, among other things, rates and service
for electric energy sold at retail, retail service territory and issuances of
securities. In addition our operating utilities are subject to regulation with
respect to transmission and sales of wholesale power, accounting and certain
other matters. We are also required to have numerous permits, approvals and
certificates from the agencies that regulate our business. We believe the
necessary permits, approvals and certificates have been obtained for our
existing operations and that our business is conducted in accordance with
applicable laws; however, we are unable to predict the impact on our operating
results from the future regulatory activities of any of these agencies. Changes
in regulations or the imposition of additional regulations could have an adverse
impact on our results of operations.
The 108th Congress spent much of 2004 working on a comprehensive energy bill.
While that legislation passed the House, the Senate failed to pass the
legislation in 2004. There will probably be an effort to resurrect the
legislation in 2005. The legislation would have further clarified the Federal
Energy Regulatory Commission's ("FERC") role with respect to Standard Market
Design and mandatory Regional Transmission Organizations ("RTOs") and would have
repealed the Public Utility Holding Company Act of 1935 ("PUHCA"). We cannot
predict the outcome or impact of the proposed or any future energy bill.
FERC, the U.S. Nuclear Regulatory Commission ("NRC"), the U.S. Environmental
Protection Agency ("EPA"), the North Carolina Utilities Commission ("NCUC") and
the Public Service Commission of South Carolina ("SCPSC") regulate many aspects
of our utility operations, including siting and construction of facilities,
customer service and the rates that we can charge customers. Although we are not
a registered holding company under PUHCA, we are subject to many of the
regulatory provisions of PUHCA.
We are unable to predict the impact on our business and operating results from
future regulatory activities of these federal, state and local agencies. Changes
in regulations or the imposition of additional regulations could have a negative
impact on our business, financial condition and results of operations.
We are subject to numerous environmental laws and regulations that require
significant capital expenditures, increase our cost of operations, and which may
impact or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental regulations affecting many aspects of
our present and future operations, including air emissions, water quality,
wastewater discharges, solid waste and hazardous waste. These laws and
regulations can result in increased capital, operating, and other costs,
particularly with regard to enforcement efforts focused on power plant emissions
obligations. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may seek to
enforce applicable environmental laws and regulations. We cannot predict the
outcome (financial or operational) of any related litigation that may arise.
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In addition, we may be a responsible party for environmental clean up at sites
identified by a regulatory body. We cannot predict with certainty the amount or
timing of all future expenditures related to environmental matters because of
the difficulty of estimating clean up costs. There is also uncertainty in
quantifying liabilities under environmental laws that impose joint and several
liability on all PRPs.
Our compliance with environmental regulations requires significant capital
expenditures that impact our financial condition. For example, in June 2002,
legislation was enacted in North Carolina requiring the state's electric
utilities to reduce the emissions of nitrogen oxide ("NOx") and sulfur dioxide
("SO2") from coal-fired power plants. We expect the capital costs required to
meet these emission targets will total approximately $895 million by 2013. Over
the next three years, we expect to incur approximately $510 million of total
capital costs associated with this legislation.
Congress currently considering further legislation that would require reductions
in air emissions of NOx, SO2, carbon dioxide and mercury. Some of these
proposals establish nationwide caps and emission rates over an extended period
of time. This national multi-pollutant approach to air pollution control could
involve significant capital costs which could be material to our consolidated
financial position or results of operations. However, we cannot predict the
outcome, costs or impact of this matter. In December 2003, the EPA released its
proposed Interstate Air Quality Rule, currently referred to as the Clean Air
Interstate Rule (CAIR). The EPA's proposal requires 29 jurisdictions, including
North Carolina, South Carolina, Georgia and Florida, to reduce NOx and SO2
emissions in order to attain preset state NOx and SO2 emissions levels. The rule
is expected to become final in March 2005. While the air quality controls
already installed and currently planned for installation to comply with the NC
Clean Air legislation will reduce the costs required to meet the CAIR
requirements for the our North Carolina units, additional compliance costs will
be determined once the rule is finalized. In March 2004, the North Carolina
Attorney General filed a petition with the EPA under Section 126 of the Clean
Air Act, asking the federal government to force coal-fired power plants in
thirteen other states, including South Carolina to reduce their NOx and SO2
emissions. The state of North Carolina contends these out-of-state emissions
interfere with North Carolina's ability to meet national air quality standards
for ozone and particulate matter. The EPA has agreed to make a determination on
the petition by August 1, 2005. PEC cannot predict the outcome or costs
associated with the matter.
See additional discussion of these environmental matters in Note 17 to the
Progress Energy Carolinas Consolidated Financial Statements.
We cannot assure you that existing environmental regulations will not be revised
or that new regulations seeking to protect the environment will not be adopted
or become applicable to us. Revised or additional regulations, which result in
increased compliance costs or additional operating restrictions, particularly if
those costs are not fully recoverable from our customers, could have a material
adverse effect on our results of operations.
The uncertain outcome regarding the timing, creation and structure of regional
transmission organizations, or RTOs, may materially impact our results of
operations, cash flows or financial condition.
Congress, FERC, and the state utility regulators have paid significant attention
in recent years to transmission issues, including the possibility of regional
transmission organizations. While these deliberations have not yet resulted in
significant changes to our utilities' transmission operations, they cast
uncertainty over those operations, which constitute a material portion of our
assets.
For the last several years, the FERC has supported independent RTOs and has
indicated a belief that it has the authority to order transmission-owning
utilities to transfer operational control of their transmission assets to such
RTOs. Many state regulators, including most regulators in the Southeast, have
expressed skepticism over the potential benefits of RTOs and generally disagree
with the FERC's interpretation of its authority to mandate RTOs. In July 2002,
the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01-12-000,
Remedying Undue Discrimination through Open Access Transmission Service and
Standard Electricity Market Design (SMD NOPR). The SMD NOPR could materially
alter the manner in which transmission and generation services are provided and
paid for, and includes structural separation of transmission from other utility
functions and the FERC's assertion of jurisdiction over certain aspects of
retail service. We cannot predict the outcome or timing of any final rules or
the effect that they may have on the GridSouth proceedings.
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At the state level, significant uncertainty exists with respect to what action,
if any, the NCUC will ultimately take. The Company has $33 million invested in
GridSouth related to startup costs at December 31, 2004. These amounts are
included as a regulatory asset at December 31, 2004. The Company expects to
recover these startup costs in conjunction with the GridSouth original
structures or in conjunction with any alternate combined transmission structures
that may be required. Furthermore, the SMD NOPR presents several uncertainties,
including what percentage of our investments in GridSouth will be recovered, how
the elimination of transmission charges, as proposed in the SMD NOPR, will
impact us, and what amount of capital expenditures will be necessary to create a
new wholesale market.
The actual structure of GridSouth or any alternative combined transmission
structure, as well as the date it may become operational, depends upon the
resolution of all regulatory approvals and technical issues. Given the
regulatory uncertainty of the ultimate timing, structure and operations of
GridSouth, or an alternate combined transmission structure, we cannot predict
whether it will be created, or whether it will have any material adverse effect
on our future consolidated results of operations, cash flows or financial
condition.
Since weather conditions directly influence the demand for and cost of providing
electricity, our results of operations, financial condition and cash flows can
fluctuate on a seasonal or quarterly basis and can be negatively affected by
changes in weather conditions and severe weather.
Our results of operations, financial condition, cash flows and ability to pay
dividends on our common stock may be affected by changing weather conditions.
Weather conditions in our service territories in North Carolina and South
Carolina directly influence the demand for electricity affect the price of
energy commodities necessary to provide electricity to our customers and energy
commodities that our nonregulated businesses sell.
Electric power demand is generally a seasonal business. In many parts of the
country, demand for power and market prices peak during the hot summer months.
In other areas, power demand peaks during the winter. As a result, our overall
operating results in the future may fluctuate substantially on a seasonal basis.
The pattern of this fluctuation may change depending on the nature and location
of facilities we acquire and the terms of power sale contracts into which we
enter. In addition, we have historically sold less power, and consequently
earned less income, when weather conditions are milder. Unusually mild weather
could diminish our results of operations and harm our financial condition.
Furthermore, severe weather in these states, such as hurricanes, tornadoes,
severe thunderstorms, snow and ice storms, can be destructive, causing outages,
downed power lines and property damage, requiring us to incur additional and
unexpected expenses and causing us to lose generating revenues.
Our ability to recover significant costs resulting from severe weather events is
subject to regulatory oversight and the timing and amount of any such recovery
is uncertain and may impact our financial conditions.
PEC is not required to maintain a storm damage reserve account and does not have
an ongoing regulatory mechanism to recover storm costs and; therefore, hurricane
restoration costs recorded in the third quarter of 2004 were charged to
operations and maintenance expenses or capital expenditures based on the nature
of the work performed. In connection with other storms, PEC has previously
sought and received permission from the NCUC and the SCPSC to defer storm
expenses and amortize them over a five-year period. PEC did not seek recovery of
2004 storm costs from the NCUC.
Our revenues, operating results and financial condition may fluctuate with the
economy and its corresponding impact on our commercial and industrial customers
as well as the demand and competitive state of the wholesale market.
Our business is impacted by fluctuations in the macroeconomy. For the year ended
December 31, 2004, commercial and industrial customers represented approximately
25% and 19%, respectively, of our billed electric revenues. As a result, changes
in the macroeconomy can have negative impacts on our revenues. As our commercial
and industrial customers experience economic hardships, our revenues can be
negatively impacted. In recent years, in North and South Carolina, sales to
industrial customers have been affected by downturns in the textile and chemical
industries.
For the year ended December 31, 2004, 16% of our billed electric revenues were
from wholesale sales. Wholesale revenues fluctuate with regional demand, fuel
prices, and contracted capacity. Our wholesale profitability is dependent upon
our ability to renew or replace expiring wholesale contracts on favorable terms.
During 2004, wholesale revenues decreased from expiring contracts being
renegotiated by us at less favorable terms due to slightly depressed markets and
from increased competition in the wholesale markets served by us. If this trend
market environment persists, we may experience further declines in our wholesale
revenues.
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In April 2004, the FERC issued two orders concerning utilities' ability to sell
wholesale electricity at market-based rates. In the first order, the FERC
adopted two new interim screens for assessing potential generation market power
of applicants for wholesale market-based rates, and described additional
analyses and mitigation measures that could be presented if an applicant does
not pass one of these interim screens. In July 2004, the FERC issued an order on
rehearing affirming its conclusions in the April order. In the second order, the
FERC initiated a rulemaking to consider whether the FERC's current methodology
for determining whether a public utility should be allowed to sell wholesale
electricity at market-based rates should be modified in any way. Given the
difficulty PEC believes it would experience in passing one of the interim
screens, on August 12, 2004, PEC notified the FERC that it would revise its
Market-based Rate tariff to restrict it to sales outside our control area and
file a new cost-based tariff for sales within our control area that incorporates
the FERC's default cost-based rate methodologies for sales of one year or less.
We anticipate making this filing the first quarter of 2005. We cannot predict
what impact our requirement to implement cost-based tariffs will have on our
future financial condition, results of operations or cash flows.
Deregulation or restructuring in the electric industry may result in increased
competition and unrecovered costs that could adversely affect our financial
condition, results of operations or cash flows.
Increased competition resulting from deregulation or restructuring efforts could
have a significant adverse financial impact on us and our utility subsidiaries
and consequently on our results of operations and cash flows. Increased
competition could also result in increased pressure to lower costs, including
the cost of electricity. Retail competition and the unbundling of regulated
energy and gas service could have a significant adverse financial impact on us
and our subsidiaries due to an impairment of assets, a loss of retail customers,
lower profit margins or increased costs of capital. Because we have not
previously operated in a competitive retail environment, we cannot predict the
extent and timing of entry by additional competitors into the electric markets.
Due to several factors, however, there currently is little discussion of any
movement toward deregulation in North Carolina and South Carolina. We cannot
predict when we will be subject to changes in legislation or regulation, nor can
we predict the impact of these changes on our financial condition, results of
operations or cash flows.
Increased commodity prices may adversely affect the financial condition, results
of operations or cash flows of us and our utilities' businesses.
We are exposed to the effects of market fluctuations in the price of natural
gas, coal, fuel oil, electricity and other energy-related products marketed and
purchased as a result of its ownership of energy-related assets. While each
state commission allows electric utilities to recover certain of these costs
through various cost recovery clauses, there is the potential that these future
costs could be deemed imprudent by the respective commissions. There is also a
delay between the timing of when these costs are incurred by the utilities and
when these costs are recovered from the ratepayers, which can adversely impact
our cash flows.
Prices for SO2 emission allowance credits under the EPA's emission trading
program increased significantly during 2004. While SO2 allowances are eligible
for annual recovery in our jurisdiction in South Carolina, no such annual
recovery exists in North Carolina. Future increases in the price of SO2
allowances could have a significant adverse financial impact on us and
consequently on our results of operations and cash flows.
Risks Related to Us and Our Business
The rates that we may charge retail customers for electric power are subject to
the authority of state regulators. Accordingly, our profit margins could be
adversely affected if we do not control operating costs.
The NCUC and the SCPSC each exercise regulatory authority for review and
approval of the retail electric power rates charged within its respective state.
State regulators may not allow our utility subsidiaries to increase retail rates
in the manner or to the extent requested by those subsidiaries. State regulators
may also seek to reduce retail rates.
Additionally, under the NC Clean Air legislation in North Carolina, passed in
2002, PEC's base retail rates were frozen for five years unless there are
significant cost changes due to governmental action, significant expenditures
due to force majeure or other extraordinary events beyond our control, and we
have agreed not to seek a base retail electric rate increase in South Carolina
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through 2005. The same legislation required a significant increase in capital
expenditures over the next several years for clean air improvements. The cash
costs incurred by us is generally not subject to being fixed or reduced by state
regulators. We will also require dedicated capital expenditures. Thus, our
ability to maintain our profit margins depends upon stable demand for
electricity and our efforts to manage our costs.
There are inherent potential risks in the operation of nuclear facilities,
including environmental, health, regulatory, terrorism, and financial risks that
could result in fines or the shutdown of our nuclear units, which may present
potential exposures in excess of our insurance coverage.
We own and operate four nuclear units that represent approximately 3,448 MW, or
28%, of our generation capacity for the year ended December 31, 2004. Our
nuclear facilities are subject to environmental, health and financial risks such
as the ability to dispose of spent nuclear fuel, the ability to maintain
adequate capital reserves for decommissioning, potential liabilities arising out
of the operation of these facilities, and the costs of securing the facilities
against possible terrorist attacks. We maintain decommissioning trusts and
external insurance coverage to minimize the financial exposure to these risks;
however, it is possible that damages could exceed the amount of our insurance
coverage.
The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines or to
shut down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could require us to make substantial capital expenditures at our
nuclear plants. In addition, although we have no reason to anticipate a serious
nuclear incident at our plants, if an incident did occur, it could materially
and adversely affect our results of operations or financial condition. A major
incident at a nuclear facility anywhere in the world could cause the NRC to
limit or prohibit the operation or licensing of any domestic nuclear unit.
From time to time, our facilities require licenses that need to be renewed or
extended in order to continue operating. We do not anticipate any problems
renewing these licenses as required. However, as a result of potential terrorist
threats and increased public scrutiny of utilities, the licensing process could
result in increased licensing or compliance costs that are difficult or
impossible to predict.
Our financial performance depends on the successful operation of our electric
generating facilities and our ability to deliver electricity to our customers.
Operating electric generating facilities and delivery systems involves many
risks, including:
o operator error and breakdown or failure of equipment or processes;
o operating limitations that may be imposed by environmental or other
regulatory requirements;
o labor disputes;
o fuel supply interruptions; and
o catastrophic events such as hurricanes, fires, earthquakes,
explosions, floods, terrorist attacks or other similar occurrences.
A decrease or elimination of revenues generated from our subsidiaries' electric
generating facilities and electricity delivery systems or an increase in the
cost of operating the facilities could have an adverse effect on our business
and results of operations.
Our business is dependent on our ability to successfully access capital markets.
Our inability to access capital may limit our ability to execute our business
plan, or pursue improvements and make acquisitions that we may otherwise rely on
for future growth.
We rely on access to both short-term and long-term capital markets, and lines of
credit with commercial banks as a significant source of liquidity for capital
requirements not satisfied by the cash flow from our operations. If we are not
able to access these sources of liquidity, our ability to implement our strategy
will be adversely affected. We believe that we will maintain sufficient access
to these financial markets based upon current credit ratings. However, certain
market disruptions or a downgrade of our credit rating to below investment grade
would increase our cost of borrowing and may adversely affect our ability to
access one or more financial markets. Market disruptions create a unique
uncertainty as they typically result from factors beyond are control. Such
market disruptions could include:
o an economic downturn;
o the bankruptcy of an unrelated energy company;
o capital market conditions generally;
208
o allegations of corporate scandal at unrelated companies;
o market prices for electricity and gas;
o terrorist attacks or threatened attacks on our facilities or unrelated
energy companies; or
o the overall health of the utility industry.
In addition, we believe that these market disruptions, unrelated to our
business, could result in a ratings downgrade and, correspondingly, increase our
cost of capital. Additional risks regarding the impact of a ratings downgrade
are discussed below. Restrictions on our ability to access financial markets may
affect our ability to execute our business plan as scheduled. An inability to
access capital may limit our ability to pursue improvements or acquisitions that
we may otherwise rely on for future growth.
Increases in our leverage could adversely affect our competitive position,
business planning and flexibility, financial condition, ability to service our
debt obligations and to pay dividends on our common stock, and ability to access
capital on favorable terms.
Our cash requirements arise primarily from the capital-intensive nature of our
electric utilities. In addition to operating cash flows, we rely heavily on our
commercial paper and long-term debt. At December 31, 2004, our commercial paper
and bank borrowings and long-term debt balances were as follows (in millions):
----------------------------------------------------------------------
Outstanding
Commercial Paper Total Long-Term
Company and Bank Borrowings Debt, Net
----------------------------------------------------------------------
PEC 221 2,750 (a)
----------------------------------------------------------------------
(a) Net of current portion, which at December 31, 2004, was $300 million.
At December 31, 2004, we had two committed credit lines that support our
commercial paper programs totaling $450 million. While our financial policy
precludes us from issuing commercial paper in excess of our credit lines, at
December 31, 2004, we had outstanding borrowings on our credit facilities of $90
million and an outstanding commercial paper balance of $131 million, leaving an
additional $229 million available for future borrowing under our credit lines.
Our credit lines impose various limitations that could impact our liquidity. Our
credit facilities include a defined maximum total debt to total capital
(leverage) ratio. At December 31, 2004, the maximum and actual leverage ratios,
pursuant to the terms of the credit facilities, were 65% and 52.3%,
respectively. Under the credit facilities, indebtedness includes certain letters
of credit and guarantees which are not recorded on our Consolidated Balance
Sheets.
In the event our capital structure changes such that we approach the permitted
ratios, our access to capital and additional liquidity could decrease.
Furthermore, our credit lines include provisions under which lenders could
refuse to advance funds to each company under their respective credit lines in
the event of a material adverse change in the respective company's financial
condition. A limitation in our liquidity could have a material adverse impact on
our business strategy and our ongoing financing needs.
Our indebtedness also includes several cross-default provisions which could
significantly impact our financial condition. Our credit lines include
cross-default provisions for defaults of indebtedness in excess of $10 million.
Under these provisions, if the applicable borrower or certain subsidiaries fail
to pay various debt obligations in excess of $10 million, the lenders could
accelerate payment of any outstanding borrowings and terminate their commitments
to the credit facility. Our cross-default provisions only apply to defaults of
indebtedness, but not defaults by our affiliates.
209
Changes in economic conditions could result in higher interest rates, which
would increase our interest expense on our floating rate debt and reduce funds
available to us for our current plans. Additionally, an increase in our leverage
could adversely affect us by:
o increasing the cost of future debt financing;
o making it more difficult for us to satisfy our existing financial
obligations;
o limiting our ability to obtain additional financing, if we need it,
for working capital, acquisitions, debt service requirements or other
purposes;
o increasing our vulnerability to adverse economic and industry
conditions;
o requiring us to dedicate a substantial portion of our cash flow from
operations to payments on our debt, which would reduce funds available
to us for operations, future business opportunities or other purposes;
o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we compete;
o placing us at a competitive disadvantage compared to our competitors
who have less debt; and
o causing a downgrade in our credit ratings.
Any reduction in our credit ratings which would cause us to be rated below
investment grade would likely increase our borrowing costs, limit our access to
additional capital and require posting of collateral, all of which could
materially and adversely affect our business, results of operations and
financial condition.
Our senior secured debt has been assigned a rating by Standard & Poor's Ratings
Group, a division of The McGraw Hill Companies, Inc., of "BBB" (negative
outlook), by Moody's Investors Service, Inc. of "A3" (stable outlook). Our
senior unsecured debt rating has been assigned a rating by S&P of "BBB"
(negative outlook) and by Moody's of "Baa1" (stable outlook). In addition, S&P's
rating philosophy links the ratings of a utility subsidiary to the credit rating
of its parent corporation. Accordingly, if S&P were to downgrade Progress
Energy, Inc.'s credit ratings, our credit rating would also likely be
downgraded, regardless of whether or not we had experienced any change in our
business operations or financial conditions. We will seek to maintain a solid
investment grade rating through prudent capital management and financing
structures. We cannot, however, assure you that our current ratings will remain
in effect for any given period of time or that our ratings will not be lowered
or withdrawn entirely by a rating agency if, in its judgment, circumstances in
the future so warrant. Any downgrade could increase our borrowing costs and
adversely affect our access to capital, which could negatively impact our
financial results. Further, we may be required to pay a higher interest rate in
future financings, and our potential pool of investors and funding sources could
decrease. In October 2004, S&P reduced our short-term debt rating to A-3 from
A-2. As a result of the impact of these actions, we have borrowed on our
revolving credit agreements. Due to the lower short-term debt rating issued by
S&P, we may continue to borrow under our revolving credit facilities instead of
issuing commercial paper due to the difference in investor demand for
lower-rated commercial paper. We note that the ratings from credit agencies are
not recommendations to buy, sell or hold our securities and that each rating
should be evaluated independently of any other rating.
The use of derivative contracts in the normal course of our business could
result in financial losses that negatively impact our results of operations.
We use derivatives, including futures, forwards and swaps, to manage our
commodity and financial market risks. In the future, we could recognize
financial losses on these contracts as a result of volatility in the market
values of the underlying commodities or if a counterparty fails to perform under
a contract. In the absence of actively quoted market prices and pricing
information from external sources, the valuation of these financial instruments
can involve management's judgment or use of estimates. As a result, changes in
the underlying assumptions or use of alternative valuation methods could affect
the value of the reported fair value of these contracts.
210
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrants have duly caused this report to be signed on their
behalf by the undersigned, thereunto duly authorized.
PROGRESS ENERGY, INC.
CAROLINA POWER & LIGHT COMPANY
Date: March 16, 2005 (Registrants)
By: /s/Robert B. McGehee
-------------------------------------
Robert B. McGehee
Chief Executive Officer
Progress Energy, Inc.
By: /s/Fred N. Day IV
-------------------------------------
Fred N. Day IV
President and Chief Executive Officer
Carolina Power & Light Company
By: /s/Geoffrey S. Chatas
-------------------------------------
Geoffrey S. Chatas
Executive Vice President and
Chief Financial Officer
Progress Energy, Inc.
Carolina Power & Light Company
By: /s/Robert H. Bazemore, Jr.
-------------------------------------
Robert H. Bazemore, Jr.
Controller
(Chief Accounting Officer)
Progress Energy, Inc.
Carolina Power & Light Company
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the date indicated.
Signature Title Date
/s/ Robert B. McGehee Director March 16, 2005
- ---------------------
(Robert B. McGehee,
Chairman)
/s/ Edwin B. Borden Director March 16, 2005
- -------------------
(Edwin B. Borden)
/s/ James E. Bostic, Jr. Director March 16, 2005
- -----------------------
(James E. Bostic, Jr.)
/s/ David L. Burner Director March 16, 2005
- -------------------
(David L. Burner)
211
/s/ Charles W. Coker Director March 16, 2005
- ---------------------
(Charles W. Coker)
/s/ Richard L. Daugherty Director March 16, 2005
(Richard L. Daugherty)
/s/ W.D. Frederick, Jr. Director March 16, 2005
- -----------------------
(W.D. Frederick, Jr.)
/s/ William O. McCoy Director March 16, 2005
- ---------------------
(William O. McCoy)
/s/ E. Marie McKee Director March 16, 2005
- -------------------
(E. Marie McKee)
/s/ John H. Mullin, III Director March 16, 2005
- -----------------------
(John H. Mullin, III)
/s/ Richard A. Nunis Director March 16, 2005
(Richard A. Nunis)
/s/Peter S. Rummell Director March 16, 2005
(Peter S. Rummell)
/s/ Carlos A. Saladrigas Director March 16, 2005
- ------------------------
(Carlos A. Saladrigas)
/s/ Jean Giles Wittner Director March 16, 2005
- ----------------------
(Jean Giles Wittner)
212
EXHIBIT INDEX
Progress
Number Exhibit Energy, Inc. PEC
*2(a) Agreement and Plan of Exchange, dated as of August 22, X X
1999, by and among Carolina Power & Light Company,
Florida Progress Corporation and CP&L Holdings, Inc.
(filed as Exhibit 2.1 to Current Report on Form 8-K dated
August 22, 1999, File No. 1-3382).
*2(b) Amended and Restated Agreement and Plan of Exchange, by X X
and among Carolina Power & Light Company, Florida
Progress Corporation and CP&L Energy, Inc., dated as of
August 22, 1999, amended and restated as of March 3,
2000, (filed as Annex A to Joint Preliminary Proxy
Statement of Carolina Power & Light Company and Florida
Progress Corporation dated March 6, 2000, File No.
1-3382).
*3a(1) Restated Charter of Carolina Power & Light Company, as X
amended May 10, 1995, (filed as Exhibit No. 3(i) to
Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 1995, File No. 1-3382).
*3a(2) Restated Charter of Carolina Power & Light Company as X
amended on May 10, 1996, (filed as Exhibit No. 3(i) to
Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 1997, File No. 1-3382).
*3a(3) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on June 15, 2000,
(filed as Exhibit No. 3a(1) to Quarterly Report on Form
10-Q for the quarterly period ended June 30, 2000, File
No. 1-15929 and No. 1-3382).
*3b(1) Amended and Restated Articles of Incorporation of CP&L X
Energy, Inc., as amended and restated on December 4,
2000, (filed as Exhibit 3b(1) to Annual Report on Form
10-K dated March 28, 2002, File No. 1-3392 and 1-15929).
*3b(2) By-Laws of Carolina Power & Light Company, as amended on X
March 17, 2004, (filed as Exhibit No. 3(ii)(b) to
Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 2004, File No. 1-3382 and 1-15929).
*3b(3) By-Laws of Carolina Power & Light Company, as amended on X
December 12, 2001 (filed as Exhibit 3b(2) to Annual
Report on Form 10-K dated March 28, 2002, File No. 1-3382
and 1-15929).
*3b(4) By-Laws of Progress Energy, Inc., as amended on March 17, X
2004, (filed as Exhibit No. 3(ii)(a) to Quarterly Report
on Form 10-Q for the quarterly period ended March 31,
2004, File No. 1-3382 and 1-15929).
*3b(5) By-Laws of Progress Energy, Inc., as amended and restated X
December 12, 2001, (filed as Exhibit No. 3 to Current
Report on Form 8-K dated January 17, 2002, File No.
1-15929).
213
*4a(1) Resolution of Board of Directors, dated December 8, 1954, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
Carolina Power & Light Company's Serial Preferred Stock,
$4.20 Series (filed as Exhibit 3(c), File No. 33-25560).
*4a(2) Resolution of Board of Directors, dated January 17, 1967, X
authorizing the issuance of, and establishing the series
designation, dividend rate and redemption prices for
Carolina Power & Light Company's Serial Preferred Stock,
$5.44 Series (filed as Exhibit 3(d), File No. 33-25560).
*4a(3) Statement of Classification of Shares dated January 13, X
1971, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for Carolina Power & Light Company's Serial
Preferred Stock, $7.95 Series (filed as Exhibit 3(f),
File No. 33-25560).
*4a(4) Statement of Classification of Shares dated September 7, X
1972, relating to the authorization of, and establishing
the series designation, dividend rate and redemption
prices for Carolina Power & Light Company's Serial
Preferred Stock, $7.72 Series (filed as Exhibit 3(g),
File No. 33-25560).
*4b(1) Mortgage and Deed of Trust dated as of May 1, 1940, X
between Carolina Power & Light Company and The Bank of
New York (formerly, Irving Trust Company) and Frederick
G. Herbst (Douglas J. MacInnes, Successor), Trustees and
the First through Fifth Supplemental Indentures thereto
(Exhibit 2(b), File No. 2-64189); the Sixth through
Sixty-sixth Supplemental Indentures (Exhibit 2(b)-5, File
No. 2-16210; Exhibit 2(b)-6, File No. 2-16210; Exhibit
4(b)-8, File No. 2-19118; Exhibit 4(b)-2, File No.
2-22439; Exhibit 4(b)-2, File No. 2-24624; Exhibit 2(c),
File No. 2-27297; Exhibit 2(c), File No. 2-30172; Exhibit
2(c), File No. 2-35694; Exhibit 2(c), File No. 2-37505;
Exhibit 2(c), File No. 2-39002; Exhibit 2(c), File No.
2-41738; Exhibit 2(c), File No. 2-43439; Exhibit 2(c),
File No. 2-47751; Exhibit 2(c), File No. 2-49347; Exhibit
2(c), File No. 2-53113; Exhibit 2(d), File No. 2-53113;
Exhibit 2(c), File No. 2-59511; Exhibit 2(c), File No.
2-61611; Exhibit 2(d), File No. 2-64189; Exhibit 2(c),
File No. 2-65514; Exhibits 2(c) and 2(d), File No.
2-66851; Exhibits 4(b)-1, 4(b)-2, and 4(b)-3, File
No. 2-81299; Exhibits 4(c)-1 through 4(c)-8, File
No. 2-95505; Exhibits 4(b) through 4(h), File No.
33-25560; Exhibits 4(b) and 4(c), File No. 33-33431;
Exhibits 4(b) and 4(c), File No. 33-38298; Exhibits 4(h)
214
and 4(i), File No. 33-42869; Exhibits 4(e)-(g), File No.
33-48607; Exhibits 4(e) and 4(f), File No. 33-55060;
Exhibits 4(e) and 4(f), File No. 33-60014; Exhibits 4(a)
and 4(b) to Post-Effective Amendment No. 1, File No.
33-38349; Exhibit 4(e), File No. 33-50597; Exhibit 4(e)
and 4(f), File No. 33-57835; Exhibit to Current Report on
Form 8-K dated August 28, 1997, File No. 1-3382; Form of
Carolina Power & Light Company First Mortgage Bond, 6.80%
Series Due August 15, 2007 filed as Exhibit 4 to Form
10-Q for the period ended September 30, 1998, File No.
1-3382; Exhibit 4(b), File No. 333-69237; and Exhibit
4(c) to Current Report on Form 8-K dated March 19, 1999,
File No. 1-3382.); and the Sixty-eighth Supplemental
Indenture (Exhibit No. 4(b) to Current Report on Form 8-K
dated April 20, 2000, File No. 1-3382; and the
Sixty-ninth Supplemental Indenture (Exhibit No. 4b(2) to
Annual Report on Form 10-K dated March 29, 2001, File No.
1-3382); and the Seventieth Supplemental Indenture,
(Exhibit 4b(3) to Annual Report on Form 10-K dated March
29, 2001, File No. 1-3382); and the Seventy-first
Supplemental Indenture (Exhibit 4b(2) to Annual Report on
Form 10-K dated March 28, 2002, File No. 1-3382 and
1-15929); and the Seventy-second Supplemental Indenture
(Exhibit 4 to PEC Report on Form 8-K dated September 12,
2003, File No. 1-3382).
*4c(1) Indenture, dated as of February 15, 2001, between X
Progress Energy, Inc. and Bank One Trust Company, N.A.,
as Trustee, with respect to Senior Notes (filed as
Exhibit 4(a) to Form 8-K dated February 27, 2001, File
No. 1-15929).
*4c(2) Indenture, dated as of March 1, 1995, between Carolina X
Power & Light Company and Bankers Trust Company, as
Trustee, with respect to Unsecured Subordinated Debt
Securities (filed as Exhibit No. 4(c) to Current Report
on Form 8-K dated April 13, 1995, File No. 1-3382).
*4c(3) Resolutions adopted by the Executive Committee of the X
Board of Directors at a meeting held on April 13, 1995,
establishing the terms of the 8.55% Quarterly Income
Capital Securities (Series A Subordinated Deferrable
Interest Debentures) (filed as Exhibit 4(b) to Current
Report on Form 8-K dated April 13, 1995, File No. 1-3382).
*4d Indenture (for Senior Notes), dated as of March 1, 1999, X
between Carolina Power & Light Company and The Bank of
New York, as Trustee, (filed as Exhibit No. 4(a) to
Current Report on Form 8-K dated March 19, 1999, File No.
1-3382), and the First and Second Supplemental Senior
Note Indentures thereto (Exhibit No. 4(b) to Current
Report on Form 8-K dated March 19, 1999, File No.
1-3382); Exhibit No. 4(a) to Current Report on Form 8-K
dated April 20, 2000, File No. 1-3382).
*4e Indenture (For Debt Securities), dated as of October 28, X
1999, between Carolina Power & Light Company and The
Chase Manhattan Bank, as Trustee (filed as Exhibit 4(a)
to Current Report on Form 8-K dated November 5, 1999,
File No. 1-3382), and an Officer's Certificate issued
pursuant thereto, dated as of October 28, 1999,
authorizing the issuance and sale of Extendible Notes due
October 28, 2009 (Exhibit 4(b) to Current Report on Form
8-K dated November 5, 1999, File No. 1-3382).
215
*4f Contingent Value Obligation Agreement, dated as of X
November 30, 2000, between CP&L Energy, Inc. and The
Chase Manhattan Bank, as Trustee (Exhibit 4.1 to Current
Report on Form 8-K dated December 12, 2000, File No.
1-3382).
*10a(1) Purchase, Construction and Ownership Agreement dated July X
30, 1981, between Carolina Power & Light Company and
North Carolina Municipal Power Agency Number 3 and
Exhibits, together with resolution dated December 16,
1981, changing name to North Carolina Eastern Municipal
Power Agency, amending letter dated February 18, 1982,
and amendment dated February 24, 1982, (filed as
Exhibit 10(a), File No. 33-25560).
*10a(2) Operating and Fuel Agreement dated July 30, 1981, between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981, changing name to
North Carolina Eastern Municipal Power Agency, amending
letters dated August 21, 1981 and December 15, 1981, and
amendment dated February 24, 1982 (filed as
Exhibit 10(b), File No. 33-25560).
*10a(3) Power Coordination Agreement dated July 30, 1981, between X
Carolina Power & Light Company and North Carolina
Municipal Power Agency Number 3 and Exhibits, together
with resolution dated December 16, 1981, changing name to
North Carolina Eastern Municipal Power Agency and
amending letter dated January 29, 1982, (filed as
Exhibit 10(c), File No. 33-25560).
*10a(4) Amendment dated December 16, 1982 to Purchase, X
Construction and Ownership Agreement dated July 30, 1981,
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency (filed as Exhibit 10(d),
File No. 33-25560).
*10a(5) Agreement Regarding New Resources and Interim Capacity X
between Carolina Power & Light Company and North Carolina
Eastern Municipal Power Agency dated October 13, 1987,
(filed as Exhibit 10(e), File No. 33-25560).
*10a(6) Power Coordination Agreement - 1987A between North X
Carolina Eastern Municipal Power Agency and Carolina
Power & Light Company for Contract Power From New
Resources Period 1987-1993 dated October 13, 1987, (filed
as Exhibit 10(f), File No. 33-25560).
*10b(1) Progress Energy, Inc. $600,000,000 364-Day Revolving X
Credit Agreement dated as of January 31, 2005, (filed as
Exhibit 10 to Current Report on Form 8-K filed February
4, 2005, File No. 1-15929).
*10b(2) Progress Energy, Inc. $1,130,000,000 5-Year Revolving X
Credit Agreement dated as of August 5, 2004, (filed as
Exhibit 10(i) to Quarterly Report on Form 10-Q for the
period ended June 30, 2004, File No. 1-3382 and 1-15929).
216
*10b(3) Amendment and Restatement, dated as of July 30, 2003, to X
the 364-Day Revolving Credit Agreement among PEC and
certain lenders (filed as Exhibit 10(v) to Quarterly
Report on Form 10-Q for the period ended June 30, 2003,
File No. 1-03382 and 1-15929).
*10b(4) Notice, dated March 25, 2003, to the Agent for the X
Lenders named in the PEC 364-Day Revolving Credit
Agreement, dated July 31, 2002, of a commitment reduction
in the amount of $120,000,000 (filed as Exhibit 10(ii) to
Quarterly Report on Form 10-Q for the period ended March
31, 2003, File No. 1-03382 and 1-15929).
*10b(5) Assumption Agreement from The Bank of New York dated X
August 5, 2002, for a total commitment of $25 million,
increasing the amount of the PEC 364-Day and 3-Year
Revolving Credit Agreements, dated as of July 31, 2002,
to $285,000,000 each (filed as Exhibit 10(v) to Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 2002, File No. 1-03382 and 1-15929).
*10b(6) Carolina Power & Light Company $272,500,000 364-Day X
Revolving Credit Agreement dated as of July 31, 2002,
(filed as Exhibit 10(iii) to Quarterly Report on Form
10-Q for the period ended September 30, 2002, File No.
1-3382 and 1-15929).
*10b(7) Carolina Power & Light Company $272,500,000 3-Year X
Revolving Credit Agreement dated as of July 31, 2002,
(filed as Exhibit 10(iv) to Quarterly Report on Form 10-Q
for the period ended September 30, 2002, File No. 1-3382
and 1-15929).
*10b(8) PEF 364-Day $200,000,000 Credit Agreement dated as of X
April 1, 2003 (filed as Exhibit 10(ii) to Florida Power
Corporation Form 10-Q for the quarter ended March 31,
2003).
*10b(9) PEF 3-Year $200,000,000 Credit Agreement, dated as of X
April 1, 2003, (filed as Exhibit 10(iii) to the Florida
Power Corporation Form 10-Q for the quarter ended March
31, 2003).
10b(10) Amendment, dated as of March 11, 2005, to the $1,130,000,000 X
5-Year Revolving Credit Agreement among Progress Energy, Inc.,
and certain lenders, dated August 5, 2004.
- -+*10c(1) Retirement Plan for Outside Directors (filed as X
Exhibit 10(i), File No. 33-25560).
- -+*10c(2) Resolutions of the Board of Directors dated May 8, 1991, X X
amending the PEC Directors Deferred Compensation Plan
(filed as Exhibit 10(b), File No. 33-48607).
+*10c(3) Resolutions of Board of Directors dated July 9, 1997, X
amending the Deferred Compensation Plan for Key
Management Employees of Carolina Power & Light Company.
- -+*10c(4) Carolina Power & Light Company Restricted Stock X X
Agreement, as approved January 7, 1998, pursuant to the
Company's 1997 Equity Incentive Plan (filed as Exhibit
No. 10 to Quarterly Report on Form 10-Q for the quarterly
period ended March 31, 1998, File No. 1-3382.)
217
+*10c(5) 1997 Equity Incentive Plan, Amended and Restated as of X X
September 26, 2001, (filed as Exhibit 4.3 to Progress
Energy Form S-8 dated September 27, 2001, File No.
1-3382).
- -+*10c(6) Performance Share Sub-Plan of the 1997 Equity Incentive X X
Plan, as amended January 1, 2001, (filed as Exhibit
10c(11) to Annual Report on Form 10-K dated March 28,
2002, File No. 1-3382 and 1-15929).
+*10c(7) Progress Energy, Inc. Form of Stock Option Agreement X X
(filed as Exhibit 4.4 to Form S-8 dated September 27,
2001, File No. 333-70332).
+*10c(8) Progress Energy, Inc. Form of Stock Option Award (filed X X
as Exhibit 4.5 to Form S-8 dated September 27, 2001, File
No. 333-70332).
+*10c(9) 2002 Progress Energy, Inc. Equity Incentive Plan, amended X X
and restated July 10, 2002, (filed as Exhibit 10(vi) to
Quarterly Report on Form 10-Q for the quarterly period
ended September 30, 2002, File No. 1-3382 and 1-15929).
+*10c(10) Amended Management Incentive Compensation Plan of X X
Progress Energy, Inc., effective January 1, 2005, (filed
as Exhibit 10(i) to current report on Form 8-K dated
December 13, 2004, File Nos. 1-3382, 1-3274, 1-15929 and
1-8349).
+10c(11) Progress Energy Inc., Amended and Restated Management X X
Deferred Compensation Plan, Adopted as of January 1,
2000, as Revised and Restated, effective January 1, 2005.
+10c(12) Progress Energy, Inc. Management Change-in-Control Plan, X X
Amended and Restated Effective as of January 1, 2005.
+10c(13) Amended Performance Share Sub-Plan of the 2002 Progress X X
Energy, Inc. Equity Incentive Plan effective as of
January 1, 2005.
+*10c(14) Form of Deferred Compensation Plan for Directors--Method X X
of Payment Agreement of Progress Energy, Inc., effective
as of January 1, 2005 (filed as Exhibit 10(ii) to Current
Report on Form 8-K dated December 13, 2004, File Nos.
1-3382, 1-3274, 1-15929 and 1-8349).
+10c(15) Amended and Restated Progress Energy, Inc. Restoration X X
Retirement Plan, effective as of January 1, 2005.
+10c(16) Amended and Restated Supplemental Senior Executive X X
Retirement Plan of Progress Energy, Inc., amended,
effective January 1, 2005.
218
+*10c(17) Amended Non-Employee Director Stock Unit Plan of Progress X X
Energy, Inc., effective January 1, 2005 (filed as Exhibit
10(iii) to Current Report on Form 8-K dated December 13,
2004, File Nos. 1-3382, 1-3274, 1-15929 and 1-8349).
+10c(18) Form of Progress Energy, Inc. Restricted Stock Agreement
pursuant to the 2002 Progress Energy Inc. Equity
Incentive Plan, as amended July 2002.
+*10c(19) Agreement dated April 27, 1999, between Carolina Power & X
Light Company and Sherwood H. Smith, Jr. (filed as
Exhibit 10b, File No. 1-3382).
+*10c(20) Employment Agreement dated August 1, 2000, between CP&L X
Service Company LLC and William Cavanaugh III (filed as
Exhibit 10(i) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(21) Employment Agreement dated August 1, 2000, between CP&L X
Service Company LLC and Robert McGehee (filed as Exhibit
10(iv) to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000, File No. 1-15929 and No.
1-3382).
+*10c(22) Employment Agreement dated August 1, 2000, between X
Carolina Power & Light Company and William S. "Skip"
Orser (filed as Exhibit 10(ii) to Quarterly Report on
Form 10-Q for the quarterly period ended September 30,
2000, File No. 1-15929 and No. 1-3382).
+*10c(23) Form of Employment Agreement dated August 1, 2000, (i) X X
between Carolina Power & Light Company and Don K. Davis;
and (ii) between CP&L Service Company LLC and Peter M.
Scott III (filed as Exhibit 10(v) to Quarterly Report on
Form 10-Q for the quarterly period ended September 30,
2000, File No. 1-15929 and No. 1-3382).
+*10c(24) Form of Employment Agreement dated August 1, 2000, X X
between Carolina Power & Light Company and Fred Day IV,
C.S. "Scotty" Hinnant and E. Michael Williams (filed as
Exhibit 10(vi) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
+*10c(25) Employment Agreement dated November 30, 2000, between X
Carolina Power & Light Company, Florida Power Corporation
and H. William Habermeyer, Jr. (filed as Exhibit
10.(b)(32) to Florida Progress Corporation and Florida
Power Corporation Annual Report on Form 10-K for the year
ended December 31, 2000).
+*10c(26) Form of Employment Agreement between (i) Progress Energy X X
Service Company and John R. McArthur, effective January
2003; (ii) Progress Energy Florida, Inc. and Jeffrey J.
Lyash, dated December 15, 2003; and (iii) Progress Energy
Carolinas, Inc. and Lloyd M. Yates, effective January
2005 (filed as Exhibit 10c(27) to Annual Report on Form
10-K for the year ended December 31, 2002, File No.
1-3382 and 1-5929).
219
+*10c(27) Employment Agreement dated October 1, 2003, between X X
Progress Energy Service Company LLC and Geoffrey S.
Chatas (filed as Exhibit 10c(28) to the Progress Energy,
Inc. Annual Report on Form 10-K for the year-ended
December 31, 2003).
+10c(28) Agreement dated March 31, 2004, between Progress Energy, X X
Inc. and William Cavanaugh III.
+10c(29) Employment Agreement dated January 1, 2005, between X X
Progress Energy Carolinas, Inc. and William D. Johnson.
+*10c(30) Employment Agreement dated August 1, 2000, between X X
Carolina Power & Light Company and Tom Kilgore (filed as
Exhibit 10(iii) to Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 2000, File No.
1-15929 and No. 1-3382).
10d(1) Agreement dated November 18, 2004, between Winchester X
Production Company, Ltd., TGG Pipeline Ltd., Progress
Energy, Inc. and EnCana Oil & Gas (USA), Inc.
*10d(2) Precedent and Related Agreements among Florida Power X
Corporation d/b/a Progress Energy Florida, Inc. ("PEF"),
Southern Natural Gas Company ("SNG"), Florida Gas
Transmission Company ("FGT"), and BG LNG Services, LLC
("BG"), including:
a) Precedent Agreement by and between SNG and PEF,
dated December 2, 2004;
b) Gas Sale and Purchase Contract between BG and
PEF, dated December 1, 2004;
c) Interim Firm Transportation Service Agreement by
and between FGT and PEF, dated December 2, 2004;
d) Letter Agreement between FGT and PEF, dated
December 2, 2004, and Firm Transportation
Service Agreement by and between FGT and PEF to
be entered into upon satisfaction of certain
conditions precedent;
e) Discount Agreement between FGT and PEF, dated
December 2, 2004;
f) Amendment to Gas Sale and Purchase Contract
between BG and PEF, dated January 28, 2005; and
g) Letter Agreement between FGT and PEF, dated
January 31, 2005,
(filed as Exhibit 10.1 to Current Report on Form 8-K/A
filed March 15, 2005). (Confidential treatment has been
requested for portions of this exhibit. These portions
have been omitted from the above-referenced Current
Report and submitted separately to the SEC.)
220
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.
221
PROGRESS ENERGY, INC.
EXHIBIT NO. 12
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
- --------------------------------------------------------------------------------------------------------------------------
(millions of dollars)
Years Ended December 31 2004 2003 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------
Earnings, as defined:
Income from continuing operations before cumulative
effect of changes in accounting principles $ 753 $ 811 $ 552 $ 541 $ 478
Fixed charges, as below 689 682 711 719 275
Amortization of capitalized interest 1 1 - - -
Preferred dividend requirements (7) (7) (7) (8) (8)
Minority interest 17 (3) - - -
Capitalized interest (7) (20) (38) - -
Income taxes, as below 110 (119) (166) (162) 188
- --------------------------------------------------------------------------------------------------------------------------
Total earnings, as defined $ 1,556 $ 1,345 $ 1,052 $ 1,090 $ 933
- --------------------------------------------------------------------------------------------------------------------------
Fixed Charges, as defined:
Interest on long-term debt $ 598 $ 613 $ 600 $ 578 $ 224
Other interest 62 42 79 112 37
Imputed interest factor in rentals - charged
principally to operating expenses 22 20 25 21 9
Preferred dividend requirements of subsidiaries 7 7 7 8 8
- --------------------------------------------------------------------------------------------------------------------------
Total fixed charges, as defined $ 689 $ 682 $ 711 $ 719 $ 278
- --------------------------------------------------------------------------------------------------------------------------
Income Taxes:
Income tax expense (benefit) $ 115 $ (111) $ (158) $ (154) 196
Included in AFUDC - deferred taxes in
book depreciation (5) (8) (8) (8) (8)
- --------------------------------------------------------------------------------------------------------------------------
Total income taxes $ 110 $ (119) $ (166) $ (162) $ 188
- --------------------------------------------------------------------------------------------------------------------------
Ratio of Earnings to Fixed Charges 2.26 1.97 1.48 1.52 3.36
- --------------------------------------------------------------------------------------------------------------------------
222
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
- ------------------------------------------------------------------------------------------------------------------------
(million of dollars)
Years Ended December 31 2004 2003 2002 2001 2000
- ------------------------------------------------------------------------------------------------------------------------
Earnings, as defined:
Income before cumulative effect of change in
accounting principles $ 461 $ 505 $ 431 $ 364 $ 461
Fixed charges, as below 202 205 224 264 246
Income taxes, as below 234 233 199 215 282
- ------------------------------------------------------------------------------------------------------------------------
Total earnings, as defined $ 897 $ 943 $ 854 $ 843 $ 989
- ------------------------------------------------------------------------------------------------------------------------
Fixed Charges, as defined:
Interest on long-term debt $ 183 $ 187 $ 205 $ 246 $ 224
Other interest 12 11 12 11 17
Imputed interest factor in rentals - charged
principally to operating expenses 7 7 7 7 5
- ------------------------------------------------------------------------------------------------------------------------
Total fixed charges, as defined $ 202 $ 205 $ 224 $ 264 $ 246
- ------------------------------------------------------------------------------------------------------------------------
Preferred dividends, as defined $ 5 $ 4 $ 4 $ 5 $ 5
- ------------------------------------------------------------------------------------------------------------------------
Total fixed charges and preferred dividends combined $ 207 $ 209 $ 228 $ 269 $ 251
- ------------------------------------------------------------------------------------------------------------------------
Income Taxes:
Income tax expense $ 239 $ 241 $ 207 $ 223 $ 290
Included in AFUDC - deferred taxes in
book depreciation (5) (8) (8) (8) (8)
- ------------------------------------------------------------------------------------------------------------------------
Total income taxes $ 234 $ 233 $ 199 $ 215 $ 282
- ------------------------------------------------------------------------------------------------------------------------
Ratio of Earnings to Fixed Charges 4.44 4.60 3.81 3.19 4.02
Ratio of Earnings to Fixed Charges and Preferred
Dividends Combined 4.33 4.51 3.75 3.13 3.94
- ------------------------------------------------------------------------------------------------------------------------
223
Exhibit 21
SUBSIDIARIES OF PROGRESS ENERGY, INC.
AT DECEMBER 31, 2004
The following is a list of certain direct and indirect subsidiaries of Progress
Energy, Inc., and their respective states of incorporation:
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
224
Exhibit 23.(a)
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No.
333-114237 on Form S-3, Registration Statement No. 104952 on Form S-8,
Registration Statement No. 33-33520 on Form S-8, Registration Statement No.
333-81278 on Form S-3, Registration Statement No. 333-81278-01 on Form S-3,
Registration Statement No. 333-81278-02 on Form S-3, Registration Statement No.
333-81278-03 on Form S-3, Post-Effective Amendment 1 to Registration Statement
No. 333-69738 on Form S-3, Registration Statement No. 333-70332 on Form S-8,
Registration Statement No. 333-87274 on Form S-3, Post-Effective Amendment 1 to
Registration Statement No. 333-47910 on Form S-3, Registration Statement No.
333-52328 on Form S-8, Post-Effective Amendment 1 to Registration Statement No.
333-89685 on Form S-8, and Registration Statement No. 333-48164 on Form S-8 of
our reports dated March 7, 2005, relating to the financial statements and
financial statement schedule of Progress Energy, Inc. (which report on the
consolidated financial statements expresses an unqualified opinion and includes
an explanatory paragraph concerning the adoption of new accounting principles in
2003) and management's report on the effectiveness of internal control over
financial reporting, appearing in this Annual Report on Form 10-K of Progress
Energy, Inc. for the year ended December 31, 2004.
We also consent to the incorporation by reference in Post-Effective Amendment
No. 1 to Registration Statement No. 333-58800 on Form S-3 and Registration
Statement No. 333-103973 on Form S-3 of our reports dated March 7, 2005,
relating to the financial statements and financial statement schedule of
Carolina Power & Light Company d/b/a Progress Energy Carolinas, Inc. (PEC)
(which report on the consolidated financial statements expresses an unqualified
opinion and includes an explanatory paragraph concerning the adoption of new
accounting principles in 2003), appearing in this Annual Report on Form 10-K of
PEC for the year ended December 31, 2004.
/s/ Deloitte & Touche LLP
Raleigh, North Carolina
March 15, 2005
225